Table of Contents

 

 

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 JUNE 30, 2010

Or

 

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

 

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

605 Richard Arrington Jr. Boulevard North

Birmingham, Alabama 35203-2707

Telephone Number 205/326-2700

http://www.energen.com

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

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

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

 

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

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

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

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

 

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

Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of July 28, 2010.

 

Energen Corporation		$0.01 par value		71,877,596 shares
Alabama Gas Corporation		$0.01 par value		1,972,052 shares

 

 

 

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ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2010

TABLE OF CONTENTS

 

				Page
		PART I: FINANCIAL INFORMATION
Item 1.		Financial Statements (Unaudited)
		(a) Consolidated Condensed Statements of Income of Energen Corporation		3
		(b) Consolidated Condensed Balance Sheets of Energen Corporation		4
		(c) Consolidated Condensed Statements of Cash Flows of Energen Corporation		6
		(d) Condensed Statements of Income of Alabama Gas Corporation		7
		(e) Condensed Balance Sheets of Alabama Gas Corporation		8
		(f) Condensed Statements of Cash Flows of Alabama Gas Corporation		10
		(g) Notes to Unaudited Condensed Financial Statements		11
Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		25
		Selected Business Segment Data of Energen Corporation		34
Item 3.		Quantitative and Qualitative Disclosures about Market Risk		36
Item 4.		Controls and Procedures		37
		PART II: OTHER INFORMATION
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds		38
Item 6.		Exhibits		38
SIGNATURES				39

 

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

ENERGEN CORPORATION

(Unaudited)

 

		Three months ended June 30,								Six months ended June 30,
(in thousands, except per share data)		2010				2009				2010				2009
Operating Revenues
Oil and gas operations		$	234,586			$	198,537			$	472,200			$	387,657
Natural gas distribution			99,139				107,683				436,439				402,669
Total operating revenues			333,725				306,220				908,639				790,326
Operating Expenses
Cost of gas			43,234				50,837				240,390				202,906
Operations and maintenance			109,945				88,500				201,647				176,887
Depreciation, depletion and amortization			62,476				56,407				124,211				110,985
Taxes, other than income taxes			18,256				15,168				48,893				41,628
Accretion expense			1,521				1,163				3,007				2,299
Total operating expenses			235,432				212,075				618,148				534,705
Operating Income			98,293				94,145				290,491				255,621
Other Income (Expense)
Interest expense			(9,844	)			(9,788	)			(19,804	)			(19,569	)
Other income			385				2,817				723				1,522
Other expense			(1,346	)			(170	)			(870	)			(360	)
Total other expense			(10,805	)			(7,141	)			(19,951	)			(18,407	)
Income Before Income Taxes			87,488				87,004				270,540				237,214
Income tax expense			31,945				32,003				98,287				86,631
Net Income		$	55,543			$	55,001			$	172,253			$	150,583
Diluted Earnings Per Average Common Share		$	0.77			$	0.76			$	2.39			$	2.09
Basic Earnings Per Average Common Share		$	0.77			$	0.77			$	2.40			$	2.10
Dividends Per Common Share		$	0.13			$	0.125			$	0.26			$	0.25
Diluted Average Common Shares Outstanding			72,089				71,904				72,069				71,888
Basic Average Common Shares Outstanding			71,844				71,644				71,830				71,642

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

 

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CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

 

(in thousands)		June 30, 2010			December 31, 2009
ASSETS
Current Assets
Cash and cash equivalents		$	126,647		$	75,844
Short-term investments			154,882			-
Accounts receivable, net of allowance for doubtful accounts of $15,546 at June 30, 2010, and $17,251 at December 31, 2009			260,002			327,163
Inventories
Storage gas inventory			31,248			42,475
Materials and supplies			23,018			17,440
Liquified natural gas in storage			3,355			3,409
Regulatory asset			30,857			33,196
Income tax receivable			17,614			4,552
Prepayments and other			9,110			11,527
Total current assets			656,733			515,606
Property, Plant and Equipment
Oil and gas properties, successful efforts method			3,478,515			3,379,128
Less accumulated depreciation, depletion and amortization			1,062,025			972,676
Oil and gas properties, net			2,416,490			2,406,452
Utility plant			1,247,118			1,211,624
Less accumulated depreciation			507,939			489,924
Utility plant, net			739,179			721,700
Other property, net			18,014			16,317
Total property, plant and equipment, net			3,173,683			3,144,469
Other Assets
Regulatory asset			110,856			102,133
Long-term derivative instruments			24,831			7,824
Pension assets			18,261			-
Deferred charges and other			32,664			33,086
Total other assets			186,612			143,043
TOTAL ASSETS		$	4,017,028		$	3,803,118

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

 

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CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

 

(in thousands, except share and per share data)		June 30, 2010				December 31, 2009
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Long-term debt due within one year		$	150,000			$	150,000
Accounts payable			146,660				164,327
Accrued taxes			54,437				49,884
Customers’ deposits			19,995				20,836
Amounts due customers			184				24,106
Accrued wages and benefits			19,383				27,347
Regulatory liability			102,701				29,719
Royalty payable			20,247				19,034
Deferred income taxes			13,323				10,015
Other			28,803				25,493
Total current liabilities			555,733				520,761
Long-term debt			410,368				410,786
Deferred Credits and Other Liabilities
Asset retirement obligation			92,461				88,298
Pension and other postretirement liabilities			39,305				55,899
Regulatory liability			115,046				155,088
Long-term derivative instruments			34,433				60,446
Deferred income taxes			555,984				505,460
Other			29,073				18,137
Total deferred credits and other liabilities			866,302				883,328
Commitments and Contingencies
Shareholders’ Equity
Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized			-				-
Common shareholders’ equity
Common stock, $0.01 par value; 150,000,000 shares authorized, 74,772,633 shares issued at June 30, 2010, and 74,593,431 shares issued at December 31, 2009			748				746
Premium on capital stock			466,708				461,661
Capital surplus			2,802				2,802
Retained earnings			1,780,319				1,626,753
Accumulated other comprehensive income (loss), net of tax
Unrealized gain on hedges, net			88,724				49,405
Pension and postretirement plans			(30,532	)			(31,790	)
Deferred compensation plan			3,938				3,121
Treasury stock, at cost; 3,051,940 shares at June 30, 2010, and 2,991,373 shares at December 31, 2009			(128,082	)			(124,455	)
Total shareholders’ equity			2,184,625				1,988,243
TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY		$	4,017,028			$	3,803,118

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

 

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CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

ENERGEN CORPORATION

(Unaudited)

 

Six months ended June 30, (in thousands)		2010				2009
Operating Activities
Net income		$	172,253			$	150,583
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			124,211				110,985
Accretion expense			3,007				2,299
Deferred income taxes			37,499				45,759
Bad debt expense			(237	)			4,080
Exploratory expense			19,416				163
Change in derivative fair value			(1,746	)			(118	)
Gain on sale of assets			(491	)			(472	)
Other, net			15,241				9,766
Net change in:
Accounts receivable			97,040				91,450
Inventories			5,703				18,376
Accounts payable			(50,581	)			(68,422	)
Amounts due customers			29,311				(10,599	)
Income tax receivable			(13,062	)			42,731
Pension and other postretirement benefit contributions			(39,737	)			(6,309	)
Other current assets and liabilities			2,686				6,530
Net cash provided by operating activities			400,513				396,802
Investing Activities
Additions to property, plant and equipment			(171,185	)			(200,264	)
Acquisitions, net of cash acquired			(5,580	)			(185,680	)
Proceeds from sale of assets			549				939
Purchase of short-term investments			(154,880	)			-
Other, net			(702	)			(1,675	)
Net cash used in investing activities			(331,798	)			(386,680	)
Financing Activities
Payment of dividends on common stock			(18,687	)			(17,606	)
Issuance of common stock			586				184
Payment of long-term debt			(519	)			(548	)
Net change in short-term debt			-				33,000
Tax benefit on stock compensation			708				73
Net cash (used in) provided by financing activities			(17,912	)			15,103
Net change in cash and cash equivalents			50,803				25,225
Cash and cash equivalents at beginning of period			75,844				13,177
Cash and Cash Equivalents at End of Period		$	126,647			$	38,402

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

 

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CONDENSED STATEMENTS OF INCOME

ALABAMA GAS CORPORATION

(Unaudited)

 

		Three months ended June 30,								Six months ended June 30,
(in thousands)		2010				2009				2010				2009
Operating Revenues		$	99,139			$	107,683			$	436,439			$	402,669
Operating Expenses
Cost of gas			43,234				50,837				240,390				202,906
Operations and maintenance			33,501				33,236				64,904				64,292
Depreciation and amortization			11,890				12,654				24,929				25,269
Income taxes
Current			(4,201	)			(5,867	)			20,454				20,723
Deferred			3,977				6,060				7,270				8,828
Taxes, other than income taxes			7,376				7,714				27,823				26,121
Total operating expenses			95,777				104,634				385,770				348,139
Operating Income			3,362				3,049				50,669				54,530
Other Income (Expense)
Allowance for funds used during construction			148				340				270				550
Other income			241				1,072				452				554
Other expense			(595	)			(154	)			(495	)			(343	)
Total other income (expense)			(206	)			1,258				227				761
Interest Charges
Interest on long-term debt			2,964				2,979				5,932				5,961
Other interest expense			532				426				1,058				952
Total interest charges			3,496				3,405				6,990				6,913
Net Income (Loss)		$	(340	)		$	902			$	43,906			$	48,378

