ENERGEN CORP - 10-Q Quarterly Report

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 QUARTER ENDED JUNE 30, 2004

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

Commission			IRS Employer
File		State of	Identification
Number	Registrant	Incorporation	Number


1-7810	Energen Corporation	Alabama	63-0757759
2-38960	Alabama Gas Corporation	Alabama	63-0022000

605 Richard Arrington Jr. Boulevard North
Birmingham, Alabama 35203-2707
Telephone Number 205/326-2700
http://www.energen.com

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

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Energen Corporation YES X NO ___

Alabama Gas Corporation YES___ NO X

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of August 3, 2004

	Energen Corporation	$0.01 par value	36,383,542 shares
	Alabama Gas Corporation	$0.01 par value	1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION
FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2004

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	20
	Selected Business Segment Data of Energen Corporation	26
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	27
Item 4.	Controls and Procedures	28

	PART II: OTHER INFORMATION
Item 2.	Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities	29

Item 6.	Exhibits and Reports on Form 8-K	29

SIGNATURES		30

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended		Six months ended
	June 30,		June 30,
(in thousands, except per share data)	2004	2003	2004	2003
Operating Revenues
Oil and gas operations	$ 95,433	$ 89,782	$ 191,660	$ 178,301
Natural gas distribution	92,744	94,248	347,946	315,387
Total operating revenues	188,177	184,030	539,606	493,688

Operating Expenses
Cost of gas	40,291	42,107	179,029	154,079
Operations and maintenance	56,244	47,711	109,391	98,528
Depreciation, depletion and amortization	28,927	29,535	57,663	58,270
Taxes, other than income taxes	16,047	14,165	40,325	35,685
Accretion expense	532	466	1,022	960
Total operating expenses	142,041	133,984	387,430	347,522
Operating Income	46,136	50,046	152,176	146,166

Other Income (Expense)
Interest expense	(10,694)	(10,734)	(21,012)	(21,556)
Other income	633	1,999	1,495	5,119
Other expense	(670)	(2,263)	(1,695)	(5,352)
Total other expense	(10,731)	(10,998)	(21,212)	(21,789)

Income From Continuing Operations Before Income Taxes	35,405	39,048	130,964	124,377
Income tax expense	13,137	14,589	48,499	46,595
Income From Continuing Operations	22,268	24,459	82,465	77,782

Discontinued Operations, net of taxes
Income from discontinued operations	2	149	3	822
Loss on disposal	-	(1,261)	(13)	(676)
Income (Loss) From Discontinued Operations	2	(1,112)	(10)	146

Net Income	$ 22,270	$ 23,347	$ 82,455	$ 77,928

Diluted Earnings Per Average Common Share
Continuing operations	$ 0.61	$ 0.69	$ 2.25	$ 2.21
Discontinued operations	-	(0.03)	-	-
Net Income	$ 0.61	$ 0.66	$ 2.25	$ 2.21
Basic Earnings Per Average Common Share
Continuing operations	$ 0.61	$ 0.70	$ 2.28	$ 2.23
Discontinued operations	-	(0.03)	-	-
Net Income	$ 0.61	$ 0.67	$ 2.28	$ 2.23
Dividends Per Common Share	$ 0.185	$ 0.18	$ 0.370	$ 0.36
Diluted Average Common Shares Outstanding	36,625	35,349	36,600	35,193
Basic Average Common Shares Outstanding	36,230	35,000	36,202	34,868

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

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands)	June 30, 2004	December 31, 2003

ASSETS
Current Assets
Cash and cash equivalents	$ 62,962	$ 2,127
Accounts receivable, net of allowance for doubtful accounts of $11,435 at June 30, 2004, and $9,852 at December 31, 2003	107,004	172,915
Inventories, at average cost
Storage gas inventory	29,556	40,654
Materials and supplies	8,462	7,677
Liquified natural gas in storage	3,528	3,475
Deferred income taxes	49,599	38,145
Prepayments and other	43,891	25,073

Total current assets	305,002	290,066

Property, Plant and Equipment
Oil and gas properties, successful efforts method	1,263,895	1,197,340
Less accumulated depreciation, depletion and amortization	343,601	310,368
Oil and gas properties, net	920,294	886,972
Utility plant	913,221	883,225
Less accumulated depreciation	357,275	341,787
Utility plant, net	555,946	541,438
Other property, net	5,016	5,041

Total property, plant and equipment, net	1,481,256	1,433,451

Other Assets
Regulatory asset	18,082	18,082
Deferred charges and other	30,839	39,833

Total other assets	48,921	57,915

TOTAL ASSETS	$ 1,835,179	$ 1,781,432

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

CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands, except share data)	June 30, 2004	December 31, 2003

CAPITAL AND LIABILITIES
Current Liabilities
Long-term debt due within one year	$ 10,000	$ 10,000
Notes payable to banks	-	11,000
Accounts payable	142,205	135,319
Accrued taxes	43,514	28,551
Customers' deposits	17,683	17,884
Amounts due customers	139	8,571
Accrued wages and benefits	23,699	24,957
Regulatory liability	44,729	54,146
Other	36,121	37,303

Total current liabilities	318,090	327,731

Deferred Credits and Other Liabilities
Asset retirement obligation	33,196	26,515
Minimum pension liability	21,170	17,911
Regulatory liability	108,625	113,427
Deferred income taxes	61,917	33,200
Other	15,663	10,774

Total deferred credits and other liabilities	240,571	201,827

Commitments and Contingencies

Capitalization
Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized	- -	- -
Common shareholders' equity
Common stock, $0.01 par value; 75,000,000 shares authorized, 36,384,593 shares outstanding at June 30, 2004, and 36,223,531 shares outstanding at December 31, 2003	364	362
Premium on capital stock	375,222	367,765
Capital surplus	2,802	2,802
Retained earnings	429,013	360,001
Accumulated other comprehensive loss, net of tax
Unrealized loss on hedges	(40,832)	(21,714)
Minimum pension liability	(8,881)	(8,881)
Deferred compensation on restricted stock	(3,103)	(1,258)
Deferred compensation plan	22,141	17,063
Treasury stock, at cost (483,254 shares at June 30, 2004, and 415,869 shares at December 31, 2003)	(23,082)	(17,108)
Total common shareholders' equity	753,644	699,032
Long-term debt	522,874	552,842
Total capitalization	1,276,518	1,251,874

TOTAL CAPITAL AND LIABILITIES	$ 1,835,179	$ 1,781,432

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

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)

Six months ended June 30, (in thousands)	2004	2003

Operating Activities
Net income	$ 82,455	$ 77,928
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization	57,663	59,190
Deferred income taxes	28,257	27,268
Deferred investment tax credits	(224)	(224)
Change in derivative fair value	3,881	1,406
(Gain) loss on sale of assets	(255)	(9,679)
Loss on properties held-for-sale	-	10,404
Net change in:
Accounts receivable	44,376	22,483
Inventories	10,260	(17,082)
Accounts payable	(21,384)	(6,072)
Amounts due customers	(14,560)	(3,282)
Other current assets and liabilities	10,859	318
Other, net	10,857	(4,847)

