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, 2003

\| \|	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 Act). YES X NO ____

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of August 12, 2003

	Energen Corporation	$0.01 par value	36,018,297 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, 2003

TABLE OF CONTENTS

		Page

PART I: FINANCIAL INFORMATION


Item 1.	Financial Statements
	(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	21
	Selected Business Segment Data of Energen Corporation	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	28
Item 4.	Controls and Procedures	29

	PART II: OTHER INFORMATION

Item 6.	Exhibits and Reports on Form 8-K	30

SIGNATURES		31

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended		Six months ended
	June 30,		June 30,
(in thousands, except per share data)	2003	2002	2003	2002
Operating Revenues
Oil and gas operations	$ 89,756	$ 62,097	$ 178,274	$ 106,954
Natural gas distribution	94,248	75,709	315,387	272,233
Total operating revenues	184,004	137,806	493,661	379,187

Operating Expenses
Cost of gas	42,107	29,993	154,079	126,141
Operations and maintenance	47,705	44,842	98,502	89,772
Depreciation, depletion and amortization	29,521	25,987	58,246	49,028
Taxes, other than income taxes	14,166	11,176	35,688	27,080
Total operating expenses	133,499	111,998	346,515	292,021
Operating Income	50,505	25,808	147,146	87,166

Other Income (Expense)
Interest expense	(10,734)	(11,172)	(21,556)	(21,841)
Accretion expense	(466)	(472)	(960)	(851)
Other income	1,999	3,129	5,119	6,707
Other expense	(2,263)	(3,086)	(5,352)	(6,603)
Total other expense	(11,464)	(11,601)	(22,749)	(22,588)

Income From Continuing Operations Before Income Taxes and Cumulative Effect of Change in Accounting Principle	39,041	14,207	124,397	64,578
Income tax expense	14,584	1,407	46,602	12,671
Income From Continuing Operations Before Cumulative Effect of Change in Accounting Principle	24,457	12,800	77,795	51,907

Discontinued Operations, net of taxes
Income (loss) from discontinued operations	151	(362)	809	(567)
Gain (loss) on disposal	(1,261)	306	(676)	306
Income (Loss) From Discontinued Operations	(1,110)	(56)	133	(261)

Cumulative Effect of Change in Accounting Principle, net of taxes	-	-	-	(2,220)
Net Income	$ 23,347	$ 12,744	$ 77,928	$ 49,426

Diluted Earnings Per Average Common Share
Continuing Operations	$ 0.69	$ 0.37	$ 2.21	$ 1.58
Discontinued Operations	(0.03)	-	-	(0.01)
Cumulative effect of change in accounting principle	-	-	-	(0.07)
Net Income	$ 0.66	$ 0.37	$ 2.21	$ 1.50
Basic Earnings Per Average Common Share
Continuing Operations	$ 0.70	$ 0.38	$ 2.23	$ 1.59
Discontinued Operations	(0.03)	(0.01)	-	(0.01)
Cumulative effect of change in accounting principle	-	-	-	(0.07)
Net Income	$ 0.67	$ 0.37	$ 2.23	$ 1.51
Dividends Per Common Share	$ 0.18	$ 0.175	$ 0.36	$ 0.35
Diluted Average Common Shares Outstanding	35,349	34,406	35,193	32,927
Basic Average Common Shares Outstanding	35,000	34,093	34,868	32,645

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

CONDENSED CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands)	June 30, 2003	December 31, 2002

ASSETS
Current Assets
Cash and cash equivalents	$ 7,220	$ 4,804
Accounts receivable, net of allowance for doubtful accounts of $10,661 at June 30, 2003, and $8,874 at December 31, 2002	95,561	100,946
Inventories, at average cost
Storage gas inventory	39,286	23,668
Materials and supplies	10,020	8,335
Liquified natural gas in storage	3,450	3,671
Deferred gas costs	3,942	21,040
Deferred income taxes	44,240	33,941
Prepayments and other	22,209	20,367
	225,928
Total current assets	225,928	216,772

Property, Plant and Equipment
Oil and gas properties, successful efforts method	1,123,394	1,103,472
Less accumulated depreciation, depletion and amortization	278,601	269,616
Oil and gas properties, net	844,793	833,856
Utility plant	854,240	825,421
Less accumulated depreciation	426,537	408,165
Utility plant, net	427,703	417,256
Other property, net	5,171	5,691

Total property, plant and equipment, net	1,277,667	1,256,803

Other Assets
Deferred income taxes	-	16,333
Assets held-for-sale	7,558	-
Regulatory asset	15,457	14,744
Deferred charges and other	29,680	26,239

Total other assets	52,695	57,316

TOTAL ASSETS	$ 1,556,290	$ 1,530,891

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

CONDENSED CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)

(in thousands, except share data)	June 30, 2003	December 31, 2002

CAPITAL AND LIABILITIES
Current Liabilities
Long-term debt due within one year	$ 23,000	$ 23,000
Notes payable to banks	30,000	113,000
Accounts payable	127,290	103,964
Accrued taxes	44,239	27,936
Customers' deposits	16,847	17,404
Amounts due customers	-	8,458
Accrued wages and benefits	20,496	23,652
Regulatory liability	14,665	23,814
Other	39,318	34,710

Total current liabilities	315,855	375,938

Deferred Credits and Other Liabilities
Asset retirement obligation	25,233	27,235
Minimum pension liability	25,825	25,825
Regulatory liability	1,260	1,468
Asset retirement obligation on assets held-for-sale	1,558	-
Deferred income taxes	7,036	-
Other	13,438	4,661

Total deferred credits and other liabilities	74,350	59,189

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, 35,661,469 shares outstanding at June 30, 2003, and 34,745,477 shares outstanding at December 31, 2002	357	347
Premium on capital stock	348,459	320,060
Capital surplus	2,802	2,802
Retained earnings	340,625	275,266
Accumulated other comprehensive loss, net of tax	(37,275)	(14,811)
Deferred compensation on restricted stock	(1,886)	(770)
Deferred compensation plan	12,949	10,348
Treasury stock, at cost (388,965 shares at June 30, 2003, and 358,228 shares at December 31, 2002)	(12,952)	(10,432)