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

 

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CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

 

(in thousands)		June 30, 2010				December 31, 2009
ASSETS
Property, Plant and Equipment
Utility plant		$	1,247,118			$	1,211,624
Less accumulated depreciation			507,939				489,924
Utility plant, net			739,179				721,700
Other property, net			44				146
Current Assets
Cash and cash equivalents			67,508				9,460
Accounts receivable
Gas			65,695				137,891
Other			9,874				8,617
Affiliated companies			790				-
Allowance for doubtful accounts			(14,700	)			(16,400	)
Inventories
Storage gas inventory			31,248				42,475
Materials and supplies			4,187				4,374
Liquified natural gas in storage			3,355				3,409
Deferred income taxes			25,633				25,896
Income tax receivable			1,956				3,469
Regulatory asset			30,857				33,196
Prepayments and other			1,513				3,303
Total current assets			227,916				255,690
Other Assets
Regulatory asset			110,856				102,133
Pension assets			11,445				-
Deferred charges and other			5,232				4,997
Total other assets			127,533				107,130
TOTAL ASSETS		$	1,094,672			$	1,084,666

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

 

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CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

 

(in thousands, except share data)		June 30, 2010			December 31, 2009
LIABILITIES AND CAPITALIZATION
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized		$	-		$	-
Common shareholder’s equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at June 30, 2010 and December 31, 2009			20			20
Premium on capital stock			31,682			31,682
Capital surplus			2,802			2,802
Retained earnings			308,521			283,299
Total common shareholder’s equity			343,025			317,803
Long-term debt			206,003			206,522
Total capitalization			549,028			524,325
Current Liabilities
Accounts payable			65,421			78,154
Affiliated companies			-			24,962
Accrued taxes			43,105			35,314
Customers’ deposits			19,995			20,836
Amounts due customers			184			24,106
Accrued wages and benefits			9,470			11,472
Regulatory liability			102,701			29,719
Other			12,832			9,830
Total current liabilities			253,708			234,393
Deferred Credits and Other Liabilities
Deferred income taxes			119,060			121,826
Pension and other postretirement liabilities			8,997			19,054
Regulatory liability			115,046			155,088
Long-term derivative instruments			29,046			18,965
Other			19,787			11,015
Total deferred credits and other liabilities			291,936			325,948
Commitments and Contingencies
TOTAL LIABILITIES AND CAPITALIZATION		$	1,094,672		$	1,084,666

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

 

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CONDENSED STATEMENTS OF CASH FLOWS

ALABAMA GAS CORPORATION

(Unaudited)

 

Six months ended June 30, (in thousands)		2010				2009
Operating Activities
Net income		$	43,906			$	48,378
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			24,929				25,269
Deferred income taxes			7,270				8,828
Bad debt expense			(225	)			4,006
Other, net			3,516				3,443
Net change in:
Accounts receivable			50,953				68,625
Inventories			11,468				22,185
Accounts payable			(18,070	)			(49,646	)
Amounts due customers			29,311				(10,599	)
Income tax receivable			1,513				28,830
Pension and other postretirement benefit contributions			(24,286	)			(2,025	)
Other current assets and liabilities			9,743				11,291
Net cash provided by operating activities			140,028				158,585
Investing Activities
Additions to property, plant and equipment			(36,586	)			(33,013	)
Other, net			(1,229	)			(1,444	)
Net cash used in investing activities			(37,815	)			(34,457	)
Financing Activities
Dividends			(18,684	)			(17,926	)
Payment of long-term debt			(519	)			(548	)
Net decreases in advances from affiliates			(24,962	)			(21,794	)
Net change in short-term debt			-				(62,000	)
Net cash used in financing activities			(44,165	)			(102,268	)
Net change in cash and cash equivalents			58,048				21,860
Cash and cash equivalents at beginning of period			9,460				9,728
Cash and Cash Equivalents at End of Period		$	67,508			$	31,588

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

 

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NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

 

1. BASIS OF PRESENTATION

The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2009, 2008 and 2007 included in the 2009 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The Company’s natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year.

All adjustments to the unaudited financial statements that are, in the opinion of management, necessary for a fair statement of the results for the interim periods have been recorded. Such adjustments consisted of normal recurring items. Certain reclassifications were made to conform prior years’ financial statements to the current-quarter presentation.

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

2. SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents: All highly liquid financial instruments with an original maturity of three months or less at the time of purchase are considered to be cash or cash equivalents. The Company maintains sweep accounts with financial institutions in which the account balances are invested overnight in repurchase agreements collateralized at 102 percent by the United States (U.S.) Government Securities. As of June 30, 2010 Energen had $73.8 million and Alagasco had $20 million of repurchase agreements included in cash and cash equivalents. The Company has deposits with certain financial institutions which exceed federally insured limits. The Company has reviewed the credit risk associated with these deposits and believes there is minimal risk of a material loss.

Short-Term Investments: All highly liquid financial instruments with maturities greater than three months and less than one year at the date of purchase are considered to be short term investments. As of June 30, 2010, Energen had $154.9 million of U.S. Treasury bills classified as short term investments which mature on December 9, 2010. Short-term investments are classified as Level 2 fair value.

Utility Plant and Depreciation: On June 28, 2010, the Alabama Public Service Commission (APSC) approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximately 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million in July, 2010 and will return to eligible customers an additional approximately $115.5 million, which includes approximately $19.7 million over the next twelve months, on a declining basis through lower tariff rates over a nine year period beginning October 1, 2010. The total amount refundable to customers is subject to adjournments over the nine year period for charges made to the Enhanced Stability Reserve (ESR) and other commission-approved charges. The refund in July, 2010 and the remaining amount refundable over the nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the past five years. Approved depreciation rates average approximately 4.2 percent and 4.4 percent in the six months ended June 30, 2010 and 2009, respectively.

 

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3. REGULATORY MATTERS

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

Alagasco’s allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order. Under RSE, the APSC conducts quarterly reviews to determine, based on Alagasco’s projections and year-to-date performance, whether Alagasco’s return on average equity at the end of the rate year will be within the allowed range of return. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. During the three months and six months ended June 30, 2010, Alagasco had a $1.8 million pre-tax and $10.6 million pre-tax, respectively, reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. As of September 30, 2009, Alagasco had a $1.5 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. A $10.2 million and $24.7 million annual increase in revenues became effective December 1, 2009 and 2008, respectively.

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

Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply. Alagasco’s tariff provides a temperature adjustment mechanism, also included in the GSA, that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Other non-temperature weather related conditions that may affect customer usage are not included in the temperature adjustment.

In 1998, the APSC approved an Enhanced Stability Reserve, with a maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses resulting from force majeure events when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; and (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco’s return on average equity to fall below 13.15 percent. Prior to the APSC’s June 28, 2010 order, following a year in which a charge against the ESR was made, the APSC provided for accretions to the ESR of no more than $40,000 monthly until the maximum funding level was achieved. Under the terms of the current RSE extension, Alagasco will not have accretions against the ESR until December 31, 2010 unless the Company incurs a significant natural disaster during the three year period ended December 31, 2010 and receives approval from the APSC to resume accretions under the ESR. In the APSC’s June 28, 2010 order approving Alagasco’s lower depreciation rates, the APSC approved standing authority for Alagasco to charge items to the ESR in excess of its funded balance and to allocate each year from the future removal costs that are being refunded to customers over the nine year period the amount necessary to clear the regulatory asset in the ESR each September 30, subject to APSC-approved guidelines. The APSC also approved the amortization of the ESR into rates over a five year period in cases where the ESR is unfunded or underfunded, subject to APSC-approved guidelines. As a result of these changes in the funding mechanism for the ESR, the Commission suspended the $40,000 per month accruals to the ESR during the nine year period when future removal costs are being refunded to customers.

In addition to the items mentioned above, Alagasco expects to recover certain manufactured gas plant site remediation costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory account of $2.7 million as of June 30, 2010, as more fully described in Note 10, Commitments and Contingencies.

4. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen’s oil and gas subsidiary, recognizes all derivatives on the balance sheet and measures all derivatives at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the

 

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

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Energen Resources was in a net gain position with all nine of its active counterparties at June 30, 2010. The following counterparties, Morgan Stanley Capital Group, Inc., J Aron & Company, Merrill Lynch Commodities, Inc., Bank of Montreal and Citibank, N.A., represented approximately 27 percent, 15 percent, 13 percent, 12 percent and 10 percent, respectively, of Energen Resources’ net gain on fair value of derivatives. As of June 30, 2010, Energen Resources had a $12.3 million receivable from BP Corporation North America, Inc. (BP) of which $8.3 million was classified as current. The Company considered the credit quality of BP in determining hedge effectiveness and believes that the hedges remain effective.