Net cash provided by operating activities	212,185	157,811

Investing Activities
Additions to property, plant and equipment	(100,925)	(109,271)
Proceeds from sale of assets	282	20,716
Other, net	(60)	239

Net cash used in investing activities	(100,703)	(88,316)

Financing Activities
Payment of dividends on common stock	(13,443)	(12,573)
Issuance of common stock	4,213	28,833
Purchase of treasury stock	(384)	(339)
Reduction of long-term debt	(30,033)	-
Net change in short-term debt	(11,000)	(83,000)

Net cash used in financing activities	(50,647)	(67,079)

Net change in cash and cash equivalents	60,835	2,416
Cash and cash equivalents at beginning of period	2,127	4,804

Cash and Cash Equivalents at End of Period	$ 62,962	$ 7,220

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

CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
	Three months ended		Six months ended
	June 30,		June 30,
(in thousands)	2004	2003	2004	2003

Operating Revenues	$ 92,744	$ 94,248	$ 347,946	$ 315,387

Operating Expenses
Cost of gas	40,677	42,730	179,883	155,294
Operations and maintenance	30,262	28,103	58,859	56,551
Depreciation	9,858	9,222	19,468	18,147
Income taxes
Current	(1,388)	373	19,414	19,876
Deferred, net	1,620	800	3,078	1,843
Deferred investment tax credits, net	(112)	(112)	(224)	(224)
Taxes, other than income taxes	7,372	7,205	23,147	21,207

Total operating expenses	88,289	88,321	303,625	272,694

Operating Income (Loss)	4,455	5,927	44,321	42,693

Other Income (Expense)
Allowance for funds used during construction	361	170	661	493
Other income	397	952	1,101	2,193
Other expense	(670)	(1,287)	(1,686)	(2,610)

Total other income (expense)	88	(165)	76	76

Interest Charges
Interest on long-term debt	2,763	3,237	5,750	6,475
Other interest expense	1,221	390	1,769	712

Total interest charges	3,984	3,627	7,519	7,187

Net Income	$ 559	$ 2,135	$ 36,878	$ 35,582

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

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)

(in thousands)	June 30, 2004	December 31, 2003

ASSETS
Property, Plant and Equipment
Utility plant	$ 913,221	$ 883,225
Less accumulated depreciation	357,275	341,787

Utility plant, net	555,946	541,438

Other property, net	328	331

Current Assets
Cash and cash equivalents	2,804	1,440
Accounts receivable
Gas	62,595	134,376
Merchandise	1,596	1,210
Other	2,207	1,018
Allowance for doubtful accounts	(10,500)	(9,100)
Inventories, at average cost
Storage gas inventory	29,556	40,654
Materials and supplies	4,525	5,527
Liquified natural gas in storage	3,528	3,475
Deferred income taxes	18,732	17,650
Regulatory asset	-	251
Prepayments and other	40,178	22,056

Total current assets	155,221	218,557

Other Assets
Regulatory asset	18,082	18,082
Deferred charges and other	10,170	19,285

Total other assets	28,252	37,367

TOTAL ASSETS	$ 739,747	$ 797,693

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

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)

(in thousands, except share data)	June 30, 2004	December 31, 2003

CAPITAL AND LIABILITIES
Capitalization
Preferred stock, cumulative $0.01 par value, 120,000 shares authorized, issuable in series-$4.70 Series	$ -	$ -
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares outstanding at June 30, 2004, and December 31, 2003	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	239,324	215,869

Total common shareholder's equity	273,828	250,373
Long-term debt	139,500	169,533

Total capitalization	413,328	419,906

Current Liabilities
Notes payable to banks	-	11,000
Accounts payable	51,814	56,020
Amounts due to affiliates	999	37,290
Accrued taxes	39,637	22,145
Customers' deposits	17,683	17,884
Amounts due customers	139	8,571
Accrued wages and benefits	5,312	6,247
Regulatory liability	44,729	54,146
Other	8,695	9,039

Total current liabilities	169,008	222,342

Deferred Credits and Other Liabilities
Deferred income taxes	36,489	32,178
Minimum pension liability	9,522	6,988
Regulatory liability	108,625	113,427
Other	2,775	2,852

Total deferred credits and other liabilities	157,411	155,445

Commitments and Contingencies	-	-

TOTAL CAPITAL AND LIABILITIES	$ 739,747	$ 797,693

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

CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)

Six months ended June 30, (in thousands)	2004	2003

Operating Activities
Net income	$ 36,878	$ 35,582
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization	19,468	18,147
Deferred income taxes, net	3,078	1,843
Deferred investment tax credits	(224)	(224)
Net change in:
Accounts receivable	50,071	26,623
Inventories	12,047	(15,836)
Accounts payable	(3,955)	2,538
Amounts due customers	(14,560)	(3,282)
Other current assets and liabilities	16,136	9,642
Other, net	2,700	(1,635)

Net cash provided by operating activities	121,639	73,398

Investing Activities
Additions to property, plant and equipment	(29,517)	(28,249)
Other, net	(11)	219

Net cash used in investing activities	(29,528)	(28,030)

Financing Activities
Dividends	(13,423)	-
Reduction of long-term debt	(30,033)	-
Net advances to affiliates	(36,291)	(31,778)
Net change in short-term debt	(11,000)	(13,000)

Net cash used in financing activities	(90,747)	(44,778)

Net change in cash and cash equivalents	1,364	590
Cash and cash equivalents at beginning of period	1,440	2,818

Cash and Cash Equivalents at End of Period	$ 2,804	$ 3,408

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

NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

1. BASIS OF PRESENTATION

The unaudited financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001, included in the 2003 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. On December 5, 2001, the Board of Directors of the Company approved a change in the Company's fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001 to December 31, 2001. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of Ameri ca 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 year-end consolidated condensed balance sheet data included in the interim report was derived from audited financial statements, but does not include all annual disclosures required by accounting principles generally accepted in the United States of America. The Company's natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year.

The quarterly information reflects the application of Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets." SFAS No. 144 requires that gains and losses from the sale of certain oil and gas properties and write-downs of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations in the current and prior periods. All other adjustments to the unaudited financial statements that are, in the opinion of management, necessary for a fair statement of the results of operations 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.