Total common shareholders' equity	653,079	582,810
Long-term debt	513,006	512,954

Total capitalization	1,166,085	1,095,764

TOTAL CAPITAL AND LIABILITIES	$ 1,556,290	$ 1,530,891

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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)

Six months ended June 30, (in thousands)	2003	2002

Operating Activities
Net income	$ 77,928	$ 49,426
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization	59,190	55,200
Deferred income taxes	27,268	470
Deferred investment tax credits	(224)	(224)
Change in derivative fair value	1,406	(7,565)
Gain on sale of assets	(9,679)	(3,191)
Loss on properties held-for-sale	10,404	-
Cumulative effect of change in accounting principle, net of taxes	-	(2,220)
Net change in:
Accounts receivable	5,385	5,382
Inventories	(17,082)	24,487
Deferred gas costs	17,098	15,122
Accounts payable	(6,072)	(10,550)
Amounts due customers	(3,282)	(9,857)
Other current assets and liabilities	318	12,108
Other, net	(4,847)	2,000

Net cash provided by operating activities	157,811	130,588

Investing Activities
Additions to property, plant and equipment	(109,271)	(61,908)
Acquisition	-	(117,043)
Proceeds from sale of assets	20,716	13,554
Other, net	239	133

Net cash used in investing activities	(88,316)	(165,264)

Financing Activities
Payment of dividends on common stock	(12,573)	(11,482)
Issuance of common stock	28,833	5,121
Purchase of treasury stock	(339)	-
Reduction of long-term debt	-	(1,509)
Net change in short-term debt	(83,000)	39,047

Net cash provided by (used in) financing activities	(67,079)	31,177

Net change in cash and cash equivalents	2,416	(3,499)
Cash and cash equivalents at beginning of period	4,804	6,482

Cash and Cash Equivalents at End of Period	$ 7,220	$ 2,983

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)	2003	2002	2003	2002

Operating Revenues	$ 94,248	$ 75,709	$ 315,387	$ 272,233

Operating Expenses
Cost of gas	42,730	30,482	155,294	126,924
Operations and maintenance	28,103	26,015	56,551	52,588
Depreciation	9,222	8,313	18,147	16,543
Income taxes
Current	373	(990)	19,876	17,401
Deferred, net	800	1,513	1,843	1,890
Deferred investment tax credits, net	(112)	(112)	(224)	(224)
Taxes, other than income taxes	7,205	6,178	21,207	18,646

Total operating expenses	88,321	71,399	272,694	233,768

Operating Income	5,927	4,310	42,693	38,465

Other Income (Expense)
Allowance for funds used during construction	170	312	493	525
Other income	952	1,417	2,193	2,706
Other expense	(1,287)	(1,453)	(2,610)	(2,879)

Total other income (expense)	(165)	276	76	352

Interest Charges
Interest on long-term debt	3,237	3,324	6,475	6,651
Other interest expense	390	298	712	660

Total interest charges	3,627	3,622	7,187	7,311

Net Income	$ 2,135	$ 964	$ 35,582	$ 31,506

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

CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)

(in thousands)	June 30, 2003	December 31, 2002

ASSETS
Property, Plant and Equipment
Utility plant	$ 854,240	$ 825,421
Less accumulated depreciation	426,537	408,165

Utility plant, net	427,703	417,256

Other property, net	334	842

Current Assets
Cash and cash equivalents	3,408	2,818
Accounts receivable
Gas	60,609	70,220
Merchandise	1,321	1,748
Other	2,969	656
Allowance for doubtful accounts	(10,000)	(8,200)
Advances to affiliates	30,346	-
Inventories, at average cost
Storage gas inventory	39,286	23,668
Materials and supplies	5,488	5,049
Liquified natural gas in storage	3,450	3,671
Deferred gas costs	3,942	21,040
Deferred income taxes	19,335	20,093
Prepayments and other	4,791	18,314

Total current assets	164,945	159,077

Other Assets
Regulatory asset	15,457	14,744
Deferred charges and other	13,136	11,290

Total other assets	28,593	26,034

TOTAL ASSETS	$ 621,575	$ 603,209

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, 2003	December 31, 2002

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, 2003, and December 31, 2002	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	218,434	182,852

Total common shareholder's equity	252,938	217,356
Long-term debt	169,533	169,533

Total capitalization	422,471	386,889

Current Liabilities
Long-term debt due within one year	15,000	15,000
Notes payable to banks	-	13,000
Accounts payable	58,258	55,720
Amounts due to affiliates	-	1,432
Accrued taxes	36,680	24,044
Customers' deposits	16,847	17,404
Amounts due customers	-	8,458
Accrued wages and benefits	4,094	5,710
Regulatory liability	14,665	23,814
Other	9,659	8,947

Total current liabilities	155,203	173,529

Deferred Credits and Other Liabilities
Deferred income taxes	21,996	20,747
Minimum pension liability	18,661	18,661
Accumulated deferred investment tax credits	532	756
Regulatory liability	1,260	1,468
Customer advances for construction and other	1,452	1,159

Total deferred credits and other liabilities	43,901	42,791

Commitments and Contingencies	-	-

TOTAL CAPITAL AND LIABILITIES	$ 621,575	$ 603,209

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)	2003	2002

Operating Activities
Net income	$ 35,582	$ 31,506
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization	18,147	16,543
Deferred income taxes, net	1,843	1,890
Deferred investment tax credits	(224)	(224)
Net change in:
Accounts receivable	9,525	10,223
Inventories	(15,836)	24,971
Deferred gas costs	17,098	15,122
Accounts payable	2,538	7,746
Amounts due customers	(3,282)	(9,857)
Other current assets and liabilities	9,642	6,095
Other, net	(1,635)	(6,226)

Net cash provided by operating activities	73,398	97,789

Investing Activities
Additions to property, plant and equipment	(28,249)	(29,151)
Other, net	219	124

Net cash used in investing activities	(28,030)	(29,027)