The current policy of the Company is to not enter into agreements that require the posting of collateral. The Company has a few older agreements, none of which have active positions as of June 30, 2010, which include collateral posting requirements based on the amount of exposure and counterparty credit ratings. The majority of the Company’s counterparty agreements include provisions for net settlement of transactions payable on the same date and in the same currency. Most, but not all, of the agreements include various contractual set-off rights which may be exercised by the non-defaulting party in the event of an early termination due to a default.

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

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

 

(in thousands)		June 30, 2010
		Oil and Gas Operations				Natural Gas Distribution				Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable		$	145,298			$	-			$	145,298
Long-term asset derivative instruments			37,834				-				37,834
Total derivative assets			183,132				-				183,132
Accounts receivable			(15,515	)*			-				(15,515	)
Long-term asset derivative instruments			(12,944	)*			-				(12,944	)
Long-term liability derivative instruments			(5,387	)			-				(5,387	)
Total derivative liabilities			(33,846	)			-				(33,846	)
Total derivatives designated			149,286				-				149,286
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable			(52	)*			19				(33	)
Long-term asset derivative instruments			(58	)*			-				(58	)
Total derivative assets			(110	)			19				(91	)
Accounts payable			-				(30,471	)			(30,471	)
Long-term liability derivative instruments			-				(29,046	)			(29,046	)
Total derivative liabilities			-				(59,517	)			(59,517	)
Total derivatives not designated			(110	)			(59,498	)			(59,608	)
Total derivatives		$	149,176			$	(59,498	)		$	89,678

 

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(in thousands)		December 31, 2009
		Oil and Gas Operations				Natural Gas Distribution				Total
Derivative assets or (liabilities) designated as hedging instruments
Accounts receivable		$	148,937			$	-			$	148,937
Long-term asset derivative instruments			16,164				-				16,164
Total derivative assets			165,101				-				165,101
Accounts receivable			(29,484	)*			-				(29,484	)
Accounts payable			(6,352	)			-				(6,352	)
Long-term asset derivative instruments			(8,340	)*			-				(8,340	)
Long-term liability derivative instruments			(41,374	)			-				(41,374	)
Total derivative liabilities			(85,550	)			-				(85,550	)
Total derivatives designated			79,551				-				79,551
Derivative assets or (liabilities) not designated as hedging instruments
Accounts receivable			(10	)*			-				(10	)
Accounts payable			-				(25,750	)			(25,750	)
Long-term liability derivative instruments			(106	)			(18,965	)			(19,071	)
Total derivative liabilities			(116	)			(44,715	)			(44,831	)
Total derivatives not designated			(116	)			(44,715	)			(44,831	)
Total derivatives		$	79,435			$	(44,715	)		$	34,720

*	Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

The Company had a net $54.4 million and a net $30.3 million deferred tax liability included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in OCI as of June 30, 2010 and December 31, 2009, respectively.

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

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

 

(in thousands)		Location of Gain (Loss) on Income Statement		Three months ended June 30, 2010			Three months ended June 30, 2009
Gain (loss) recognized in OCI on derivative (effective portion), net of tax of $26.3 million and ($29.6) million		-		$	42,917		$	(48,347	)
Gain reclassified from accumulated OCI into income (effective portion)		Operating revenues		$	56,666		$	69,902
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		Operating revenues		$	175		$	(693	)

 

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(in thousands)		Location of Gain (Loss) on Income Statement		Six months ended June 30, 2010			Six months ended June 30, 2009
Gain recognized in OCI on derivative (effective portion), net of tax of $60.3 million and $16.3 million		-		$	98,385		$	26,647
Gain reclassified from accumulated OCI into income (effective portion)		Operating revenues		$	93,390		$	139,557
Gain (loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)		Operating revenues		$	1,879		$	(492	)

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

 

(in thousands)		Location of Gain (Loss) on Income Statement		Three months ended June 30, 2010				Three months ended June 30, 2009
Gain (loss) recognized in income on derivative		Operating revenues		$	(1	)		$	436

 

(in thousands)		Location of Gain (Loss) on Income Statement		Six months ended June 30, 2010				Six months ended June 30, 2009
Gain (loss) recognized in income on derivative		Operating revenues		$	(4	)		$	441

As of June 30, 2010, $77 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified and reported in earnings as operating revenues during the next twelve-month period. The actual amount that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. As of June 30, 2010, the Company had 12 thousand barrels (MBbl) of oil hedges which expire during 2011 that did not meet the definition of a cash flow hedge but are considered by the Company to be economic hedges.

Energen Resources entered into the following transactions for the remainder of 2010 and subsequent years:

 

Production     Period		Total Hedged Volumes		Average Contract Price		Description
Natural Gas
2010		7.1 Bcf		$8.77 Mcf		NYMEX Swaps
		19.0 Bcf		$7.24 Mcf		Basin Specific Swaps
2011		13.1 Bcf		$6.66 Mcf		NYMEX Swaps
		25.7 Bcf		$6.36 Mcf		Basin Specific Swaps
Oil
2010		1,967 MBbl		$86.51 Bbl		NYMEX Swaps
2011		3,474 MBbl		$77.01 Bbl		NYMEX Swaps
2012		3,130 MBbl		$81.55 Bbl		NYMEX Swaps
2013		336 MBbl		$73.30 Bbl		NYMEX Swaps
Oil Basis Differential
2010		1,159 MBbl		*		Basis Swaps
2011		2,076 MBbl		*		Basis Swaps
2012		672 MBbl		*		Basis Swaps
Natural Gas Liquids
2010		18.7 MMGal		$0.88 Gal		Liquids Swaps
2011		38.9 MMGal		$0.89 Gal		Liquids Swaps
2012		18.1 MMGal		$0.91 Gal		Liquids Swaps
*  Average contract prices are not meaningful due to the varying nature of each contract.

 

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Alagasco entered into the following natural gas transactions for the remainder of 2010 and subsequent years:

 

Production     Period		Total Hedged Volumes				Description
2010		9.1 Bcf				NYMEX Swaps
2011		13.9 Bcf				NYMEX Swaps
2012		15.7 Bcf				NYMEX Swaps

As of June 30, 2010, the maximum term over which Energen Resources and Alagasco have hedged exposures to the variability of cash flows is through December 31, 2013 and December 31, 2012, respectively.

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

 

Level 1 –

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

Level 2 –

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

Level 3 –

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

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

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

 

		June 30, 2010
(in thousands)		Level 2*				Level 3*				Total
Current assets		$	56,225			$	73,526			$	129,751
Noncurrent assets			5,602				19,229				24,831
Current liabilities			(30,228	)			(243	)			(30,471	)
Noncurrent liabilities			(33,738	)			(695	)			(34,433	)
Net derivative asset (liability)		$	(2,139	)		$	91,817			$	89,678

 

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

*	Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of June 30, 2010, Alagasco had $19,000, $30.5 million and $29 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current assets, current liabilities and noncurrent liabilities, respectively. As of December 31, 2009, Alagasco had $25.8 million and $19 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of June 30, 2010 and December 31, 2009.

 

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

 

(in thousands)		Three months ended June 30, 2010				Three months ended June 30, 2009
Balance at beginning of period		$	114,440			$	191,059
Realized (gains) losses			(303	)			(1,383	)
Unrealized gains (losses) relating to instruments held at the reporting date			9,215				(658	)
Purchases and settlements during period			(31,535	)			(44,135	)
Balance at end of period		$	91,817			$	144,883

 

(in thousands)		Six months ended June 30, 2010				Six months ended June 30, 2009
Balance at beginning of period		$	64,517			$	154,094
Realized (gains) losses			(303	)			(1,383	)
Unrealized gains (losses) relating to instruments held at the reporting date			75,886				74,411
Purchases and settlements during period			(48,283	)			(82,239	)
Balance at end of period		$	91,817			$	144,883

5. RECONCILIATION OF EARNINGS PER SHARE (EPS)

 

(in thousands, except per share amounts)		Three months ended June 30, 2010								Three months ended June 30, 2009
		Net Income			Shares		Per Share Amount			Net Income			Shares		Per Share Amount
Basic EPS		$	55,543		71,844		$	0.77		$	55,001		71,644		$	0.77
Effect of dilutive securities
Performance share awards					-								107
Stock options					228								105
Non-vested restricted stock					17								48
Diluted EPS		$	55,543		72,089		$	0.77		$	55,001		71,904		$	0.76

 

(in thousands, except per share amounts)		Six months ended June 30, 2010								Six months ended June 30, 2009
		Net Income			Shares		Per Share Amount			Net Income			Shares		Per Share Amount
Basic EPS		$	172,253		71,830		$	2.40		$	150,583		71,642		$	2.10
Effect of dilutive securities
Performance share awards					-								104
Stock options					223								97
Non-vested restricted stock					16								45
Diluted EPS		$	172,253		72,069		$	2.39		$	150,583		71,888		$	2.09