STOCK-BASED COMPENSATION

The Company adopted the fair value recognition provisions of SFAS No. 123, "Accounting for Stock-Based Compensation," prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to four years. The cost related to stock-based employee compensation included in the determination of net income for the three months and six months ended June 30, 2004 and 2003, approximates that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on net income and diluted and basic earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period:

	Three months ended June 30,		Six months ended June 30,
(in thousands)	2004	2003	2004	2003
Net income
As reported	$ 22,270	$ 23,347	$ 82,455	$ 77,928
Stock-based compensation expense included in reported net income, net of tax	1,499	691	2,544	1,374
Stock-based compensation expense determined under value based method, net of tax	(1,133)	(774)	(2,051)	(1,627)
Pro forma	$ 22,636	$ 23,264	$ 82,948	$ 77,675


Diluted earnings per average common share
As reported	$ 0.61	$ 0.66	$ 2.25	$ 2.21
Pro forma	$ 0.62	$ 0.66	$ 2.27	$ 2.21
Basic earnings per average common share
As reported	$ 0.61	$ 0.67	$ 2.28	$ 2.23
Pro forma	$ 0.62	$ 0.66	$ 2.29	$ 2.23

3. REGULATORY

All of Alagasco's utility operations are conducted in the state of Alabama. Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which established the Rate Stabilization and Equalization (RSE) rate-setting process in 1983. RSE was extended with modifications in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended Alagasco's rate-setting methodology, RSE, without change, for a six-year period through January 1, 2008. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. Alagasco's allowed range of return on average equity remains 13.15 percent to 13.65 percent throughout the term of the order, subject to change in the event that the Commission, following a generic rate of return hearing, adjusts the equity returns of all major energy utilities operating under a similar methodology. Under RSE as extended, 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 13.15 percent to 13.65 percent. Reductions in rates can be made quarterly to bring the projected return within the allowed range; increases, however, are allowed only once each rate year, effective December 1, and cannot exceed 4 percent of prior-year revenues. As of September 30, 2003, Alagasco had a $3 million reduction in revenues to bring the return on average equity within the allowed range of return. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco's operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 poi nts above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. The increase in O&M expense per customer was slightly above the index range for the rate year ended September 30, 2003; as a result, the utility returned to customers $0.1 million pre-tax through rate adjustments under the provisions of RSE. An $11.2 million and a $12.7 million annual increase in revenues became effective December 1, 2003 and 2002, respectively, under RSE.

Alagasco calculates a temperature adjustment to customers' monthly bills to substantially remove the effect of departures from normal temperatures on Alagasco's earnings. Adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider, established in 1993, which permits the pass-through to customers of changes in the cost of gas supply.

4. DERIVATIVE COMMODITY INSTRUMENTS

Energen Resources Corporation, Energen's oil and gas subsidiary, periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 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 typically include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company.

Energen Resources applies SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," which requires all derivatives to be recognized on the balance sheet and measured at fair value. If a derivative is designated as a cash flow hedge, the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, is measured at each reporting period. The effective portion of the gain or loss on the derivative instrument is recognized in other comprehensive income (OCI) as a component of equity and subsequently reclassified into earnings as operating revenues when the forecasted transaction affects earnings. The ineffective portion of a derivative's change in fair value is required to be recognized in earnings immediately. Derivatives that do not qualify for hedge treatment under SFAS No. 133 must be recorded at fair value with gains or losses recognized in earnings in the period of change.

As of June 30, 2004, $35.6 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to operating revenues in earnings during the next 12-month period. The actual amounts that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. Gains and losses on derivative instruments that are not accounted for as cash flow hedges as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. For the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, the Company recorded a $332,000 after-tax loss for the three months ended June 30, 2004, and a $184,000 after-tax loss year-to-date. Also, Energen Resources recorded an after-tax loss of $1.2 million for the quarter and a $2.6 million after-tax loss year-to-date on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of June 30, 2004, the Company had 5.14 billion cubic feet (Bcf) of gas hedges and 180,000 barrels (Bbl) of oil hedges which expire by year-end that did not meet the definition of a cash flow hedge but are considered by the Company to be viable economic hedges. As of June 30, 2004, and December 31, 2003, the Company had $25 million and $13.9 million, respectively, included in current and noncurrent deferred income taxes on the consolidated balance sheets related to OCI.

Energen Resources has entered into the following transactions for the remainder of 2004 and subsequent years:
Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2004	10.2 Bcf	$5.04 Mcf	NYMEX Swaps
	12.6 Bcf	$4.30 Mcf	Basin Specific Swaps
	1.2 Bcf	$4.05 - $4.44 Mcf	NYMEX Collars
2005	15.1 Bcf	$5.94 Mcf	NYMEX Swaps
	16.1 Bcf	$4.55 Mcf	Basin Specific Swaps
Oil
2004	728 MBbl	$28.44 Bbl	NYMEX Swaps
	706 MBbl	$27.70 Bbl	West Texas Sour (WTS) Swaps
2005	1,092 MBbl	$31.86 Bbl	NYMEX Swaps
	720 MBbl	$31.17 Bbl	WTS Swaps
Oil Basis Differential
2004	210 MBbl	*	Basis Swaps
2005	612 MBbl	*	Basis Swaps
Natural Gas Liquids
2004	18.6 MMGal	$0.41 Gal	Liquids Swaps
2005	30.2 MMGal	$0.49 Gal	Liquids Swaps
* Average contract prices not meaningful due to the varying nature of each contract.

All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. This process includes specific identification of the hedging instrument and the hedge transaction, the nature of the risk being hedged and how the hedging instrument's effectiveness in hedging the exposure to the hedged transaction's variability in cash flows attributable to the hedged risk will be assessed. Both at the inception of the hedge and on an ongoing basis, the Company assesses whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged items. The Company discontinues hedge accounting if a derivative has ceased to be a highly effective hedge. The maximum term over which Energen Resourc es has hedged exposures to the variability of cash flows is through December 31, 2005.

On December 4, 2000, the APSC authorized Alagasco to engage in energy risk-management activities to manage the utility's cost of gas supply. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet with a corresponding regulatory asset or liability. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco's APSC-approved tariff. In accordance with SFAS No. 71, Alagasco had recorded $35.3 million in prepayments and other representing the fair value of derivatives as of June 30, 2004. As of December 31, 2003, Alagasco had recorded $17 million in prepayments and other and $8.7 million in deferred charges and other. Alagasco also recognized $0.3 million in other current liabilities as of December 31, 2003.

5. RECONCILIATION OF EARNINGS PER SHARE

		Three months ended				Three months ended
(in thousands, except per share amounts)		June 30, 2004				June 30, 2003
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount

Basic EPS	$ 22,270		36,230	$ 0.61	$23,347		35,000	$ 0.67
Effect of Dilutive Securities
Long-range performance shares			130				125
Stock options			249				215
Restricted stock			16				9

Diluted EPS	$ 22,270		36,625	$ 0.61	$23,347		35,349	$ 0.66

		Six months ended				Six months ended
(in thousands, except per share amounts)		June 30, 2004				June 30, 2003
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount

Basic EPS	$ 82,455		36,202	$ 2.28	$77,928		34,868	$ 2.23
Effect of Dilutive Securities
Long-range performance shares			126				121
Stock options			243				197
Restricted stock			29				7

Diluted EPS	$ 82,455		36,600	$ 2.25	$77,928		35,193	$ 2.21

For the three months and six months ended June 30, 2004 and 2003, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.
6. SEGMENT INFORMATION The Company principally is engaged in two business segments: the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution) and the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations).
	Three months ended		Six months ended
	June 30,		June 30,
(in thousands)	2004	2003	2004	2003
Operating revenues from continuing operations
Oil and gas operations	$ 95,819	$ 90,405	$192,514	$ 179,516
Natural gas distribution	92,744	94,248	347,946	315,387
Eliminations and other	(386)	(623)	(854)	(1,215)
Total	$ 188,177	$ 184,030	$539,606	$ 493,688
Operating income (loss) from continuing operations
Oil and gas operations	$ 41,747	$ 43,515	$ 85,880	$ 82,690
Natural gas distribution	4,575	6,988	66,589	64,188
Eliminations and corporate expenses	(186)	(457)	(293)	(712)
Total	$ 46,136	$ 50,046	$152,176	$ 146,166
Other income (expense)
Oil and gas operations	$ (6,848)	$ (7,067)	$(13,778)	$ (14,350)
Natural gas distribution	(3,896)	(3,792)	(7,443)	(7,111)
Eliminations and other	13	(139)	9	(328)
Total	$ (10,731)	$ (10,998)	$(21,212)	$ (21,789)
Income from continuing operations before income taxes	$ 35,405	$ 39,048	$130,964	$ 124,377