Financing Activities
Dividends	-	(5,491)
Net advances to affiliates	(31,778)	(46,493)
Reduction of long-term debt	-	(427)
Net change in short-term debt	(13,000)	(19,000)

Net cash used in financing activities	(44,778)	(71,411)

Net change in cash and cash equivalents	590	(2,649)
Cash and cash equivalents at beginning of period	2,818	3,372

Cash and Cash Equivalents at End of Period	$ 3,408	$ 723

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 year ended December 31, 2002, the three months ended December 31, 2001, and the years ended September 30, 2001 and 2000, included in the 2002 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 Amer ica 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 the interim periods are not necessarily indicative of the results that may be expected for the year. The quarterly information has been revised to reflect the adoption in 2002 of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." Upon adoption of SFAS No. 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and capitalize an equal amount as the cost of the asset as of January 1, 2002. Upon initial application of the Statement, a cumulative effect of a change in accounting principle of $2.2 million after-tax was required in order to recognize a liability for any existing asset retirement obligations. The Company adopted SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets," on January 1, 2002. 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 associat ed 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 (as amended), "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. Therefore, 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, 2003 and 2002, is less than 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 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)	2003	2002	2003	2002
Net income
As reported	$ 23,347	$ 12,744	$ 77,928	$ 49,426
Stock-based compensation expense included in reported net income, net of tax	691	573	1,374	1,145
Stock-based compensation expense determined under value based method, net of tax	(774)	(597)	(1,627)	(1,193)
Pro forma	$ 23,264	$ 12,720	$ 77,675	$ 49,378
Diluted earnings per average common share
As reported	$ 0.66	$ 0.37	$ 2.21	$ 1.50
Pro forma	$ 0.66	$ 0.37	$ 2.21	$ 1.50
Basic earnings per average common share
As reported	$ 0.67	$ 0.37	$ 2.23	$ 1.51
Pro forma	$ 0.66	$ 0.37	$ 2.23	$ 1.51

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 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 c onducts 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. RSE limits the utility's equity upon which a return is permitted to 60 percent of total capitalization and provides for certain cost control measures designed to monitor Alagasco's operations and maintenance (O&M) expense. Under the inflation-based cost control measurement established by the APSC, if the percentage change in O&M expense per customer falls within a range of 1.25 points above or below the percentage change in the Consumer Price Index For All Urban Consumers (index range), no adjustment is required. If the change in O&M expense per customer exceeds the index range, three-quarters of the difference is returned to customers. To the extent the change is less than the index range, the utility benefits by one-half of the difference through future rate adjustments. The increase in O&M expense per customer was above the index range for the rate year ended September 30, 2002; as a result, the utility returned to customers $0.3 million pre-tax through rate adjustments under the provisions of RSE. A $12.4 million and $16.3 million annual increase in revenues became effective December 1, 2002 and 2001, 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 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.

The APSC approved an Enhanced Stability Reserve (ESR) beginning rate year 1998 with an approved 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 such as storms, severe weather, and outages, when one or a combination of two such events results in more than $200,000 of additional O&M expense during a rate year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the rate year, if such losses cause Alagasco's return on average equity to fall below 13.15 percent. Following a year in which a charge against the ESR is made, the APSC provides for accretions to the ESR of no more than $40,000 monthly until the maximum funding level is achieved. At June 30, 2003, and December 31, 2002, the ESR balances of $3.4 million and $3 million, respectively, were included in regulatory liability on the consolidated financial statements.

At June 30, 2003 and December 31, 2002, Alagasco had an $18.7 million accrued obligation related to its salaried and union pension plans. In accordance with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation," Alagasco recorded a regulatory asset of $14.7 million at June 30, 2003, and December 31, 2002, respectively, for the portion of the accrued obligation to be recovered through rates in future periods.

4. DERIVATIVE COMMODITY INSTRUMENTS

The Company applies SFAS No. 133 (subsequently amended by SFAS Nos. 137 and 138), "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 Company is required to measure the effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item, 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 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.

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 include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counterparty credit.

Energen Resources had certain agreements with Enron North America Corp. (Enron) as the counterparty as of October 1, 2001. As prescribed by SFAS No. 133, the value of the outstanding Enron contracts which qualified for cash flow hedge accounting treatment was reflected on the balance sheet as an asset and the effective portion of the derivative was reported as OCI. These outstanding contracts ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. The Company recorded an expense to O&M for the write-down to fair value of the asset related to the effected derivative contracts. The deferred revenues related to the non-performing hedges were recorded in accumulated other comprehensive income until such time as they were reclassified to earnings as originally forecasted to occur. As a result, Energen's net income in the three-month transition period ended December 31, 2001, reflected a one-time, non-cash expense of $5.5 million, net of tax. En ergen's net income reflected a non-cash benefit of $2 million, net of tax, for the three month period ended June 30, 2002, and a $4.1 million, net of tax, non-cash benefit for the six month period ended June 30, 2002. Net income in the year ended December 31, 2002, reflected a total non-cash benefit of $5.7 million, net of tax, related to the Enron hedge position.

As of June 30, 2003, $26.4 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to earnings during the next twelve-month period. 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 no gain or loss for the three-months ended June 30, 2003, and a $1.1 million after-tax loss year-to-date. Also, Energen Resources recorded an after-tax loss of $226,000 for the quarter and a $560,000 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, 2003, the Company had 0.67 billion cub ic feet (Bcf) of gas 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, 2003, and December 31, 2002, the Company had a $21.1 million asset and a $6.7 million asset, 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 2003 and subsequent years:

Production Period	Total Hedged Volume	Average Contract Price	Description
Natural Gas
2003	16.1 Bcf	$4.12 Mcf	NYMEX Swaps
	2.7 Bcf	$4.02 Mcf	Basin Specific Swaps
	2.4 Bcf	$3.72 - $4.70 Mcf	Basin Specific Collars
2004	8.9 Bcf	$4.13 Mcf	NYMEX Swaps
	18.7 Bcf	$4.07 Mcf	Basin Specific Swaps
	2.4 Bcf	$4.05 - $4.44 Mcf	NYMEX Collars
2005	1.2 Bcf	$3.75 Mcf	NYMEX Swaps
	6.0 Bcf	$3.96 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2003	8.2 Bcf	**	Basis Swaps
Oil
2003	1,170 MBbl	$25.94 Bbl	NYMEX Swaps
2004	120 MBbl	$26.15 Bbl	NYMEX Swaps
	* 540 MBbl	$25.75 Bbl	NYMEX Swaps
Oil Basis Differential
2003	1,107 MBbl	**	Basis Swaps
2004	* 180 MBbl	**	Basis Swaps
Natural Gas Liquids
2003	19 MMGal	$0.42 Gal	Liquids Swaps
2004	30 MMGal	$0.41 Gal	Liquids Swaps
* Contracts entered into subsequent to June 30, 2003.
** 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 En ergen Resources 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 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 its APSC-approved tariff. In accordance with SFAS No. 71, Alagasco had recorded a regulatory asset of $16.8 million representing the fair value of derivatives as of December 31, 2002. As of June 30, 2003, Alagasco recorded a regulatory liability of $2.4 million and a regulatory asset of $.7 million representing the fair value of derivatives.

5. RECONCILIATION OF EARNINGS PER SHARE

		Three months ended				Three months ended
(in thousands, except per share amounts)		June 30, 2003				June 30, 2002
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount

Basic EPS	$ 23,347		35,000	$ 0.67	$ 12,744		34,093	$ 0.37
Effect of Dilutive Securities
Long-range performance shares			125				131
Stock options			215				179
Restricted stock			9				3

Diluted EPS	$ 23,347		35,349	$ 0.66	$ 12,744		34,406	$ 0.37

		Six months ended				Six months ended
(in thousands, except per share amounts)		June 30, 2003				June 30, 2002
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount

Basic EPS	$ 77,928		34,868	$ 2.23	$ 49,426		32,645	$ 1.51
Effect of Dilutive Securities
Long-range performance shares			121				124
Stock options			197				155
Restricted stock			7				3

Diluted EPS	$ 77,928		35,193	$ 2.21	$ 49,426		32,927	$ 1.50

For the three months and the six months ended June 30, 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)	2003	2002	2003	2002
Operating revenues from continuing operations
Oil and gas operations	$ 89,756	$ 62,097	$ 178,274	$ 106,954
Natural gas distribution	94,248	75,709	315,387	272,233
Total	$ 184,004	$ 137,806	$ 493,661	$ 379,187
Operating income (loss) from continuing operations
Oil and gas operations	$ 43,974	$ 21,558	$ 83,670	$ 30,562
Natural gas distribution	6,988	4,721	64,188	57,532
Eliminations and corporate expenses	(457)	(471)	(712)	(928)
Total	$ 50,505	$ 25,808	$ 147,146	$ 87,166

(in thousands)	June 30, 2003	December 31, 2002
Identifiable assets
Oil and gas operations	$ 939,519	$ 926,839
Natural gas distribution	591,229	603,209
Eliminations and other	25,542	843
Total	$ 1,556,290	$ 1,530,891

7. COMPREHENSIVE INCOME (LOSS) Comprehensive income (loss) consisted of the following:
	Three months ended	Three months ended
(in thousands)	June 30, 2003	June 30, 2002

Net Income	$ 23,347	$ 12,744
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($14.3) million and $0.7 million	(22,357)	1,034
Reclassification adjustment, net of tax of $4.5 million and ($12) thousand	7,009	(19)

Comprehensive Income	$ 7,999	$ 13,759

	Six months ended	Six months ended
(in thousands)	June 30, 2003	June 30, 2002

Net Income	$ 77,928	$ 49,426
Other comprehensive income (loss)
Current period change in fair value of derivative instruments, net of tax of ($28.9) million and ($1.2) million	(45,163)	(1,837)
Reclassification adjustment, net of tax of $14.5 million and ($1.8) million	22,699	(2,776)

Comprehensive Income	$ 55,464	$ 44,813

Accumulated other comprehensive income (loss) consisted of the following:

(in thousands)		June 30, 2003			December 31, 2002

Unrealized loss on hedges, net of tax of ($21.1) million and ($6.7) million		$ (32,935)			$ (10,471)
Minimum pension liability, net of tax of ($2.3) million		(4,340)			(4,340)

Accumulated Other Comprehensive Loss		$ (37,275)			$ (14,811)

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 flow of the asset. In addition, SFAS No. 144 requires that gains and losses in 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. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. During the six months ended June 30, 2003, Energen Resources recorded a pre-tax writedown of $10.4 million o n certain non-strategic gas properties located in the Gulf Coast region, which are currently classified as held-for-sale. This writedown adjusted the carrying amount of the properties to their fair value based upon expected market value. The properties have a net carrying amount of $6 million and are being actively marketed for sale. The Company anticipates the sale of this property during the quarter ended September 30, 2003. 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)	2003		2002	2003		2002

Oil and gas revenues	$ 820		$ 2,301	$ 3,542		$ 5,303

Pretax income (loss) from discontinued operations	$ 250		$ (594)	$ 1,326		$ (930)
Income tax expense (benefit)	99		(232)	517		(363)
Income (Loss) From Discontinued Operations	151		(362)	809		(567)

Impairment charge on held-for-sale property	(2,157)		(2,815)	(10,404)		(2,815)
Gain on disposal	91		3,316	9,297		3,316
Income tax expense (benefit)	(805)		195	(431)		195
Gain (Loss) on Disposal	(1,261)		306	(676)		306

Total Income (Loss) From Discontinued Operations	$ (1,110)		$ (56)	$ 133		$ (261)

Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations	$ -		$ (0.01)	$ 0.02		$ (0.02)
Gain (Loss) on Disposal	(0.03)		0.01	(0.02)		0.01
Total Income (Loss) from Discontinued Operations	$ (0.03)		$ -	$ -		$ (0.01)