For the three months and six months ended June 30, 2010, the Company had 472,560 options that were excluded from the computation of diluted EPS, as their effect was non-dilutive. For the three months and six months ended June 30, 2009, the Company had 426,245 and 964,737, respectively, options that were excluded from the computation of diluted EPS. For the three months and six months ended June 30, 2010 and 2009, the Company had no shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

 

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6. SEGMENT INFORMATION

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

 

		Three months ended June 30,								Six months ended June 30,
(in thousands)		2010				2009				2010				2009
Operating revenues
Oil and gas operations		$	234,586			$	198,537			$	472,200			$	387,657
Natural gas distribution			99,139				107,683				436,439				402,669
Total		$	333,725			$	306,220			$	908,639			$	790,326
Operating income (loss)
Oil and gas operations		$	95,456			$	91,449			$	212,741			$	172,595
Natural gas distribution			3,138				3,242				78,393				84,081
Eliminations and corporate expenses			(301	)			(546	)			(643	)			(1,055	)
Total		$	98,293			$	94,145			$	290,491			$	255,621
Other income (expense)
Oil and gas operations		$	(6,555	)		$	(4,896	)		$	(12,426	)		$	(12,164	)
Natural gas distribution			(3,702	)			(2,147	)			(6,763	)			(6,152	)
Eliminations and other			(548	)			(98	)			(762	)			(91	)
Total		$	(10,805	)		$	(7,141	)		$	(19,951	)		$	(18,407	)
Income before income taxes		$	87,488			$	87,004			$	270,540			$	237,214

 

(in thousands)		June 30, 2010			December 31, 2009
Identifiable assets
Oil and gas operations		$	2,704,631		$	2,654,068
Natural gas distribution			1,093,882			1,084,666
Subtotal			3,798,513			3,738,734
Eliminations and other			218,515			64,384
Total		$	4,017,028		$	3,803,118

7. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

 

		Three months ended June 30,
(in thousands)		2010				2009
Net income		$	55,543			$	55,001
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $26.3 million and ($29.6) million			42,917				(48,347	)
Reclassification adjustment for derivative instruments, net of tax of ($21.6) million and ($26.3) million			(35,241	)			(42,910	)
Pension and postretirement plans, net of tax of $0.3 million and $0.3 million			630				508
Comprehensive income (loss)		$	63,849			$	(35,748	)

 

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		Six months ended June 30,
(in thousands)		2010				2009
Net income		$	172,253			$	150,583
Other comprehensive income (loss):
Current period change in fair value of derivative instruments, net of tax of $60.3 million and $16.3 million			98,385				26,647
Reclassification adjustment for derivative instruments, net of tax of ($36.2) million and ($52.8) million			(59,066	)			(86,220	)
Pension and postretirement plans, net of tax of $0.7 million and $0.5 million			1,258				1,017
Comprehensive income		$	212,830			$	92,027

 

(in thousands)		June 30, 2010				December 31, 2009
Unrealized gain on hedges, net of tax of $54.4 million and $30.3 million		$	88,724			$	49,405
Pension and postretirement plans, net of tax of ($16.4) million and ($17.1) million			(30,532	)			(31,790	)
Accumulated other comprehensive income		$	58,192			$	17,615

8. STOCK COMPENSATION

1997 Stock Incentive Plan

The 1997 Stock Incentive Plan provides for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plan provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods. All outstanding options vest within three years from date of grant and expire 10 years from the grant date. The Company granted 281,110 non-qualified option shares during the first quarter of 2010 with a grant-date fair value of $16.47.

2004 Stock Appreciation Rights Plan

The Energen 2004 Stock Appreciation Rights Plan provides for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement and have a three year vesting period. The Company granted 171,749 awards during the first quarter of 2010. These awards had a fair value of $14.90 as of June 30, 2010.

Petrotech Incentive Plan

The Energen Resources’ Petrotech Incentive Plan provides for the grant of stock equivalent units. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. In the first quarter of 2010, Energen Resources awarded 2,161 Petrotech units with a three year vesting period. These awards had a fair value of $43.06 as of June 30, 2010.

1997 Deferred Compensation Plan

During the three months and six months ended June 30, 2010, the Company had noncash purchases of approximately $0.7 million and $2.3 million, respectively, of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation. The Company utilized internally generated cash flows in payment of the related tax withholdings.

9. EMPLOYEE BENEFIT PLANS

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

 

		Three months ended June 30,								Six months ended June 30,
(in thousands)		2010				2009				2010				2009
Components of net periodic benefit cost:
Service cost		$	2,144			$	1,835			$	4,287			$	3,670
Interest cost			2,841				3,016				5,683				6,032
Expected long-term return on assets			(3,229	)			(3,501	)			(6,458	)			(7,001	)
Actuarial loss			1,443				997				2,887				1,994
Prior service cost amortization			124				145				248				289
Termination benefit charge			-				145				-				145
Net periodic expense		$	3,323			$	2,637			$	6,647			$	5,129

 

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In March 2010 and April 2010, the Company made contributions of $2.3 million and $0.6 million, respectively, to the assets of the defined benefit qualified pension plans. In May 2010, the Company made additional required contributions of approximately $6.9 million and additional discretionary contributions of approximately $24.3 million to the defined benefit qualified pension plans. The Company made discretionary contributions of approximately $1 million in June 2010 to the defined benefit qualified pension plans. No additional discretionary contributions are currently anticipated to be made to the pension plans during 2010. For the three months and six months ending June 30, 2010, the Company made benefit payments aggregating $44,000 and $2.1 million, respectively, to retirees from the nonqualified supplemental retirement plans and expects to make additional benefit payments of approximately $100,000 through the remainder of 2010.

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

 

		Three months ended June 30,								Six months ended June 30,
(in thousands)		2010				2009				2010				2009
Components of net periodic benefit cost:
Service cost		$	516			$	453			$	1,032			$	906
Interest cost			1,208				1,212				2,417				2,425
Expected long-term return on assets			(996	)			(885	)			(1,993	)			(1,771	)
Actuarial loss			-				57				-				114
Transition amortization			479				479				958				959
Net periodic expense		$	1,207			$	1,316			$	2,414			$	2,633

For the three months and six months ended June 30, 2010, the Company made contributions aggregating $1.1 million and $2.4 million, respectively, to the postretirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $2.4 million to postretirement benefit plan assets through the remainder of 2010. During the first quarter of 2010, the Company recognized $128,000 in income tax expense resulting from a reduction in deferred tax asset related to changes in the tax treatment for the Medicare Part D subsidy under the recently enacted health care reform legislation.

10. COMMITMENTS AND CONTINGENCIES

Commitments and Agreements: Certain of Alagasco’s long-term contracts associated with the delivery and storage of natural gas include fixed charges of approximately $177 million through September 2024. During the six months ending June 30, 2010 and 2009, Alagasco recognized approximately $26.8 million and $24.6 million, respectively, of long-term commitments through expense and its regulatory accounts in the accompanying financial statements. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are approximately 91 Bcf through April 2015.

Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the balance sheets. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At June 30, 2010, the fixed price purchases under these guarantees had a maximum term outstanding through June 2011 and an aggregate purchase price of $3.5 million which approximates market value.

 

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

The Company has on-going income tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur within the next twelve months as a result of the completion of various audits and the expiration of statute of limitations. The change of the unrecognized tax benefits could have a material impact to the Company’s effective tax rate. The timing and outcome of these tax examinations is highly uncertain.

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

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

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

Environmental Matters: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company’s financial position, results of operations or cash flows. New regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs. Remediation of the Huntsville, Alabama manufactured gas plant site, as discussed below, may also result in unanticipated costs.

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

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

In June 2009, Alagasco received a General Notice Letter from the United States Environmental Protection Agency (EPA) identifying Alagasco as a responsible party for a former manufactured gas plant (MGP) site located in Huntsville, Alabama, and inviting Alagasco to enter an Administrative Settlement Agreement and Order on Consent to perform a removal action at that site. The Huntsville MGP, along with the Huntsville gas distribution system, was sold by Alagasco to the City of Huntsville in 1949 with such sale being approved by the APSC. While Alagasco no longer owns the Huntsville site, the Company and the current site owner have entered into a Consent Order and agreed to develop an action plan for the site. Based on the limited information available at this time, Alagasco preliminarily estimates that it may incur costs associated with the site ranging from $3 million to $6.1 million. At the present time, the Company cannot conclude that any amount within this range is a better estimate than any other. During the three months and six months ended

 

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June 30, 2010, the Company incurred costs of $134,000 and $185,000, respectively, associated with the site. As of June 30, 2010, the Company has accrued a contingent liability of $2.6 million in addition to the costs previously incurred. The estimate assumes an action plan for excavation of affected soil and sediment only. If it is determined that a greater scope of work is appropriate, then actual costs will likely exceed the preliminary estimate. Alagasco expects to recover such costs through future rates and has recorded a corresponding amount to its Enhanced Stability Reserve regulatory asset account.