(in thousands)	June 30, 2004	December 31, 2003
Identifiable assets
Oil and gas operations	$ 1,011,112	$ 959,815
Natural gas distribution	739,747	797,693
Subtotal	1,750,859	1,757,508
Eliminations and other	84,320	23,924
Total	$ 1,835,179	$ 1,781,432

7. COMPREHENSIVE INCOME (LOSS) Comprehensive income (loss) consisted of the following:
	Three months ended	Three months ended
(in thousands)	June 30, 2004	June 30, 2003

Net Income	$ 22,270	$ 23,347
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($10.5) million and ($14.3) million	(17,119)	(22,357)
Reclassification adjustment, net of tax of $7.2 million and $4.5 million	11,820	7,009

Comprehensive Income	$ 16,971	$ 7,999

	Six months ended	Six months ended
(in thousands)	June 30, 2004	June 30, 2003

Net Income	$ 82,455	$ 77,928
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($22.7) million and ($28.9) million	(38,039)	(45,163)
Reclassification adjustment, net of tax of $11.6 million and $14.5 million	18,921	22,699

Comprehensive Income	$ 63,337	$ 55,464

Accumulated other comprehensive loss consisted of the following:
(in thousands)		June 30, 2004			December 31, 2003

Unrealized loss on hedges, net of tax of ($25.0) million and ($13.9) million		$ (40,832)			$ (21,714)
Minimum pension liability, net of tax of ($4.8) million		(8,881)			(8,881)

Accumulated Other Comprehensive Loss		$ (49,713)			$ (30,595)

8. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS On January 1, 2002, the Company adopted SFAS No. 144, which retains the previous asset impairment requirements of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses on the sale of certain oil and gas properties and write-downs of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale must be rep orted at the lower of the carrying amount or fair value. Energen Resources had no property sales during the second quarter of 2004 or the year-to-date ended June 30, 2004. During the three months and six months ended June 30, 2003, Energen Resources recorded a pre-tax writedown to fair value based upon expected market value of $2.2 million and $10.4 million, respectively, on certain non-strategic gas properties located in the Gulf Coast region. These properties were subsequently sold during the third quarter of 2003 for a pre-tax gain of $0.4 million. The pre-tax gain on disposals for the three months ended June 30, 2003, was $0.09 million and $9.3 million for the six months ended June 30, 2003, largely due to sales of properties located in the San Juan Basin. The following are the results of operations from discontinued operations:
	Three months ended			Six months ended
	June 30,			June 30,
(in thousands, except per share data)	2004		2003	2004		2003

Oil and gas revenues	$ 2		$ 794	$ 2		$ 3,515

Pretax income from discontinued operations	$ 3		$ 243	$ 4		$ 1,346
Income tax expense	1		94	1		524
Income From Discontinued Operations	2		149	3		822

Impairment charge on held-for-sale property	-		(2,157)	-		(10,404)
Gain (loss) on disposal	-		91	(21)		9,297
Income tax benefit	-		(805)	(8)		(431)
Gain (Loss) on Disposal	-		(1,261)	(13)		(676)

Total Income (Loss) From Discontinued Operations	$ 2		$ (1,112)	$ (10)		$ 146

Diluted Earnings Per Average Common Share
Income from Discontinued Operations	$ -		$ -	$ -		$ 0.02
Loss on Disposal	-		(0.03)	-		(0.02)
Total Income from Discontinued Operations	$ -		$ (0.03)	$ -		$ -

Basic Earnings Per Average Common Share
Income from Discontinued Operations	$ -		$ -	$ -		$ 0.02
Loss on Disposal	-		(0.03)	-		(0.02)
Total Income from Discontinued Operations	$ -		$ (0.03)	$ -		$ -

9. EMPLOYEE BENEFIT PLANS

In December 2003, the FASB revised SFAS No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits - an amendment of FASB Statements No. 87, 88 and 106." The revised Statement added additional interim disclosures relating to the net periodic benefit cost of defined benefit pension plans and other postretirement plans effective for interim periods ending after December 15, 2003.

The components of net pension expense were:

(in thousands)	Plan A		Plan B
	Three Months Ended June 30,		Three Months Ended June 30,
	2004	2003	2004	2003
Components of net periodic benefit cost:
Service cost	$ 1,356	$ 989	$ 146	$ 123
Interest cost	1,664	1,660	346	354
Expected long-term return on assets	(1,950)	(1,714)	(522)	(390)
Actuarial loss (gain)	433	157	27	-
Prior service cost amortization	58	58	88	88
Net periodic expense	$ 1,561	$ 1,150	$ 85	$ 175

(in thousands)	Plan A		Plan B
	Six Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
Components of net periodic benefit cost:
Service cost	$ 2,712	$ 1,978	$ 292	$ 246
Interest cost	3,328	3,320	692	708
Expected long-term return on assets	(3,900)	(3,428)	(1,044)	(780)
Actuarial loss (gain)	866	314	54	-
Prior service cost amortization	116	116	176	176
Net periodic expense	$ 3,122	$ 2,300	$ 170	$ 350

In January 2004, the Company contributed $773,000 to Plan A assets and $46,000 to Plan B assets. The Company does not expect to make additional contributions to Plan A or Plan B assets during 2004.

Net periodic post-retirement benefit expense included the following:

(in thousands)	Salaried Employees		Union Employees
	Three Months Ended June 30,		Three Months Ended June 30,
	2004	2003	2004	2003
Components of net periodic benefit cost:
Service cost	$ 320	$ 206	$ 119	$ 103
Interest cost	580	511	494	503
Expected long-term return on assets	(380)	(325)	(615)	(525)
Actuarial loss (gain)	-	-	(73)	(71)
Prior service cost amortization	-	-	1	4
Transition amortization	171	171	321	321
Net periodic expense	$ 691	$ 563	$ 247	$ 335

(in thousands)	Salaried Employees		Union Employees
	Six Months Ended June 30,		Six Months Ended June 30,
	2004	2003	2004	2003
Components of net periodic benefit cost:
Service cost	$ 640	$ 412	$ 238	$ 206
Interest cost	1,160	1,022	988	1,006
Expected long-term return on assets	(760)	(650)	(1,230)	(1,050)
Actuarial loss (gain)	-	-	(146)	(142)
Prior service cost amortization	-	-	2	8
Transition amortization	342	342	642	642
Net periodic expense	$ 1,382	$ 1,126	$ 494	$ 670

For the three and six months ended June 30, 2004, the Company made contributions aggregating $0.9 million and $1.9 million, respectively, to the post-retirement plans. The Company expects to make additional contributions of approximately $1.9 million through the remainder of 2004.