Basic Earnings Per Average Common Share
Income (Loss ) from Discontinued Operations	$ -		$ (0.01)	$ 0.02		$ (0.02)
Gain (Loss) on Disposal	(0.03)		-	(0.02)		0.01
Total Income (Loss) from Discontinued Operations	$ (0.03)		$ (0.01)	$ -		$ (0.01)

9. ACQUISITION OF OIL AND GAS PROPERTIES On April 8, 2002, Energen Resources completed its purchase of oil and gas properties located in the Permian Basin in west Texas from First Permian, L.L.C. (First Permian), for approximately $120 million cash and 3,043,479 shares of the Company's common stock. The common stock was valued at $23.95 per share, the average stock price at the time Energen signed the related Purchase and Sale Agreement. The total acquisition approximated $184 million. Summarized below are the consolidated results of operations for the six months ended June 31, 2002, on an unaudited pro forma basis as if the purchase of assets 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 six months ended June 30, 2002, and on the data provided by the seller, after giving effect to the issuance of 3,043,479 million shares of common stock. 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.
	Six months ended
(in thousands, except per share data)	June 30, 2002

Operating revenues		$ 385,792
Income from continuing operations before cumulative effect of change in accounting principle		$ 53,040
Net income		$ 50,559
Diluted earnings per average common share		$ 1.54
Basic earnings per average common share		$ 1.55

10. EQUITY OFFERING

In July 2003, Energen completed the issuance of 1,000,000 shares of common stock through the periodic draw-down of shares in a shelf registration. The sale of shares began May 9, 2003, and concluded on July 16, 2003, generating net proceeds of $32.4 million. These proceeds have been 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.

11. COMMITMENTS AND CONTINGENCIES

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: The Company is subject to various environmental regulations. Management believes that the Company is in compliance with the currently applicable standards of the environmental agencies to which it is subject and that potential environmental liabilities are minimal. Alagasco is in the chain of title of eight former manufactured gas plant sites, of which it still owns four, and five manufactured gas distribution sites, of which it still owns one. 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. Also, to the extent

Energen Resources has operating agreements with various joint venture partners, environmental costs would be shared proportionately.

To date, the Company's expenditures to comply with environmental or safety regulations have not been material and are not expected to be significant in the future. However, new regulations, enforcement policies, claims for damages or other events could result in significant future costs.

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

The FASB issued Interpretation No. 45, "Guarantor's Accounting and Disclosures Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others," (FIN 45) in November 2002. FIN 45 clarifies the requirements of SFAS No. 5, "Accounting for Contingencies," related to a guarantor's accounting for, and disclosures of, the issuance of certain types of guarantees. Management has completed a review of potential contingencies and noted the following guarantee disclosures: 1) Alagasco has an agreement with a financial institution whereby it can sell on an ongoing basis, with recourse, certain installment receivables related to its merchandising program up to a maximum of $15 million. Alagasco's exposure to credit loss in the event of non-performance by customers is represented by the balance of installment receivables. The Company adopted the provisions for recognition and measurement for all guarantees issued or modified after December 31, 2002 on a prospective basis. The fair v alue of guarantees issued after December 31, 2002, is not significant to the Company. 2) Alagasco purchases gas as agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the consolidated balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer with the customer liable for any resulting losses. At June 30, 2003, the gas guaranteed had an aggregate purchase price of $10 million and a market value of $9.7 million. The maximum term over which Alagasco has guarantees outstanding is through December 2004.

SFAS No. 141, "Business Combinations," and SFAS No. 142, "Goodwill and Other Intangible Assets," were issued by the FASB in June 2001 and became effective on July 1, 2001 and January 1, 2002, respectively. SFAS No. 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method and SFAS No. 142 establishes new guidelines in accounting for goodwill and other intangible assets. Under SFAS No. 142, goodwill and certain intangible assets that have indefinite useful lives are not amortized, but rather are reviewed annually for impairment. The FASB, the Securities and Exchange Commission and others continue to discuss the appropriate application of SFAS No. 141 and SFAS No. 142 to oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves. Depending on the outcome of such discussions, these oil and gas mineral rights for both undeveloped and developed leaseholds could be cla ssified separately from oil and gas properties as intangible assets on the balance sheet, rather than as a part of oil and gas properties as currently recorded. In addition, the disclosures required by SFAS No. 141 and SFAS No. 142 relative to intangible assets would be included in the notes to the financial statements. The Company anticipates that this interpretation of SFAS No. 141 and SFAS No. 142 would only affect balance sheet classifications of oil and gas leaseholds. Results of operations and cash flows are not anticipated to be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with SFAS No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies." The Company will continue to evaluate the impact of the application of these standards as further guidance is provided.

In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." SFAS No. 149 amends and clarifies accounting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133. This statement is effective for contracts entered into or modified after June 30, 2003 and is to be applied on a prospective basis. The Company is currently evaluating the impact of this standard but does not anticipate a material impact on its financial condition or results of operations from the adoption of this pronouncement.

The FASB issued SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity," in May 2003. SFAS No. 150 establishes standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Company has not entered into such financial instruments and therefore does not anticipate an impact on its financial condition or results of operations from the adoption of this pronouncement.

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

Energen's net income totaled $23.3 million ($0.66 per diluted share) for the three months ended June 30, 2003, and compared favorably to net income of $12.7 million ($0.37 per diluted share) recorded in the same period last year. In the second quarter of 2003, Energen's income from continuing operations totaled $24.5 million ($0.69 per diluted share) and compared with income from continuing operations of $12.8 million ($0.37 per diluted share) in the same period a year ago. Energen Resources Corporation, Energen's oil and gas subsidiary, had net income for the three months ended June 30, 2003 of $21.5 million as compared with $11.8 million in the previous period. Energen Resources generated income from continuing operations of $22.6 million in the current quarter as compared with $11.8 million in the same quarter last year primarily as a result of significantly increased commodity prices for oil, natural gas and natural gas liquids as well as the impact of higher gas production volumes. Pr ior period income from continuing operations included a non-cash benefit of $2.0 million after-tax, or $0.06 per diluted share, associated with its previous hedge position with Enron North America Corp. (Enron) and the recognition of $3.6 million in non-conventional fuels tax credits. Energen's natural gas utility, Alagasco, reported net income of $2.1 million in the second quarter of 2003 as compared to net income of $1.0 million in the same period last year primarily due to increased earnings on a higher level of equity and the timing of revenue recovery between quarters.