11. FINANCIAL INSTRUMENTS

The stated value of cash and cash equivalents, short-term investments, trade receivables (net of allowance), and short-term debt approximates fair value due to the short maturity of the instruments. The fair value of Energen’s long-term debt, including the current portion, with a carrying value of $561 million approximates $595.3 million at June 30, 2010. The fair value of Alagasco’s fixed-rate long-term debt, including the current portion, with a carrying value of $206 million approximates $211.4 million at June 30, 2010. The fair values were based on market prices of similar debt issues having the same remaining maturities, redemption terms and credit rating.

12. REGULATORY ASSETS AND LIABILITIES

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

 

		June 30, 2010						December 31, 2009
(in thousands)		Current			Noncurrent			Current			Noncurrent
Regulatory assets:
Pension and postretirement assets		$	132		$	64,327		$	132		$	66,552
Accretion and depreciation for asset retirement obligation			-			14,523			-			13,566
Gas supply adjustment			-			-			7,059			-
Risk management activities			30,471			29,046			25,750			18,965
RSE adjustment			25			-			25			-
Enhanced stability reserve			-			2,706			-			2,706
Other			229			254			230			344
Total regulatory assets		$	30,857		$	110,856		$	33,196		$	102,133
Regulatory liabilities:
RSE adjustment		$	9,076		$	-		$	1,508		$	-
Unbilled service margin			9,646			-			28,178			-
Gas supply adjustment			38,604			-			-			-
Asset removal costs, net			45,322			95,939			-			136,799
Asset retirement obligation			-			18,254			-			17,419
Other			53			853			33			870
Total regulatory liabilities		$	102,701		$	115,046		$	29,719		$	155,088

13. ASSET RETIREMENT OBLIGATIONS

The Company recognizes a liability for the fair value of asset retirement obligations (ARO) in the periods incurred. Subsequent to initial measurement, liabilities are accreted to their present value and capitalized costs are depreciated over the estimated useful life of the related assets. Upon settlement of the liability, the Company may recognize a gain or loss for differences between estimated and actual settlement costs. The ARO fair value liability is recognized on a discounted basis incorporating an estimate of performance risk specific to the Company.

 

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During the six months ended June 30, 2010, Energen Resources recognized amounts representing expected future costs associated with site reclamation, facilities dismantlement, and plug and abandonment of wells as follows:

 

(in thousands)
Balance of ARO as of December 31, 2009		$	88,298
Liabilities incurred			1,480
Liabilities settled			(324	)
Accretion expense			3,007
Balance of ARO as of June 30, 2010		$	92,461

The Company recognizes conditional obligations if such obligations can be reasonably estimated and a legal requirement to perform an asset retirement activity exist. Alagasco recorded a conditional asset retirement obligation, on a discounted basis of $18.3 million and $17.4 million to purge and cap its gas pipelines upon abandonment, as a regulatory liability as of June 30, 2010 and December 31, 2009, respectively. The costs associated with asset retirement obligations are currently either being recovered in rates or are probable of recovery in future rates.

Alagasco accrues removal costs on certain gas distribution assets over the useful lives of its property, plant and equipment through depreciation expense in accordance with rates approved by the APSC. The total accumulated asset removal costs are $141.2 million and $136.8 million for June 30, 2010 and December 31, 2009, respectively. Corresponding regulatory liabilities for accumulated asset removal costs of $95.9 million and $136.8 million for June 30, 2010 and December 31, 2009, respectively, are included as regulatory liabilities in deferred credits and other liabilities on the balance sheets. As of June 30, 2010, the Company also recognized $45.3 million of accumulated asset removal costs as regulatory liabilities in current liabilities on the balance sheet in response to the June 28, 2010 APSC order as discussed in Note 2, Significant Accounting Policies.

14. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES

During the second quarter of 2010, Energen Resources wrote off unproved leasehold costs associated with the deep Conasauga shale acreage as efforts indicate that it is not economically viable given associated capital costs and the outlook for natural gas prices. The non-cash costs of approximately $16.1 million pre-tax were charged to exploration expense, which is included in O&M expense, in June 2010. During the six months ended June 30, 2010, Energen Resources capitalized approximately $4.2 million of unproved leaseholds costs, approximately $0.3 million of which was related to the Company’s acreage position in Alabama shales. Energen used its available cash and existing lines of credit to finance these unproved leasehold costs.

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

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

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

 

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

 

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Included in the Company’s consolidated results of operations for the six months ended June 30, 2010, is $24.4 million of operating revenues and $11.4 million in operating income resulting from operation of the properties acquired from Range Resources.

Summarized below are the consolidated results of operations for the three months and six months ended June 30, 2009, on an unaudited pro forma basis as if the acquisition had occurred at the beginning of the period presented. The pro forma information is based on the Company’s consolidated results of operations for the three months and six months ended June 30, 2009, and on the data provided by the seller. The pro forma financial information does not purport to be indicative of results of operations that would have occurred had the transaction occurred on the basis assumed above, nor are they indicative of results of the future operations of the combined enterprises.

 

(in thousands)		Three months ended June 30, 2009			Six months ended June 30, 2009
Operating revenues		$	316,768		$	808,901
Operating income		$	97,494		$	259,852

15. RECENTLY ISSUED ACCOUNTING STANDARDS

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

On January 1, 2010, the Company adopted Accounting Standard Update (ASU) No. 2010-06, Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures About Fair Value Measurements. These disclosures are effective for the first interim or annual reporting period beginning after December 15, 2009, except for the gross presentation of the Level 3 roll forward, which is required for annual reporting periods beginning after December 15, 2010 and for interim reporting periods within those years. This standard did not have an impact on the consolidated condensed financial statements of the Company.

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

 

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

 

RESULTS OF OPERATIONS

Energen’s net income totaled $55.5 million ($0.77 per diluted share) for the three months ended June 30, 2010 compared with net income of $55 million ($0.76 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen’s oil and gas subsidiary, had net income for the three months ended June 30, 2010, of $56.8 million as compared with $54.9 million in the same quarter in the previous year. Significantly higher commodity prices (approximately $19 million after-tax) and increased production volumes (approximately $4 million after-tax) were partially offset by increased depreciation, depletion and amortization (DD&A) expense (approximately $4 million after-tax), higher production taxes (approximately $2 million after-tax) and higher exploration expense (approximately $12 million after-tax) due to a non-cash write-off of $10 million after-tax (approximately $0.14 per diluted share) of unproved leasehold costs associated with the deep Conasauga shale acreage. Energen’s natural gas utility, Alagasco, reported a net loss of $0.3 million in the second quarter of 2010 compared to net income of $0.9 million in the same period last year. This decrease largely reflects the timing of rate recovery under Alagasco’s rate-setting mechanisms, partially offset by the utility’s ability to earn on a higher level of equity.

For the 2010 year-to-date, Energen’s net income totaled $172.3 million ($2.39 per diluted share) and compared favorably to net income of $150.6 million ($2.09 per diluted share) for the same period in the prior year. Energen Resources generated net income for the six months ended June 30, 2010, of $128.4 million as compared with $102 million in the previous period primarily as a result of higher commodity prices (approximately $47 million after-tax) and increased production volumes (approximately $7 million). Negatively affecting net income was the impact of higher DD&A expense (approximately $8 million after-tax), increased production taxes (approximately $3 million after-tax), increased administrative expense (approximately $4 million after-tax) and increased exploration expense (approximately $12 million after-tax) largely due to the $10 million after-tax Conasauga shale acreage write-off. Alagasco’s net income of $43.9 million in the current year-to-date compared to net income of $48.4 million in the same period in the previous year primarily due to the same reasons discussed above.

Oil and Gas Operations

Revenues from oil and gas operations rose 18.2 percent to $234.6 million for the three months ended June 30, 2010 and 21.8 percent to $472.2 million in the year-to-date largely as a result of increased commodity prices along with the impact of higher oil and natural gas liquids production volumes. During the current quarter, revenue per unit of production for natural gas rose 9.1 percent to $6.84 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 30.9 percent to $78.34 per barrel. Natural gas liquids revenue per unit of production fell 12.5 percent to an average price of $0.77 per gallon. In the year-to-date, revenue per unit of production for natural gas increased 9.5 percent to $7.02 per Mcf, oil revenue per unit of production rose 39.6 percent to $78.77 per barrel and natural gas liquids revenue per unit of production fell 3.5 percent to an average price of $0.82 per gallon.

Production for both the current quarter and year-to-date rose primarily due to increased volumes related to the June 2009 purchase of certain Permian Basin oil properties partially offset by normal production declines. Natural gas production in the second quarter declined 2 percent to 17.6 billion cubic feet (Bcf), oil volumes increased 13 percent to 1,258 thousand barrels (MBbl) and natural gas liquids production increased 3.3 percent to 19 million gallons (MMgal). For the year-to-date, natural gas production decreased 1.7 percent to 35 Bcf, while oil volumes rose 10.9 percent to 2,444 MBbl. Natural gas liquids production increased 5.3 percent to 37.8 MMgal. Natural gas comprised approximately 63 percent of Energen Resources’ production for the current quarter and the year-to-date.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. The Company includes gains and losses on the disposition of these assets in operating revenues. Energen Resources recorded no property sales in the second quarter of 2010 and 2009. In the first quarter of 2010, Energen Resources recorded a pre-tax gain of $0.6 million largely from the sale of certain property in the Black Warrior Basin. Energen Resources recorded a pre-tax gain of $0.3 million in the first quarter of 2009 on the sale of various properties.