10. COMMITMENTS AND CONTINGENCIES Commitments and Agreements: Certain of Alagasco's long-term contracts for the supply, storage and delivery of natural gas include fixed charges that amount to approximately $209 million through May 2013. Alagasco 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 65.7 billion cubic feet through June 2007. Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive damage awards may bear little or no relation to culpability or actual damages, thus making it increasingly difficult to predict litigation results. Various pending or threatened legal proceedings arising in the normal course of business are in progress currently, and the Company has accrued a provision for estimated costs. 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 and results of operations and is not expected to do so in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs. Alagasco is in the chain of title of nine former manufactured gas plant sites, of which it still owns four, and five manufactured gas distribution sites, of which it still owns one. Alagasco had previously reported eight manufactured gas plant sites. The inclusion of an additional site is based on recently completed title research concerning the site. An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco's share, if any, of such costs will not materially affect the results of operations or financial condition of Alagasco.
11. REGULATORY ASSETS AND LIABILITIES The following table details regulatory assets and liabilities on the balance sheets:
(in thousands)	June 30, 2004		December 31, 2003
	Current	Noncurrent	Current	Noncurrent
Regulatory assets:
Pension asset	$ -	$ 18,082	$ -	$ 18,082
Risk management activities	-	-	251	-
Total regulatory assets	$ -	$ 18,082	$ 251	$ 18,082

Regulatory liabilities:
Enhanced stability reserve	$ 3,868	$ -	$ 3,481	$ -
Gas supply adjustment	685	-	4,903	-
Risk management activities	35,271	-	17,025	8,650
RSE adjustment	322	-	2,619	-
Unbilled service margin	4,583	-	26,118	-
Asset removal costs, net	-	107,751	-	103,727
Other	-	874	-	1,050
Total regulatory liabilities	$ 44,729	$ 108,625	$ 54,146	$ 113,427

12. LONG-TERM DEBT AND SHORT-TERM CREDIT LINES

In April 2004, Alagasco elected to call a total of $30 million of Medium-Term Notes maturing January 16, 2006 to December 15, 2023. During the three-months ended June 30, 2004, the Company recorded a pre-tax loss on debt extinguishment of $0.9 million for the call premiums and unamortized issuance costs.

As of June 30, 2004, Energen and Alagasco had short-term credit lines available for working capital needs of $282 million. Subsequent to June 30, 2004, Energen and Alagasco increased their short-term credit lines available to $287 million. Alagasco has been authorized by the APSC to borrow up to a total of $70 million of these available short-term credit lines.

13. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)

SFAS No. 141, "Business Combinations," requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142, "Goodwill and Other Intangible Assets," establishes guidelines in accounting for goodwill and other intangible assets. The appropriate application of SFAS No. 141 and SFAS No. 142 is being considered to determine whether oil and gas mineral rights should be classified separately as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. Although formal guidance for oil and gas companies had not been issued, at the March 2004 Emerging Issues Task Force (EITF) meeting, a consensus was reached that mineral rights related to the mining industry should be accounted for as tangible assets (EITF 04-2). The Board subsequently ratified the consensus and a FASB Staff Position (FSP) was issued in April 2004 to amend SFAS No. 141 and SFAS No. 142 accordingly. In July 2004, a pr oposed FSP was issued which considers the appropriate balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing entities. The Company will continue to evaluate the impact of the application of these standards as final guidance is provided.

On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Although the Company anticipates that the benefits it pays after 2006 will be lower as a result of the new Medicare provisions, the retiree medical obligations and costs reported do not reflect the impact of this legislation. Deferring the recognition of the new Medicare provisions' impact is permitted by FSP No. 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (FAS 106-1). In May 2004, the FASB issued FSP No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," (FAS 106-2) which provides more specific authoritative guidance on the accounting for this federal subsidy and supersedes FAS 106-1 when adopted. The Company is required to adopt the provisions of FAS 106-2 effective for the first interim period beginning after June 15, 2004. The Company is currently reviewing the impact related to the recognition of the subsidy and the related financial statement disclosures.

14. SUBSEQUENT EVENT

On August 2, 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $263 million. Energen Resources acquired an estimated 240 Bcfe of proved natural gas and natural gas liquids reserves. Approximately 51 percent of the proved reserves are estimated to be behind pipe and undeveloped. The Company estimates that approximately 80 percent of the acquisition reserves are gas with natural gas liquids comprising the balance. Prior to June 30, 2004, Energen used available cash of $20 million for an initial payment related to the acquisition. Energen used its short-term credit facilities and internally generated cash flows to finance the remainder of the acquisition upon completion of the purchase. The effective date of the sale is August 1, 2004.

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

Energen's net income totaled $22.3 million ($0.61 per diluted share) for the three months ended June 30, 2004, compared to net income of $23.3 million ($0.66 per diluted share) recorded in the same period in the prior year. In the second quarter of 2004, Energen's income from continuing operations totaled $22.3 million ($0.61 per diluted share) and compared with income from continuing operations of $24.5 million ($0.69 per diluted share) in the same period a year ago. Income from discontinued operations for the current-year period was minimal as compared with a loss of $1.1 million ($0.03 per diluted share) from the prior-year second quarter. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended June 30, 2004, of $21.8 million compared with $21.5 million in the previous period. Energen Resources generated net income from continuing operations of $21.8 million in the current quarter as compared with $22.6 million in the same quarter last year as higher commodity prices were offset by increased lease operating expenses, decreased production and increased administrative expenses. Energen's natural gas utility, Alagasco, reported net income of $0.6 million in the second quarter of 2004 as compared to net income of $2.1 million in the same period last year primarily due to increased earnings on a higher level of equity offset by the timing of revenue recovery between quarters under the utility's rate-setting mechanism.

For the 2004 year-to-date, Energen's net income totaled $82.5 million ($2.25 per diluted share) and compared favorably to net income of $77.9 million ($2.21 per diluted share) for the same period in the prior year. For the six months ended June 30, 2004, Energen's income from continuing operations totaled $82.5 million ($2.25 per diluted share) and compared with $77.8 million ($2.21 per diluted share) in the same period a year ago. Discontinued operations generated a minimal loss of $10,000 in the current year-to-date period as compared with income from discontinued operations of $146,000 in the same period a year ago. Energen Resources had net income for the six months ended June 30, 2004, of $45 million as compared with $42.4 million in the previous period. Energen Resources generated income from continuing operations of $45 million in the current year-to-date as compared with $42.3 million in the same period last year primarily as a result of higher commodity prices partially offset by the impact of increased lease operating expenses and administrative expenses. Alagasco's net income of $36.9 million in the current year-to-date increased from net income of $35.6 million in the same period in the previous year reflecting the utility's ability to earn on a higher level of equity representing investment in utility plant.

Oil and Gas Operations

Revenues from oil and gas operations rose 6.3 percent to $95.4 million for the three months ended June 30, 2004, largely as a result of significantly increased commodity prices partially offset by lower production. For the year-to-date, revenues from oil and gas operations increased 7.5 percent to $191.7 million primarily due to increased gas, oil and natural gas liquids prices as production remained virtually unchanged in the six months of 2004 compared to the first half of the prior-year. In the current quarter, average gas prices increased 12.3 percent to $4.76 per thousand cubic feet (Mcf), while average oil prices rose 3.4 percent to $26.52 per barrel. Natural gas liquids prices increased 20 percent to an average price of $0.42 per gallon. In the year-to-date, average gas prices increased 10.4 percent to $4.76 per Mcf, average oil prices rose 4 percent to $26.83 per barrel and natural gas liquids prices increased 7.9 percent to an average price of $0.41 per gallon.