For the 2003 year-to-date, Energen's net income totaled $77.9 million ($2.21 per diluted share) and compared favorably to net income of $49.4 million ($1.50 per diluted share) for the same period in the prior year. For the six months ended June 30, 2003, Energen's income from continuing operations before the cumulative effect of a change in accounting principle totaled $77.8 million ($2.21 per diluted share) and compared with $51.9 million ($1.58 per diluted share) in the same period a year ago. Energen Resources had net income for the six months ended June 30, 2003 of $42.4 million as compared with $18.2 million in the previous period. Net income in the prior year-to-date included a one-time charge of $2.2 million after-tax ($0.07 per diluted share), reflecting the cumulative effect on prior years of the adoption of Statement of Financial Accounting Standard (SFAS) No. 143, "Accounting for Asset Retirement Obligations." Energen Resources generated income from continuing operations before the cumulative effect of a change in accounting principle of $42.3 million in the current year-to-date as compared with $20.7 million in the same period last year primarily as a result of higher commodity prices along with the impact of increased oil and gas production volumes. Prior period income from continuing operations before the cumulative effect of a change in accounting principle included a non-cash benefit of $4.1 million after-tax, or $0.12 per diluted share, associated with its previous hedge position with Enron and the recognition of $11.6 million in non-conventional fuels tax credits. Alagasco's earnings of $35.6 million in the current year-to-date increased from net income of $31.5 million in the same period in the previous year primarily due to increased earnings on a higher level of equity and the timing of revenue recovery on cycle sale customers.

Oil and Gas Operations

Revenues from oil and gas operations rose 44.5 percent to $89.8 million for the three months ended June 30, 2003, largely as a result of significantly increased commodity prices and increased gas production volumes. For the year-to-date, revenues from oil and gas operations increased 66.7 percent to $178.3 million primarily due to increased commodity prices and increased production volumes. Including the prior period non-cash benefit from the former Enron hedges, average gas prices increased 33.8 percent to $4.24 per thousand cubic feet (Mcf), while average oil prices rose 9.9 percent to $25.65 per barrel and natural gas liquids prices increased 15.8 percent to an average price of $14.58 per barrel in the current quarter. For the year-to-date, including the prior period non-cash benefit from the former Enron hedges, average gas prices increased 47.6 percent to $4.31 per Mcf, average oil prices increased 11.6 percent to $25.81 per barrel and natural gas liquids prices increased 41 perc ent to an average price of $16.13 per barrel.

Natural gas production from continuing operations in the second quarter increased 27.2 percent to 14.2 billion cubic feet (Bcf), while oil volumes declined 2 percent to 850 thousand barrels (MBbl). Natural gas liquids production remained stable at 410 MBbl. The increase in natural gas production in the current quarter largely was due to acquisitions in the San Juan Basin, a new Permian Basin gas project and the successful coalbed methane down-spacing program. For the year-to-date, natural gas production rose 23 percent to 27.5 Bcf, oil volumes increased 27 percent to 1,701 MBbl and natural gas liquids production declined 1 percent to 784 MBbl. The increase in natural gas and oil production largely was due to the same reasons that influenced the quarter results as well as a prior year acquisition of oil properties in the Permian Basin. Natural gas comprised approximately 65 percent of Energen Resources' production for the current quarter and the year-to-date.

Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under 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. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counterparty credit. All hedge transactions are subject t o the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions.

Energen Resources has entered into the following transactions for the remainder of 2003 and subsequent years:

Production Period	Total Hedged Volume	Average Contract Price	Description
Natural Gas
2003	16.1 Bcf	$4.12 Mcf	NYMEX Swaps
	2.7 Bcf	$4.02 Mcf	Basin Specific Swaps
	2.4 Bcf	$3.72 - $4.70 Mcf	Basin Specific Collars
2004	8.9 Bcf	$4.13 Mcf	NYMEX Swaps
	18.7 Bcf	$4.07 Mcf	Basin Specific Swaps
	2.4 Bcf	$4.05 - $4.44 Mcf	NYMEX Collars
2005	1.2 Bcf	$3.75 Mcf	NYMEX Swaps
	6.0 Bcf	$3.96 Mcf	Basin Specific Swaps
Natural Gas Basis Differential
2003	8.2 Bcf	**	Basis Swaps
Oil
2003	1,170 MBbl	$25.94 Bbl	NYMEX Swaps
2004	120 MBbl	$26.15 Bbl	NYMEX Swaps
	* 540 MBbl	$25.75 Bbl	NYMEX Swaps
Oil Basis Differential
2003	1,107 MBbl	**	Basis Swaps
2004	* 180 MBbl	**	Basis Swaps
Natural Gas Liquids
2003	19 MMGal	$0.42 Gal	Liquids Swaps
2004	30 MMGal	$0.41 Gal	Liquids Swaps
* Contracts entered into subsequent to June 30, 2003.
** Average contract prices not meaningful due to the varying nature of each contract.

Realized prices are anticipated to be lower than NYMEX prices due to basis differences and other factors. Production from continuing operations in 2003 is expected to approximate 85.1 Bcfe, including approximately 82.7 Bcfe of production from proved reserves owned at December 31, 2002.

Operations and maintenance (O&M) expense increased $0.8 million for the quarter and $5.0 million in the year-to-date. Lease operating expenses (excluding production taxes) increased by $1.2 million for the quarter and $6.4 million year-to-date primarily due to the acquisition of oil and gas properties. Exploration expense was lower by $0.2 million in the second quarter and $1.8 million year-to-date, largely due to the timing of exploratory efforts.

Energen Resources' depreciation, depletion and amortization (DD&A) expense for the quarter rose $2.6 million and $7.6 million in the year-to-date primarily as a result of increased production. The average depletion rate for the current quarter was $0.91 as compared to $0.92 in the same period a year ago. For the six months ended June 30, 2003, the average depletion rate was $0.91 as compared to $0.90 in the previous period.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $2.1 million higher this quarter and $5.9 million higher for the year-to-date largely due to significantly increased commodity market prices as well as increased production.

Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the writedown of certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets," which was adopted as of January 1, 2002. In the current 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 certain non-strategic gas properties located in the Gulf Coast region. In the year-to-date, Energen Resources rec orded a pre-tax gain of $9.3 million from the sale of 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, which are currently classified as held-for-sale. In the previous quarter and year-to-date Energen Resources recorded a pre-tax gain of $0.3 million. The net gains (losses) from these transactions are included in total income (loss) from discontinued operations.

Natural Gas Distribution

Natural gas distribution revenues increased $18.5 million for the quarter largely due to an increase in the commodity cost of gas. Transportation volumes decreased 5.3 percent over the same period last year primarily due to higher gas prices which resulted in alternate fuel usage. Revenues for the year-to-date increased $43.2 million due to an increase in the commodity cost of gas as well as an increase in weather related usage. Weather that was 6.6 percent colder than in the same period last year contributed to a 10 percent increase in residential sales volumes and a 10.7 percent increase in small commercial and industrial customer sales volumes. For the same reasons that influenced the quarter, large transportation volumes decreased 4.8 percent. Higher commodity gas prices along with increased gas purchase volumes contributed to a 40.2 percent increase in cost of gas for the quarter and a 22.4 percent increase year-to-date. The GSA rider in Alagasco's rate schedule provides for a pas s-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 2, 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 increased 8 percent in the current quarter and 7.5 percent in the year-to-date primarily due to increased information technology related costs, increased bad debt expense and higher labor related costs. A 10.9 percent increase in depreciation expense in the current quarter and a 9.7 percent increase in the year-to-date period were due to normal growth of the utility's distribution system and replacement of support systems with higher depreciation rates than average rates applicable to the distribution system. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.

Non-Operating Items

Interest expense for the Company decreased $0.4 million in the second quarter and $0.3 million for the year-to-date comparisons. Reduced long-term debt of $22.7 million, including the retirement of Series 1993 Notes for $7.8 million in September 2002, was partially offset by increased short-term debt at Energen, primarily related to Energen Resources' acquisition of Permian Basin properties in April 2002.

Income tax expense increased $13.2 million in quarter comparisons primarily due to higher consolidated pre-tax income and the absence of $3.6 million in non-conventional fuels tax credits recognized in the same period a year ago. In year-to-date comparisons, income tax expense rose $33.9 million due to higher pre-tax income and the recognition in the prior year of $11.6 million in non-conventional fuels tax credits. The Company's ability to generate nonconventional fuels tax credits on qualified production ended December 31, 2002, with the expiration of the credit.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $157.8 million as compared to $130.6 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 affected by colder-than-normal weather and increased gas costs compared to the prior period.

The Company had a net investment of $88.3 million through the six months ended June 30, 2003, primarily in additions of property, plant and equipment. Energen Resources invested $81 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. In March 2003, Energen Resources completed its purchase of oil and gas properties located in the San Juan Basin for approximately $37 million. The Company gained an estimated 93 Bcfe of long-lived proved natural gas reserves associated with these acquisitions. Energen Resources sold certain properties in the current year-to-date resulting in cash proceeds of $20.7 million. Utility capital expenditures totaled $28.2 million in the year-to-date and primarily represented system distribution expansion and support facilities.

The Company used $67.1 million for financing activities in the year-to-date primarily due to the repayment of borrowings under Energen's short-term credit facilities partially offset by proceeds from the issuance of common stock.

FUTURE CAPITAL RESOURCES AND LIQUIDITY

The Company plans to continue to implement its 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 calendar years ended December 31, 2002, Energen's diluted EPS grew at an average compound rate of 11.5 percent a year. Over the next five years, Energen is targeting an average EPS growth rate over each rolling five-year period of approximately 7 to 8 percent a year.

To finance Energen Resources' investment program, the Company expects to utilize short-term credit facilities to supplement internally generated cash flow, with long-term debt and equity providing permanent financing. Energen currently has available short-term credit facilities aggregating $267 million to help finance its growth plans and operating needs. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued accessibility could be affected by future economic and business conditions. Energen's management plans to utilize increases in cash flows to help finance Energen Resources' acquisition strategy. In July 2003, the Company completed a $32.4 million equity issuance through the periodic draw-down of shares in a shelf registration. During 2003, the Company may issue up to $75 million in long-term debt to replace short-term obligations and to provide permanent financing for its acquisition strategy. During the five year period ending D ecember 31, 2007, the Company expects to provide up to $13 million a year from the issuance of common stock through the dividend reinvestment and direct stock purchase plan and through employee savings plans.

In 2003 Energen Resources plans to invest approximately $165 million, including $41 million in property acquisitions and related development and $124 million in other development and exploratory activities. Included in this $124 million is approximately $65 million for the development of previously identified proved undeveloped reserves and exploratory exposure of approximately $3 million. Capital investment at Energen Resources in 2004 is expected to approximate $110 million for property acquisitions and related development and $85 million for other development and exploration. Of this $85 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' capital investment for oil and gas activities over the five-year period ending December 31, 2007 is estimated to be approximately $830 million, with $570 million for property acquisitions and related development, $235 million for other developme nt and $25 million for exploratory and other activities. Of the $235 million, Energen Resources anticipates spending approximately $120 million on development of previously identified proved undeveloped reserves; of the $25 million, Energen Resources anticipates incurring approximately $15 million in exploratory exposure. 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 strategy. These acquisitions may alter the aforementioned financing requirements. Additionally, Energen Resources may enter into negotiations to sell, trade or otherwise dispose of properties which may reduce or eliminate the a mount of additional financing described above.

A dramatic increase in national wholesale natural gas prices will increase natural gas costs for Alagasco customers for the 2003-2004 heating season as compared to the 2002-2003 heating season. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment rider which permits the pass-through to customers for changes in the cost of gas supply. On March 1, 2003, Alagasco increased its rates to begin recovering these increased gas costs although such increases will not have a significant impact on most customers until the winter heating season.