 

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Operations and maintenance (O&M) expense increased $21.4 million for the quarter and $24.6 in the year-to-date. Lease operating expense (excluding production taxes) increased $1.4 million for the quarter largely due to the June 2009 acquisition of Permian Basin oil properties (approximately $3 million) and increased electrical costs ($1 million) partially offset by lower workover expense ($1.8 million) and lower ad valorem taxes (approximately $0.7 million). In the year-to-date, lease operating expense (excluding production taxes) decreased $0.7 million primarily due to decreased workover expense ($2.7 million), lower nonoperated costs ($2.3 million), lower ad valorem taxes (approximately $1.3 million) and decreased repair and maintenance expense ($1 million) partially offset by the June 2009 acquisition of oil properties (approximately $5.6 million) and additional marketing and transportation costs ($1.4 million). Administrative expense increased $1.5 million for the three months ended June 30, 2010. For the six months ended June 30, 2010, administrative expense rose $5.6 million primarily due to higher labor and benefit costs primarily related to the Company’s performance-based compensation plans (approximately $3.3 million) and increased legal expenses (approximately $1.3 million). Exploration expense rose $18.6 million in the second quarter of 2010 and $19.6 million year-to-date. In the second quarter of 2010, Energen Resources recorded a non-cash write-off of $16.1 million pre-tax of unproved leasehold associated with the deep Conasauga shale acreage.

Energen Resources’ DD&A expense for the quarter rose $6.8 million and increased $13.6 million year-to-date. The average depletion rate for the current quarter was $1.78 per thousand cubic feet equivalent (Mcfe) as compared to $1.57 per Mcfe in the same period a year ago. For the six months ended June 30, 2010, the average depletion rate was $1.77 per Mcfe as compared to $1.56 per Mcfe in the previous period. The increase in the current quarter and year-to-date per unit DD&A rate, which contributed approximately $7.5 million and $14.6 million, respectively, to the increase in DD&A expense, was largely due to higher development costs along with the reserve revisions associated with lower year-end reserve pricing. Partially offsetting the increases in DD&A, Energen Resources experienced higher production in low rate areas which was offset by lower production in high rate areas resulting in a net production volume impact of approximately $0.7 million and $1.3 million in the three months and six months ended June 30, 2010, respectively.

Energen Resources’ expense for taxes other than income taxes was $3.4 million and $5.6 million higher in the three months and six months ended June 30, 2010, respectively, largely due to production-related taxes. In the current quarter and year-to-date, higher oil, natural gas and natural gas liquid commodity market prices contributed approximately $3.2 million and $5.2 million, respectively, to the increase in production-related taxes. Also increasing production-related taxes were higher production volumes which contributed approximately $0.2 million and $0.3 million, respectively, for the quarter and year-to-date. Commodity market prices exclude the effects of derivative instruments for purposes of determining severance taxes.

Natural Gas Distribution

Natural gas distribution revenues decreased $8.5 million for the quarter largely due to a decline in gas costs along with slightly lower customer usage and adjustments from the utility’s rate-setting mechanisms. In the current quarter, Alagasco had a $1.8 million pre-tax reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. For the current quarter, weather was 19 percent colder compared to the same quarter last year. Residential sales volumes rose 6.9 percent and commercial and industrial customer sales volumes increased 2.4 percent. Transportation volumes rose 26.8 percent in period comparisons due primarily to lower usage by large commercial and industrial customers during 2009. Revenues for the year-to-date rose $33.8 million primarily due to increased customer usage partially offset by a decrease in gas costs and adjustments for rate-setting purposes. In the current year-to-date, Alagasco had reduction in revenues of $10.6 million pre-tax to bring the return on average equity to midpoint within the allowed range of return. Weather that was 39 percent colder compared with the same period in the prior year contributed to a 27.9 percent increase in residential sales volumes and an 18.8 percent rise in commercial and industrial customer sales volumes. Transportation volumes increased 20.4 percent in period comparisons for the same reasons as described above. A decrease in gas costs along with a decrease in gas purchase volumes resulted in a 15 percent decrease in cost of gas for the quarter. For the year-to-date, a significant increase in gas purchase volumes partially offset by lower gas costs contributed to a 18.5 percent increase in cost of gas. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the Gas Supply Adjustment (GSA) rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment mechanism that is designed to moderate the impact of departures from normal temperatures on Alagasco’s earnings. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.

 

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O&M expense rose 1 percent in the current quarter primarily due to higher distribution operation expenses ($0.7 million) and increased labor-related costs (approximately $0.6 million) partially offset by lower marketing expenses (approximately $1.2 million). In the six months ended June 30, 2010, O&M expense increased 1 percent primarily due to increased labor-related costs (approximately $2.4 million), increased consulting and technology costs (approximately $1.4 million) and increased distribution operation expenses (approximately $1.3 million). Partially offsetting these increases was a decrease to bad debt expense (approximately $4.2 million) which included the correction of a $3 million error identified by Alagasco, during the first quarter of 2010, in the calculation of the estimate of the allowance for doubtful accounts as of December 31, 2009. See Note 1, Basis of Presentation, in the Notes to Unaudited Condensed Financial Statements for further discussion.

A 6 percent decrease in depreciation expense in the current quarter and a 1.3 percent decrease in the year-to-date was primarily due to revised depreciation rates effective June 1, 2010, partially offset by the extension and replacement of the utility’s distribution system and replacement of its support systems. On June 28, 2010, the Alabama Public Service Commission (APSC) approved a reduction in depreciation rates for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million in July, 2010 and will return to eligible customers an additional approximately $115.5 million, which includes approximately $19.7 million over the next twelve months, on a declining basis through lower tariff rates over a nine year period beginning October 1, 2010. The total amount refundable to customers is subject to adjustments over the nine year period for charges made to the Enhanced Stability Reserve and other commission-approved charges. The refund in July, 2010 and the remaining amount refundable over the nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the past five years. Approved depreciation rates averaged approximately 4.2 percent and 4.4 percent in the six months ended June 30, 2010 and 2009, respectively.

Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company increased $0.1 million in the second quarter of 2010 and $0.2 million in the year-to-date. Income tax expense for the Company decreased $0.1 million in the current quarter. For the year-to-date, income tax expense rose $11.7 million primarily due to higher pre-tax income.

FINANCIAL POSITION AND LIQUIDITY

 

Cash flows from operations for the year-to-date were $400.5 million as compared to $396.8 million in the prior period. Net income increased during period comparisons primarily due to higher realized commodity prices along with increased production volumes at Energen Resources. The Company’s working capital needs were also influenced by accrued taxes along with commodity prices and the timing of payments. Working capital needs at Alagasco were additionally affected by decreased storage gas inventory compared to the prior period.

The Company had a net outflow of cash from investing activities of $331.8 million for the six months ended June 30, 2010 due to additions of property, plant and equipment of $176.8 million and short-term investments of $154.9 million. Energen Resources invested $140.2 million (includes approximately $11.3 million of payments associated with accrued development cost) in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $36.6 million (excludes approximately $0.6 million of accrued capital cost) year-to-date and primarily represented expansion and replacement of its distribution system and replacement of its support facilities.

The Company used $17.9 million for net financing activities in the year-to-date primarily for the payment of dividends to common shareholders.

 

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Oil and Gas Operations

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

The Company plans to continue investing significant capital in Energen Resources’ oil and gas production operations. For 2010, the Company expects its oil and gas capital spending to total approximately $360 million, including $329 million for existing properties and a total of $5.5 million for acquisitions in the Permian and San Juan basins.

The Company also may allocate additional capital for other oil and gas activities such as property acquisitions, additional development of existing properties and the exploration and further development of potential shales acreage primarily in Alabama. Energen Resources may evaluate acquisition opportunities which arise in the marketplace and from time to time will pursue acquisitions that meet Energen’s acquisition criteria. Energen Resources’ ability to invest in property acquisitions is subject to market conditions and industry trends. Property acquisitions are not included in the aforementioned estimate of oil and gas investments and could result in capital expenditures different from those outlined above. To finance capital spending at Energen Resources, the Company primarily expects to use internally generated cash flow supplemented by its short-term credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. The Company currently has no plans for the issuance of equity. Energen Resources has $150 million of long-term debt due in December 2010.

Alabama Shales

In the second quarter of 2010, Energen Resources recorded a non-cash write-off of approximately $10 million after-tax (approximately $0.14 per diluted share) of unproved leasehold costs associated with the deep Conasauga shale acreage. Efforts indicated that the acreage was not economically viable given associated capital costs and the outlook for natural gas prices.

Energen Resources continues to pursue the economic viability of the Chattanooga shale formation with anticipated results during the third quarter of 2010. During the third quarter of 2010, Energen Resources also plans to re-enter a Conasauga shale well in order to cost effectively evaluate its shallow shale potential in Alabama.