Natural gas production from continuing operations in the second quarter declined 3.5 percent to 13.8 billion cubic feet (Bcf), oil volumes decreased 2.2 percent to 831 thousand barrels (MBbl) and natural gas liquids production declined 1.7 percent to 16.9 million gallons (MMgal). For the year-to-date, natural gas production remained relatively stable at 27.5 Bcf and oil production remained stable at 1,704 MBbl. Natural gas liquids production declined 2.1 percent to 32.2 MMgal. Natural gas comprised approximately 65 percent of Energen Resources' production for the current quarter and the year-to-date.

Energen Resources has entered into the following transactions for the remainder of 2004 and subsequent years:

Production Period	Total Hedged Volumes	Average Contract Price	Description
Natural Gas
2004	10.2 Bcf	$5.04 Mcf	NYMEX Swaps
	12.6 Bcf	$4.30 Mcf	Basin Specific Swaps
	1.2 Bcf	$4.05 - $4.44 Mcf	NYMEX Collars
2005	15.1 Bcf	$5.94 Mcf	NYMEX Swaps
	16.1 Bcf	$4.55 Mcf	Basin Specific Swaps
	** 3.0 Bcf	$6.26 Mcf	NYMEX Swaps
	** 1.2 Bcf	$5.78 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2005	** 1.6 Bcf	*	Basis Swaps
Oil
2004	728 MBbl	$28.44 Bbl	NYMEX Swaps
	706 MBbl	$27.70 Bbl	West Texas Sour (WTS) Swaps
2005	1,092 MBbl	$31.86 Bbl	NYMEX Swaps
	720 MBbl	$31.17 Bbl	WTS Swaps
	** 446 MBbl	$35.95 Bbl	NYMEX Swaps
Oil Basis Differential
2004	210 MBbl	*	Basis Swaps
2005	612 MBbl	*	Basis Swaps
	** 391 MBbl	*	Basis Swaps
Natural Gas Liquids
2004	18.6 MMGal	$0.41 Gal	Liquids Swaps
2005	30.2 MMGal	$0.49 Gal	Liquids Swaps
* Average contract prices not meaningful due to the varying nature of each contract.
** Contracts entered into subsequent to June 30, 2004.