During 2003, Alagasco plans to invest approximately $57 million in utility capital expenditures for normal distribution and support systems. Alagasco maintains an investment in storage gas that is expected to average approximately $37 million in 2003. Alagasco plans to invest approximately $55 million in utility capital expenditures during 2004. The utility anticipates funding these capital requirements through internally generated capital. Over the Company's five-year planning period ending December 31, 2007, Alagasco anticipates capital investments of approximately $265 million.

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 include regulated natural gas and crude oil futures contracts traded on the NYMEX and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counter party credit.

Forward-Looking Statements and Risks

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 futures, swaps 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)	2003	2002	2003	2002

Oil and Gas Operations
Operating revenues from continuing operations
Natural gas	$ 60,420	$ 35,509	$ 118,517	$ 65,420
Oil	21,796	20,227	43,897	30,980
Natural gas liquids	5,974	5,158	12,650	9,044
Other	1,566	1,203	3,210	1,510
Total	$ 89,756	$ 62,097	$ 178,274	$ 106,954

Production volumes from continuing operations
Natural gas (MMcf)	14,248	11,202	27,515	22,371
Oil (MBbl)	850	867	1,701	1,339
Natural gas liquids (MBbl)	410	410	784	791
Production volumes from continuing operations (MMcfe)	21,805	18,863	42,425	35,150
Total production volumes (MMcfe)	21,959	19,766	43,154	37,184
Average sales price including effects of hedging
Natural gas (Mcf)	$ 4.24	$ 3.17	$ 4.31	$ 2.92
Oil (barrel)	$ 25.65	$ 23.33	$ 25.81	$ 23.13
Natural gas liquids (barrel)	$ 14.58	$ 12.59	$ 16.13	$ 11.44
Average sales price excluding effects of hedging
Natural gas (Mcf)	$ 4.92	$ 3.09	$ 5.35	$ 2.69
Oil (barrel)	$ 27.63	$ 24.32	$ 29.81	$ 22.87
Natural gas liquids (barrel)	$ 16.19	$ 12.59	$ 18.78	$ 11.44
Other data from continuing operations
Lease operating expense (LOE)
LOE and other	$ 14,523	$ 13,324	$ 31,315	$ 24,910
Production taxes	$ 6,711	$ 4,626	$ 13,960	$ 8,056
Total	$ 21,234	$ 17,950	$ 45,275	$ 32,966
Depreciation, depletion and amortization	$ 20,299	$ 17,674	$ 40,099	$ 32,485
Capital expenditures	$ 27,191	$ 194,541	$ 81,022	$ 216,199
Exploration expenditures	$ 38	$ 272	$ 178	$ 1,940
Operating income	$ 43,974	$ 21,558	$ 83,670	$ 30,562
Natural Gas Distribution
Operating revenues
Residential	$ 59,446	$ 46,076	$ 213,385	$ 183,487
Commercial and industrial - small	24,773	18,939	79,712	66,336
Transportation	8,667	9,461	19,798	20,103
Other	1,362	1,233	2,492	2,307
Total	$ 94,248	$ 75,709	$ 315,387	$ 272,233

Gas delivery volumes (MMcf)
Residential	3,857	3,804	19,917	18,098
Commercial and industrial - small	2,129	2,068	8,373	7,562
Transportation	13,785	14,550	28,178	29,601
Total	19,771	20,422	56,468	55,261

Other data
Depreciation and amortization	$ 9,222	$ 8,313	$ 18,147	$ 16,543
Capital expenditures	$ 14,996	$ 15,810	$ 28,987	$ 29,596
Operating income	$ 6,988	$ 4,721	$ 64,188	$ 57,532

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 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 include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. These counterparties have been deemed creditworthy by the Company and have agreed in certain instances to post collateral with the Company when unrealized gains on hedges exceed certain specified contr actual amounts. Notwithstanding these agreements, the Company is at risk for economic loss based upon the credit worthiness of its counterparties. In some contracts, the amount of credit allowed before Energen Resources or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade to have available counterparty credit. 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.

Energen Resources had certain agreements with Enron North America Corp. (Enron) as the counterparty as of October 1, 2001. As prescribed by SFAS No. 133, the value of the outstanding Enron contracts which qualified for cash flow hedge accounting treatment was reflected on the balance sheet as an asset and the effective portion of the derivative was reported as other comprehensive income. These outstanding contracts ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. The Company recorded an expense to operations and maintenance for the write-down to fair value of the asset related to the effected derivative contracts. The deferred revenues related to the non-performing hedges were recorded in accumulated other comprehensive income until such time as they were reclassified to earnings as originally forecasted to occur. As a result, Energen's net income in the three-month transition period ended December 31, 2001, reflected a one-time, non-ca sh expense of $5.5 million, net of tax. Energen's net income reflected a non-cash benefit of $2 million, net of tax, for the three month period ended June 30, 2002, and a $4.1 million, net of tax, non-cash benefit for the six month period ended June 30, 2002. Net income in the year ended December 31, 2002, reflected a total non-cash benefit of $5.7 million, net of tax, related to the Enron hedge position.

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 significant 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 6. EXHIBITS AND REPORTS ON FORM 8-K

a.	Exhibits

	31(a) - Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	31(b) - Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

	32 - Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes- Oxley Act of 2002.

b.	Reports on Form 8-K

	Form 8-K dated April 24, 2003, reporting Energen and Alagasco issued a press release announcing financial results for the first quarter of 2003.

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 13, 2003		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 13, 2003		By /s/ G. C. Ketcham
		G. C. Ketcham
		Executive Vice President, Chief
		Financial Officer and Treasurer of
		Energen Corporation and Alabama Gas
		Corporation


August 13, 2003		By /s/ Grace B. Carr
		Grace B. Carr
		Vice President and Controller of Energen
		Corporation


August 13, 2003		By /s/ Paula H. Rushing
		Paula H. Rushing
		Vice President-Finance of Alabama Gas
		Corporation

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