As of June 30, 2010, Energen Resources had approximately $23 million of unproved leasehold costs related to its remaining lease position in Alabama shales of which $13 million are associated with the Chattanooga shale formation with the remainder associated with the shallow Conasauga shale formation. In the event further efforts are unsuccessful and the Company concludes no further activity is warranted, Energen Resources would expect to record a loss associated with well costs and the non-cash write-off on capitalized unproved leasehold.

Natural Gas Distribution

Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) and is allowed to earn a range of return on equity of 13.15 percent to 13.65 percent. At September 30, 2009, RSE limited the utility’s equity upon which a return is permitted to 55 percent of total capitalization, subject to certain adjustments. Given existing economic conditions, Alagasco expects only modest growth in equity as annual dividends are typically paid by the utility.

On June 28, 2010, the APSC approved a reduction in depreciation rates, effective June 1, 2010, for Alagasco with the revised prospective composite depreciation rate approximating 3.1 percent. Related to the lower depreciation rates, Alagasco refunded to eligible customers approximately $25.6 million in July, 2010 and will return to eligible customers an additional approximately $115.5 million, which includes approximately $19.7 million over the next twelve months, on a declining basis through lower tariff rates over a nine year period beginning October 1, 2010. The total amount refundable to customers is subject to adjustments over the nine year period for charges made to the Enhanced Stability Reserve and other commission-approved charges. The refund in July, 2010 and the remaining amount refundable over the nine year period are due to a re-estimation of future removal costs provided for through the prior depreciation rates. The re-estimation was primarily the result of Alagasco’s actual removal cost experience, combined with technology improvements and Alagasco’s system efficiency improvements, during the past five years.

 

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Over the past several years, a higher commodity price environment and reduced economic activity have contributed to the decline in the utility’s customer base and in declines in usage volume per customer. While the commodity price environment has moderated, a return of natural gas prices to higher levels could result in a further decline in Alagasco’s customer base and usage and in increases in the utility’s GSA. Alagasco monitors the bad debt reserve and makes adjustments as required based on its evaluation of receivables which are impacted by natural gas prices and the underlying current and future economic conditions facing the utility’s customer base.

Alagasco maintains an investment in storage gas that is expected to average approximately $34 million in 2010 but will vary depending upon the price of natural gas. During 2010, Alagasco plans to invest an estimated $87 million in utility capital expenditures for normal distribution and support systems. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities.

Derivative Commodity Instruments

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its price exposure to its estimated oil, natural gas and natural gas liquids production. Such instruments may include natural gas and crude oil over-the-counter (OTC) swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment and commercial banks and energy-trading firms. The Company’s current counterparties with active positions are Morgan Stanley Capital Group, Inc., J Aron & Company, Citibank, N.A., Bank of Montreal, Merrill Lynch Commodities, Inc., BP Corporation North America, Inc. (BP), Barclays Bank PLC, Wachovia Bank National Association and Shell Energy North America (US), L.P. At June 30, 2010, the counterparty agreements under which the Company had active positions did not include collateral posting requirements. Energen Resources was in a net gain position with all nine of its counterparties at June 30, 2010. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. Hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not authorize speculative positions. Energen Resources had a $12.3 million receivable from BP as of June 30, 2010 of which $8.3 million was classified as current. The Company considered the credit quality of BP in determining hedge effectiveness and believes that the hedges remain effective.

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

Energen Resources entered into the following transactions for the remainder of 2010 and subsequent years:

Production     Period		Total Hedged Volumes		Average Contract Price		Description
Natural Gas
2010		7.1 Bcf		$8.77 Mcf		NYMEX Swaps
		19.0 Bcf		$7.24 Mcf		Basin Specific Swaps
2011		13.1 Bcf		$6.66 Mcf		NYMEX Swaps
		25.7 Bcf		$6.36 Mcf		Basin Specific Swaps
Oil
2010		1,967 MBbl		$86.51 Bbl		NYMEX Swaps
2011		3,474 MBbl		$77.01 Bbl		NYMEX Swaps
2012		3,130 MBbl		$81.55 Bbl		NYMEX Swaps
2013		336 MBbl		$73.30 Bbl		NYMEX Swaps
Oil Basis Differential
2010		1,159 MBbl		*		Basis Swaps
2011		2,076 MBbl		*		Basis Swaps
2012		672 MBbl		*		Basis Swaps
Natural Gas Liquids
2010		18.7 MMGal		$0.88 Gal		Liquids Swaps
2011		38.9 MMGal		$0.89 Gal		Liquids Swaps
2012		18.1 MMGal		$0.91 Gal		Liquids Swaps
* Average contract prices are not meaningful due to the varying nature of each contract.

 

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Alagasco entered into the following natural gas transactions for the remainder of 2010 and subsequent years:

 

Production     Period		Total Hedged Volumes				Description
2010		9.1 Bcf				NYMEX Swaps
2011		13.9 Bcf				NYMEX Swaps
2011		*0.8 Bcf				NYMEX Swaps
2012		15.7 Bcf				NYMEX Swaps
2012		*1.5 Bcf				NYMEX Swaps
2013		*1.5 Bcf				NYMEX Swaps
*  Contract entered into subsequent to June 30, 2010.

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

See Note 4, Derivative Commodity Instruments, in the Notes to Unaudited Condensed Financial Statements for information regarding the Company’s policies on fair value measurement.

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

		June 30, 2010
(in thousands)		Level 2*				Level 3*				Total
Current assets		$	56,225			$	73,526			$	129,751
Noncurrent assets			5,602				19,229				24,831
Current liabilities			(30,228	)			(243	)			(30,471	)
Noncurrent liabilities			(33,738	)			(695	)			(34,433	)
Net derivative asset		$	(2,139	)		$	91,817			$	89,678

 

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

 

*	Amounts classified in accordance with accounting guidance which permits offsetting fair value amounts recognized for multiple derivative instruments executed with the same counterparty under a master netting arrangement.

As of June 30, 2010, Alagasco had $19,000, $30.5 million and $29 million of derivative instruments which are classified as Level 2 fair values and are included in the above table as current assets, current liabilities and noncurrent liabilities, respectively. As of December 31, 2009, Alagasco has $25.8 million and $19 million of derivative instruments which are classified as Level 2 fair values and are included in the table as current and noncurrent liabilities, respectively. Alagasco had no derivative instruments classified as Level 3 fair values as of June 30, 2010 and December 31, 2009.

Level 3 assets and liabilities as of June 30, 2010 represent approximately 2 percent of total assets and an immaterial amount of total liabilities, respectively. Changes in fair value primarily result from price changes in the underlying commodity. The Company has prepared a sensitivity analysis to evaluate the hypothetical effect that changes in the prices used to estimate fair value would have on the fair value of its derivative instruments. The Company estimates that a 10 percent increase or decrease in commodity prices would result in an approximate $25.5 million change in the fair value of open Level 3 derivative contracts. The resulting impact upon the results of operations for Level 3 derivatives would be immaterial due to derivative instruments qualifying as cash flow hedges. Liquidity requirements to meet the obligation would not be significantly impacted as gains and losses on the derivative contracts would be similarly offset by sales at the spot market price.

 

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Stock Repurchases

Energen periodically considers stock repurchases as a capital investment. Energen may buy shares on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. The Company did not repurchase shares of common stock for this program during the six months ended June 30, 2010. The Company expects any future stock repurchases to be funded through internally generated cash flow or through the utilization of its short-term credit facilities. During the six months ended June 30, 2010, the Company had noncash purchases of approximately $2.8 million of Company common stock in conjunction with tax withholdings on its non-qualified deferred compensation plan and other stock compensation plans. The Company utilized internally generated cash flows in payment of the related tax withholdings.

Short-Term Credit Facilities

Energen and Alagasco rely upon excess cash flows supplemented by short-term credit facilities to fund working capital needs. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Energen and Alagasco are subject to the risk that the credit facilities will not be renewed or will be renewed at less favorable terms. However, the Company believes that its expected cash flows, the diversity of credit facilities and its ability to adjust future capital spending provides adequate support for its liquidity needs. These short-term credit facilities are 364-day committed bilateral agreements. Energen Resources is a guarantor with respect to certain Energen credit facilities. The Company currently has available short-term credit facilities as follows:

 

(in thousands)		Current Term		Energen			Alagasco			Total
Regions Bank		4/22/2011		$	165,000		$	35,000		$	200,000
Wachovia Bank, National Association		6/30/2011			100,000			100,000			100,000
Compass Bank		7/28/2011			70,000			70,000			70,000
Citicorp USA, Inc.		4/15/2011			20,000			15,000			35,000
First Commercial		7/27/2011			-			25,000			25,000
The Northern Trust Company		10/31/2011			25,000			35,000			35,000
BancorpSouth Bank		5/23/2011			-			10,000			10,000
Total				$	380,000		$	290,000		$	475,000

Dividends

Energen expects to pay annual cash dividends of $0.52 per share on the Company’s common stock in 2010. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.

Contractual Cash Obligations and Other Commitments

In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. Except as discussed below, there have been no material changes to the contractual cash obligations of the Company since December 31, 2009.