Realized prices are anticipated to be lower than New York Mercantile Exchange (NYMEX) prices due to basis differences and other factors. Operations and maintenance (O&M) expense increased $6.6 million for the quarter and $9 million in the year-to-date. Lease operating expenses (excluding production taxes) increased by $3.9 million for the quarter and $4.9 million year-to-date primarily due to increased workover and maintenance expenses, increased ad valorem taxes and additional compression. Administrative expense rose $2.7 million for the three months in the current quarter and $4.2 million in the year-to-date due to labor related and other general and administrative costs. The Company had substantially no exploration expense in the current and prior year quarter and year-to-date periods. Energen Resources' depreciation, depletion and amortization (DD&A) expense for the quarter decreased $1.2 million and $1.9 million in the year-to-date. The average depletion rates for the three-months and the year-to-date ended June 30, 2004, was $0.88 as compared to $0.91 in the same periods a year ago largely due to current production in basins with lower DD&A rates. Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $1.8 million higher this quarter and $2.8 million higher for the year-to-date largely due to increased commodity market prices. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets," which was adopted as of January 1, 2002. Energen Resources had no property sales during the current quarter or year-to-date ended June 30, 2004. In the prior year quarter, Energen Resources recorded a pre-tax gain of $0.1 million from the sale of certain properties and a pre-tax writedown of $2.2 million on certai n non-strategic gas properties located in the Gulf Coast region, which were subsequently sold in August 2003. In the previous year-to-date, Energen Resources recorded a pre-tax gain of $9.3 million from the sale of certain properties located in the San Juan Basin and a pre-tax writedown of $10.4 million on the gas properties located in the Gulf Coast region. On August 2, 2004, Energen Resources completed a purchase of San Juan Basin coalbed methane properties from a private company for approximately $263 million. Energen Resources acquired an estimated 240 Bcfe of proved natural gas and natural gas liquids reserves. Approximately 51 percent of the proved reserves are estimated to be behind pipe and undeveloped. The Company estimates that approximately 80 percent of the acquisition reserves are gas with natural gas liquids comprising the balance. Natural Gas Distribution Natural gas distribution revenues declined $1.5 million for the quarter largely due to a decrease in gas usage volumes. For the quarter, residential sales volumes declined 2.5 percent while small commercial and industrial customer sales volumes increased 4.6 percent. Transportation volumes decreased 4.4 percent in period comparisons. Revenues for the year-to-date increased $32.6 million primarily due to an increase in commodity gas costs partially offset by a decrease in weather related sales volumes. Weather that was 2.2 percent warmer than in the same period last year contributed to a 5.3 percent decline in residential sales volumes and a 1.2 percent decrease in small commercial and industrial customer sales volumes. Large transportation volumes decreased 1.4 percent. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the GSA rider. For the quarter, gas costs decreased by 4.8 percent and volumes remained essentially unchanged. For the yea r-to-date, an increase of 15.8 percent was largely due to significantly higher gas costs partially offset by decreased gas purchase volumes. The GSA rider in Alagasco's rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco's tariff provides a temperature adjustment to certain customers' bills designed to substantially remove the effect of departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers. As discussed more fully in Note 3, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend the Company's rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. O&M expense increase 7.7 percent in the current quarter primarily due to increased labor related costs and higher bad debt expense. In the year-to-date, O&M expense increased 4.1 percent largely due to increased labor related costs. A 6.9 percent increase in depreciation expense in the current quarter and a 7.3 percent increase in the year-to-date was due to normal replacement of the utility's distribution and support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly. Non-Operating Items Interest expense for the Company remained stable in the second quarter and decreased $0.5 million in the year-to-date. In period comparisons, interest expense was reduced by the payment of current maturities of long-term debt of $23 million, the election to call $30 million of Medium-Term Notes in April 2004 by Alagasco and a $32.1 million equity issuance completed in July 2003, which reduced short-term debt. These reductions in borrowings were partially offset by $50 million of long-term debt issued by Energen in October 2003 and a $0.9 million pre-tax loss on debt extinguishment for the call premiums and unamortized debt issuance costs from the aforementioned Medium-Term Notes. In quarter comparisons, income tax expense decreased $1.5 million primarily due to lower consolidated pre-tax income. Income tax expense increased $1.9 million in year-to-date comparisons largely due to higher consolidated pre-tax income.
FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $212.2 million as compared to $157.8 million in the same period last year. Increased net income during the period was augmented by changes in working capital items, which are highly influenced by throughput, changes in weather, and timing of payments. Working capital needs at Alagasco were primarily affected by storage gas inventory and increased gas costs compared to the prior period. The Company had a net outflow of cash from investing activities of $100.7 million through the six months ended June 30, 2004, primarily due to additions of property, plant and equipment. Energen Resources invested $71.4 million in capital expenditures primarily related to the development of oil and gas properties and a $20 million expenditure related to the San Juan Basin acquisition described above. Utility capital expenditures totaled $29.5 million in the year-to-date and primarily represented system distribution expansion and support facilities. The Company used $50.6 million for financing activities in the year-to-date primarily due Alagasco's election to call $30 million of Medium-Term Notes in April 2004. Also influencing financing activities was the repayment of short-term borrowings and dividends paid to common stockholders partially offset by proceeds from the issuance of common stock. As more fully discussed below, the Company used available cash to fund a portion of the San Juan Basin coalbed methane acquisition completed August 2, 2004.
FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue to implement its diversified growth strategy that focuses on expanding Energen Resources' oil and gas operations through the acquisition of producing properties with developmental potential while maintaining the strength of the Company's utility foundation. For the five years ended December 31, 2003, Energen's diluted EPS grew at an average compound rate of 21.9 percent a year. Over the next five years, Energen is targeting an average diluted EPS growth rate over each rolling five-year period of approximately 7 to 8 percent a year. Energen Resources' capital investment for oil and gas activities over a five-year planning period ending December 31, 2008, is estimated to be approximately $1.5 billion, with $1.1 billion for property acquisitions, $138 million for related acquisition development, $205 million for other development and $25 million for exploratory and other activities. To finance Energen Resources' investment program, the Company expects primarily to utilize short-term credit facilities to supplement internally generated cash flow. The Company may periodically issue long-term debt and equity to replace short-term obligations, enhance liquidity and provide for long-term financing. Energen has available short-term credit facilities aggregating $287 million to help finance its growth plans and operating needs. In July 2003, the Company completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. In October 2003, the Company issued $50 million of long-term debt. These proceeds were used for general corporate purposes and to repay a portion of short-term debt incurred to finance the oil and gas property acquisition program of Energen Resources. On August 2, 2004, Energen Resources completed a purchase to buy San Juan Basin coalbed methane properties from a private company for approximately $263 million. Energen used available cash and existing lines of credit to close the acquisition. In 2004, Energen Resources plans to invest approximately $390 million, including $263 million for the acquisition of San Juan Basin coalbed methane properties, $6 million in related acquisition development, $106 million in other development and approximately $6 million in exploratory activities. As of December 31, 2003, the estimated amount of development of previously identified proved undeveloped reserves was approximately $77 million. Capital investment at Energen Resources in 2005 is expected to approximate $200 million for property acquisitions, $27 million for related acquisition development and $50 million for other development and exploration. Of this $50 million, development of previously identified proved undeveloped reserves is estimated to be $35 million and exploratory exposure is estimated to be $3 million. Energen Resources currently expects production to approximate 86 Bcfe and 92.9 Bcfe for 2004 and 2005, respectively. The Company's most recent estimate of production attributable to already owned proved reserves was prepared as of December 31, 2003. Production from proved reserves owned as of December 31, 2003, was estimated as 81.6 Bcfe and 77 Bcfe for 2004 and 2005, respectively. Energen Resources' continued ability to invest in property acquisitions will be influenced significantly by industry trends, as the producing property acquisition market historically has been cyclical. Notwithstanding the estimated expenditures mentioned above, as an acquisition oriented company, Energen Resources continually evaluates acquisition opportunities which arise in the marketplace and from time to time may pursue acquisitions that meet Energen's acquisition criteria which could result in capital expenditures different than those outlined above. These acquisitions or negotiations to sell, trade or otherwise dispose of properties may alter the timing, nature and amounts of the aforementioned financing activities. Alagasco maintains an investment in storage gas that is expected to average approximately $38 million in 2004 but may vary depending upon the price of natural gas. In April 2004, Alagasco called $30 million of Medium-Term Notes maturing January 16, 2006 to December 15, 2023. During 2004 and 2005, Alagasco plans to invest approximately $58 million and $53 million, respectively, in utility capital expenditures for normal distribution and support systems. Over the Company's five-year planning period ending December 31, 2008, Alagasco anticipates capital investments of approximately $275 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. Alagasco may issue up to $80 million in long-term debt in the near-term planning period as a result of drawing on the short-term credit facilities for capital expenditures and the anticipated refinancing of the $30 million recalled debt discussed above. A lagasco also may refinance existing long-term debt. Certain of Alagasco's long-term contracts for the supply, storage and delivery of natural gas include fixed charges that amount to approximately $209 million through May 2013. 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 65.7 billion cubic feet through June 2007. Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 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 typically include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company. Access to capital is an integral part of the Company's business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. These agencies have recently evaluated the business and financial profiles of the Company in light of the announcement of the aforementioned coalbed methane gas acquisition and a continued business strategy that focuses on expanding the oil and gas operations through the acquisition of properties. In June 2004, Standard and Poor's confirmed its credit rating for Energen and Alagasco as A- and revised its outlook from stable to negative. In July 2004, Moody's Investor Services placed under review for possible downgrade the current ratings of Energen and Alagasco. The current Moody's debt rating for Energen is Baa1 senior unsecured and Alagasco's debt rating is A1 senior unsecured. While the Company expects to have ongoing access to its short-term credit facilities and the broa der long-term markets, continued accessibility could be affected by future economic and business conditions. While the timing and amount of future dividends remains at the discretion of the Board of Directors, the Company anticipates annual dividend increases of approximately 4 percent a year. Energen also plans to have both its lines of business support future dividends. Consistent with payouts of other gas utility companies, Alagasco is expected to pay out 65 percent to 75 percent of its net income to shareholders while Energen Resources is expected to pay out a small portion of its net income. The Company's Board also expects to change the date of its annual review of the dividend from July to January, beginning in January 2005. The Company's Board of Directors increased the quarterly cash dividend four percent on July 22, 2004. On an annualized basis, the Company's new dividend rate is 77 cents per share. Recent Pronouncements of the Financial Accounting Standards Board (FASB) SFAS No. 141, "Business Combinations," requires all business combinations initiated after June 30, 2001, to be accounted for using the purchase method and SFAS No. 142, "Goodwill and Other Intangible Assets," establishes guidelines in accounting for goodwill and other intangible assets. The appropriate application of SFAS No. 141 and SFAS No. 142 is being considered to determine whether oil and gas mineral rights should be classified separately as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. Although formal guidance for oil and gas companies had not been issued, at the March 2004 Emerging Issues Task Force (EITF) meeting, a consensus was reached that mineral rights related to the mining industry should be accounted for as tangible assets (EITF 04-2). The Board subsequently ratified the consensus and a FASB Staff Position (FSP) was issued in April 2004 to amend SFAS No. 141 and SFAS No. 142 accordingly. In July 2004, a pr oposed FSP was issued which considers the appropriate balance sheet classification and disclosures for drilling and mineral rights of oil and gas producing entities. The Company will continue to evaluate the impact of the application of these standards as final guidance is provided. On December 8, 2003, President Bush signed into law a bill that expands Medicare, adding a prescription drug benefit for Medicare-eligible retirees starting in 2006. Although the Company anticipates that the benefits it pays after 2006 will be lower as a result of the new Medicare provisions, the retiree medical obligations and costs reported do not reflect the impact of this legislation. Deferring the recognition of the new Medicare provisions' impact is permitted by FSP No. 106-1, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003" (FAS 106-1). In May 2004, the FASB issued FSP No. 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003," (FAS 106-2) which provides more specific authoritative guidance on the accounting for this federal subsidy and supersedes FAS 106-1 when adopted. The Company is required to adopt the provisions of FAS 106-2 effective for the first interim period beginning after June 15, 2004. The Company is currently reviewing the impact related to the recognition of the subsidy and the related financial statement disclosures. 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, divestitures or restructurings. The Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts. The Company undertakes no 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, future business decisions, and other uncertainties, all of which are difficult to predict. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The total amount or timing of actual future production may vary significantly from reserve and production estimates. In the event Energen Resources is unable to fully invest its planned acquisition, development and exploratory expenditures, future operating revenues, production, and proved reserves could be negatively affected. The drilling of development and exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns and these risks can be affected by lease and rig availability, complex geology and other factors. Although Energen Resources makes use of swaps, options and fixed-price contracts to mitigate risk, fluctuations in future oil and gas prices could materially affect the Company's financial position, results of operation 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.
SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)

	Three months ended		Six months ended
	June 30,		June 30,
(in thousands, except sales price data)	2004	2003	2004	2003

Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$ 65,408	$ 60,438	$ 130,884	$ 118,534
Oil	22,026	21,803	45,713	43,906
Natural gas liquids	7,135	5,975	13,155	12,651
Other	864	1,566	1,908	3,210
Total	$ 95,433	$ 89,782	$ 191,660	$ 178,301

Production volumes from continuing operations
Natural gas (MMcf)	13,754	14,248	27,491	27,515
Oil (MBbl)	831	850	1,704	1,701
Natural gas liquids (MMgal)	16.9	17.2	32.2	32.9
Production volumes from continuing operations (MMcfe)	21,149	21,807	42,310	42,427
Total production volumes (MMcfe)	21,149	21,959	42,310	43,154
Average sales price including effects of hedging
Natural gas (Mcf)	$ 4.76	$ 4.24	$ 4.76	$ 4.31
Oil (barrel)	$ 26.52	$ 25.65	$ 26.83	$ 25.81
Natural gas liquids (gallon)	$ 0.42	$ 0.35	$ 0.41	$ 0.38
Average sales price excluding effects of hedging
Natural gas (Mcf)	$ 5.61	$ 4.92	$ 5.45	$ 5.35
Oil (barrel)	$ 35.69	$ 27.64	$ 34.18	$ 29.81
Natural gas liquids (gallon)	$ 0.52	$ 0.38	$ 0.51	$ 0.45
Other data from continuing operations
Lease operating expense (LOE)
LOE and other	$ 18,445	$ 14,529	$ 36,275	$ 31,342
Production taxes	$ 8,463	$ 6,710	$ 16,711	$ 13,957
Total	$ 26,908	$ 21,239	$ 52,986	$ 45,299
Depreciation, depletion and amortization	$ 19,069	$ 20,313	$ 38,195	$ 40,123
Capital expenditures	$ 49,964	$ 27,191	$ 71,408	$ 81,022
Exploration expenditures	$ 52	$ 38	$ 100	$ 178
Operating income	$ 41,747	$ 43,515	$ 85,880	$ 82,690
Natural Gas Distribution
Operating revenues
Residential	$ 56,644	$ 59,446	$ 233,304	$ 213,385
Commercial and industrial - small	24,575	24,773	89,176	79,712
Transportation	9,102	8,667	20,477	19,798
Other	2,423	1,362	4,989	2,492
Total	$ 92,744	$ 94,248	$ 347,946	$ 315,387

Gas delivery volumes (MMcf)
Residential	3,760	3,857	18,869	19,917
Commercial and industrial - small	2,227	2,129	8,275	8,373
Transportation	13,183	13,785	27,781	28,178
Total	19,170	19,771	54,925	56,468
Other data
Depreciation and amortization	$ 9,858	$ 9,222	$ 19,468	$ 18,147
Capital expenditures	$ 16,410	$ 14,996	$ 30,221	$ 28,987
Operating income	$ 4,575	$ 6,988	$ 66,589	$ 64,188

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under Statement of Financial Accounting Standard (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities," to hedge its exposure to price fluctuations 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 typically include over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. These counterparties have been deemed creditworthy by the Company and have agreed in certain instances to post collateral with the Company when unrealized gains on hedges exceed certain specified contractual amounts. Notwithstanding these agreements, the Company is at risk for econom ic loss based upon the creditworthiness of its counterparties. In some contracts, the amount of credit allowed before collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking the hedge. The maximum term over which Energen Resources is hedging exposures to the variability of cash flows is through December 31, 2005.

See Note 4 for details related to the Company's hedging activities.

ITEM 4. CONTROLS AND PROCEDURES


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

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

PART II. OTHER INFORMATION


ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER PURCHASES OF EQUITY SECURITIES

Period		Total Number of Shares Purchased*	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares that May Yet Be Purchased Under the Plans**

April 1, 2004 through April 30, 2004		-	-	-	-
May 1, 2004 through May 31, 2004		-	-	-	-
June 1, 2004 through June 30, 2004		288	$ 48.19	-	1,075,350
Total		288	$ 48.19	-	1,075,350

* Acquired in connection with tax withholdings on stock compensation plans.
** By resolution adopted May 24, 1994, and supplemented by a resolution adopted April 26, 2000, the Board of Directors authorized the Company to repurchase up to 1,782,200 shares of the Company's common stock. The resolutions do not have an expiration date.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a.	Exhibits

	31(a) - Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a)
	31(b) - Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a)
	32 - Section 906 Certificate pursuant to 18 U.S.C. Section 1350

b.	Reports on Form 8-K

	Form 8-K dated April 28, 2004, reporting Energen and Alagasco issued a press release announcing financial results for the first quarter of 2004

	Form 8-K dated May 6, 2004, reporting Energen and Alagasco issued a press release announcing increased earnings guidance for 2005

	Form 8-K dated May 25, 2004, reporting Energen and Alagasco issued a press release announcing increased earnings guidance for 2005

	Form 8-K dated June 29, 2004, reporting Energen issued a press release announcing Energen Resources signed a purchase and sale agreement to buy San Juan Basin coalbed methane properties
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 4, 2004		By /s/ Wm. Michael Warren, Jr.
		Wm. Michael Warren, Jr.
		Chairman, President and Chief Executive
		Officer of Energen Corporation, Chairman and Chief Executive Officer of
		Alabama Gas Corporation



August 4, 2004		By /s/ G. C. Ketcham
		G. C. Ketcham
		Executive Vice President, Chief
		Financial Officer and Treasurer of
		Energen Corporation and Alabama Gas
		Corporation


August 4, 2004		By /s/ Grace B. Carr
		Grace B. Carr
		Vice President and Controller of Energen
		Corporation


August 4, 2004		By /s/ Paula H. Rushing
		Paula H. Rushing
		Vice President-Finance of Alabama Gas
		Corporation

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