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

The Company has on-going income tax examinations under various U.S. and state tax jurisdictions. Accordingly, it is reasonably possible that significant changes to the reserve for uncertain tax benefits may occur within the next twelve months as a result of the completion of various audits and the expiration of statute of limitations. The change of the unrecognized tax benefits could have a material impact to the Company’s effective tax rate. The timing and outcome of these tax examinations is highly uncertain.

Recent Accounting Standards Updates

See Note 15, Recently Issued Accounting Standards, in the Notes to Unaudited Condensed Financial Statements for information regarding recently issued accounting standards.

 

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FORWARD LOOKING STATEMENTS AND RISK FACTORS

 

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

All statements based on future expectations rather than on historical facts are forward-looking statements that are dependent on certain events, risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, the Company’s ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.

Commodity Prices: The Company and Alagasco are significantly influenced by commodity prices. Historical markets for natural gas, oil and natural gas liquids have been volatile. Energen Resources’ revenues, operating results, profitability and cash flows depend primarily upon the prices realized for its oil, gas and natural gas liquid production. Alagasco’s competitive position and customer demand is significantly influenced by prices for natural gas which are passed-through to customers.

Access to Credit Markets: The Company and its subsidiaries rely on access to credit markets. The availability and cost of credit market access is significantly influenced by market events and rating agency evaluations for both lenders and the Company. Market volatility and credit market disruption have historically demonstrated that credit availability and issuer credit ratings can change rapidly. Events negatively affecting credit ratings and credit market liquidity could increase borrowing costs or limit availability of funds to the Company.

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

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

Energen Resources Customer Concentration: Revenues and related accounts receivable from oil and gas operations primarily are generated from the sale of produced oil, natural gas and natural gas liquids to a small number of energy marketing companies. Such sales are typically made on an unsecured credit basis with payment

 

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due the month following delivery. This concentration of sales to a limited number of customers in the energy marketing industry has the potential to affect the Company’s overall exposure to credit risk, either positively or negatively, based on changes in economic, industry or other conditions specific to a single customer or to the energy marketing industry generally. Energen Resources considers the credit quality of its customers and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil, natural gas and natural gas liquids purchasers are expected to account for approximately 21 percent, 17 percent and 13 percent, respectively, of Energen Resources’ estimated 2010 production. Energen Resources’ other purchasers are each expected to purchase less than 8 percent of estimated 2010 production.

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

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

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

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

Federal, State and Local Laws and Regulations: Energen and Alagasco are subject to extensive federal, state and local regulation which significantly influences operations. Although the Company believes that operations generally comply with applicable laws and regulations, failure to comply could result in the suspension or termination of operations and subject the Company to administrative, civil and criminal penalties. Federal, state and local legislative bodies and agencies frequently exercise their respective authority to adopt new laws and regulations and to amend, modify and interpret existing laws and regulations. Such changes can subject the Company to significant tax or cost increases and can impose significant restrictions and limitations on the Company’s operations.

 

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SELECTED BUSINESS SEGMENT DATA

ENERGEN CORPORATION

(Unaudited)

 

 

		Three months ended June 30,						Six months ended June 30,
(in thousands, except sales price data)		2010			2009			2010				2009
Oil and Gas Operations
Operating revenues
Natural gas		$	120,588		$	112,822		$	246,015			$	228,457
Oil			98,523			66,620			192,498				124,362
Natural gas liquids			14,611			16,194			31,147				30,716
Other			864			2,901			2,540				4,122
Total		$	234,586		$	198,537		$	472,200			$	387,657
Production volumes
Natural gas (MMcf)			17,633			18,001			35,045				35,651
Oil (MBbl)			1,258			1,113			2,444				2,203
Natural gas liquids (MMgal)			19.0			18.4			37.8				35.9
Total production volumes (MMcfe)			27,897			27,314			55,106				54,006
Revenue per unit of production including effects of all derivative instruments
Natural gas (Mcf)		$	6.84		$	6.27		$	7.02			$	6.41
Oil (barrel)		$	78.34		$	59.85		$	78.77			$	56.44
Natural gas liquids (gallon)		$	0.77		$	0.88		$	0.82			$	0.85
Revenue per unit of production including effects of qualifying cash flow hedges
Natural gas (Mcf)		$	6.84		$	6.27		$	7.02			$	6.41
Oil (barrel)		$	78.34		$	59.46		$	78.77			$	56.25
Natural gas liquids (gallon)		$	0.77		$	0.88		$	0.82			$	0.85
Revenue per unit of production excluding effects of all derivative instruments
Natural gas (Mcf)		$	3.95		$	2.99		$	4.59			$	3.48
Oil (barrel)		$	73.36		$	55.12		$	73.91			$	45.67
Natural gas liquids (gallon)		$	0.79		$	0.59		$	0.87			$	0.54
Other data
Lease operating expense (LOE)
LOE and other		$	44,721		$	43,371		$	88,560			$	89,243
Production taxes			10,646			7,269			20,587				15,110
Total		$	55,367		$	50,640		$	109,147			$	104,353
Depreciation, depletion and amortization		$	50,586		$	43,753		$	99,282			$	85,716
Capital expenditures		$	72,352		$	241,213		$	110,915			$	315,828
Exploration expenditures		$	18,677		$	104		$	19,861			$	254
Operating income		$	95,456		$	91,449		$	212,741			$	172,595
Natural Gas Distribution
Operating revenues
Residential		$	59,676		$	64,764		$	301,082			$	269,292
Commercial and industrial			26,190			29,918			110,480				105,294
Transportation			11,683			12,209			29,516				27,225
Other			1,590			792			(4,639	)			858
Total		$	99,139		$	107,683		$	436,439			$	402,669

 

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Gas delivery volumes (MMcf)
Residential			3,310			3,095			18,272			14,286
Commercial and industrial			1,853			1,810			7,580			6,378
Transportation			10,523			8,302			23,205			19,271
Total			15,686			13,207			49,057			39,935
Other data
Depreciation and amortization		$	11,890		$	12,654		$	24,929		$	25,269
Capital expenditures		$	21,167		$	19,864		$	37,527		$	35,974
Operating income		$	3,138		$	3,242		$	78,393		$	84,081

 

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

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

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may include natural gas and crude oil over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms and are believed to be creditworthy by the Company. The Company is at risk for economic loss based upon the creditworthiness of its counterparties. All hedge transactions are subject to the Company’s risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. As of June 30, 2010, the maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2013.

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

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

The Company’s interest rate exposure as of June 30, 2010, was minimal as all long-term debt obligations were at fixed rates.

 

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ITEM 4. CONTROLS AND PROCEDURES

 

 

Energen Corporation
(a)		Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.
(b)		Our chief executive officer and chief financial officer of Energen Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.
Alabama Gas Corporation
(a)		Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and, as of the end of the period covered by this report, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures are effective at that reasonable assurance level.
(b)		Our chief executive officer and chief financial officer of Alabama Gas Corporation have concluded that during the most recent fiscal quarter covered by this report there were no changes in our internal control over financial reporting that materially affected or are reasonably likely to materially affect our internal control over financial reporting.

 

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PART II. OTHER INFORMATION

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

Period		Total Number of Shares Purchased			Average Price Paid per Share			Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs**
April 1, 2010 through April 30, 2010		-				-		-		8,992,700
May 1, 2010 through May 31, 2010		-				-		-		8,992,700
June 1, 2010 through June 30, 2010		15,174	*		$	43.90		-		8,992,700
Total		15,174			$	43.90		-		8,992,700

 

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

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

ITEM 6. EXHIBITS

 

31(a)		–		Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(b)		–		Section 302 Energen Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(c)		–		Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
31(d)		–		Section 302 Alabama Gas Corporation Certification required by Rule 13a-14(a) or Rule 15d-14(a)
32(a)		–		Section 906 Energen Corporation Certification pursuant to 18 U.S.C. Section 1350
32(b)		–		Section 906 Alabama Gas Corporation Certification pursuant to 18 U.S.C. Section 1350
101		–		The following financial statements from Energen Corporation’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, formatted in XBRL: (i) Consolidated Condensed Statements of Income, (ii) Consolidated Condensed Balance Sheets, (iii) Consolidated Condensed Statements of Cash Flows, (iv) the Notes to Unaudited Condensed Financial Statements, tagged as blocks of text.

 

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SIGNATURES

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

 

		ENERGEN CORPORATION ALABAMA GAS CORPORATION
August 3, 2010		By		/s/ J. T. McManus, II
				J. T. McManus, II
				Chairman, Chief Executive Officer and
				President of Energen Corporation; Chairman and Chief Executive Officer of Alabama Gas Corporation
August 3, 2010		By		/s/ Charles W. Porter, Jr.
				Charles W. Porter, Jr.
				Vice President, Chief Financial Officer
				and Treasurer of Energen Corporation
				and Alabama Gas Corporation
August 3, 2010		By		/s/ Russell E. Lynch, Jr.
				Russell E. Lynch, Jr.
				Vice President and Controller of Energen Corporation
August 3, 2010		By		/s/ William D. Marshall
				William D. Marshall
				Vice President and Controller of Alabama Gas Corporation

 

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