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, 2001

OR

|  |  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 the number of shares outstanding of each of the issuers' classes of common stock, as of August 10, 2001:

Energen Corporation	$0.01 par value	31,015,160 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, 2001
TABLE OF CONTENTS
		Page
PART I: FINANCIAL INFORMATION
Item 1.	Financial Statements
	(a) Consolidated Statements of Income of Energen Corporation	3
	(b) Consolidated Balance Sheets of Energen Corporation	4
	(c) Consolidated Statements of Cash Flows of Energen Corporation	6
	(d) Statements of Income of Alabama Gas Corporation	7
	(e) Balance Sheets of Alabama Gas Corporation	8
	(f) Statements of Cash Flows of Alabama Gas Corporation	10
	(g) Notes to Unaudited Financial Statements	11
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	16
	Selected Business Segment Data of Energen Corporation	21
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	22
	PART II: OTHER INFORMATION
Item 6.	Exhibits and Reports on Form 8-K	23
SIGNATURES		24

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended			Nine months ended
	June 30,			June 30,
(in thousands, except per share data)		2001	2000		2001	2000

Operating Revenues
Natural gas distribution	$ 103,779	$ 69,111	$ 493,191	$ 313,085
Oil and gas operations	57,933	47,456	177,898	139,947
Total operating revenues	161,712	116,567	671,089	453,032
Operating Expenses
Cost of gas	57,310	26,042	298,629	133,960
Operations and maintenance	46,471	42,540	138,185	126,404
Depreciation, depletion and amortization	21,335	24,210	61,825	66,947
Taxes, other than income taxes	13,267	10,617	52,685	36,805
Total operating expenses	138,383	103,409	551,324	364,116
Operating Income	23,329	13,158	119,765	88,916
Other Income (Expense)
Interest expense	(10,508)	(9,368)	(31,354)	(28,053)
Other, net	413	365	1,421	1,138
Total other expense	(10,095)	(9,003)	(29,933)	(26,915)
Income Before Income Taxes	13,234	4,155	89,832	62,001
Income tax (benefit) expense	2,861	(303)	18,748	7,241
Net Income	$ 10,373	$ 4,458	$ 71,084	$  54,760
Diluted Earnings Per Average Common Share	$ 0.33	$      0.15	$ 2.29	$      1.81
Basic Earnings Per Average Common Share	$ 0.34	$      0.15	$ 2.32	$      1.82
Dividends Per Common Share	$ 0.17	$    0.165	$ 0.51	$   0.495
Diluted Average Common Shares Outstanding	31,217	30,346	31,005	30,315
Basic Average Common Shares Outstanding	30,830	30,081	30,651	30,081

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

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
	June 30, 2001	September 30, 2000
(in thousands)	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$       3,883	$       3,823
Accounts receivable, net of allowance for doubtful     accounts of $8,829 at June 30, 2001, and     $6,681 at September 30, 2000	96,624	93,362
Inventories, at average cost
Storage gas inventory	51,218	36,437
Materials and supplies	11,133	8,535
Liquified natural gas in storage	3,059	3,267
Deferred gas costs	3,567	3,556
Amounts due from customers	15,937	-
Deferred income taxes	17,015	17,830
Prepayments and other	7,606	88,626
Total current assets	210,042	255,436
Property, Plant and Equipment
Oil and gas properties, successful efforts method	792,228	713,766
Less accumulated depreciation, depletion and amortization	197,814	165,447
Oil and gas properties, net	594,414	548,319
Utility plant	741,160	709,004
Less accumulated depreciation	371,641	353,997
Utility plant, net	369,519	355,007
Other property, net	4,623	4,503
Total property, plant and equipment, net	968,556	907,829
Other Assets
Deferred income taxes	13,852	22,782
Deferred charges and other	19,066	16,994
Total other assets	32,918	39,776
TOTAL ASSETS	$   1,211,516	$   1,203,041

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

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
	June 30, 2001	September 30, 2000
(in thousands, except share data)	(Unaudited)
CAPITAL AND LIABILITIES
Current Liabilities
Long-term debt due within one year	$      13,072	$      18,648
Notes payable to banks	55,000	168,000
Accounts payable	59,758	133,005
Accrued taxes	37,242	25,312
Customers' deposits	15,572	15,512
Amounts due customers	4,187	14,914
Accrued wages and benefits	25,611	24,256
Other	36,342	37,702
Total current liabilities	246,784	437,349
Deferred Credits and Other Liabilities
Other	3,622	10,900
Total deferred credits and other liabilities	3,622	10,900
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,      30,993,360 shares outstanding at June 30, 2001, and      30,350,802 shares outstanding at September 30, 2000	310	304
Premium on capital stock	230,046	213,582
Capital surplus	2,802	2,802
Retained earnings	240,970	185,561
Accumulated other comprehensive income, net of tax	5,338	-
Deferred compensation on restricted stock	(1,345)	-
Deferred compensation plan	6,276	4,965
Treasury stock, at cost (262,876 shares at June 30, 2001,     and 239,306 shares at September 30, 2000)	(7,374)	(6,354)
Total common shareholders' equity	477,023	400,860
Long-term debt	484,087	353,932
Total capitalization	961,110	754,792
TOTAL CAPITAL AND LIABILITIES	$   1,211,516	$   1,203,041

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Nine months ended June 30, (in thousands)	2001	2000
Operating Activities
Net income	$    71,084	$    54,760
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization	61,825	66,947
Deferred income taxes	5,470	(9,173)
Deferred investment tax credits	(336)	(336)
Gain on sale of assets	(759)	(1,472)
Net change in:
Accounts receivable	(3,262)	(19,869)
Inventories	(17,171)	(6,567)
Deferred gas costs	(11)	(1,163)
Accounts payable	9,721	(1,169)
Other current assets and liabilities	(12,377)	2,108
Other, net	(5,463)	(5,309)
Net cash provided by operating activities	108,721	78,757
Investing Activities
Additions to property, plant and equipment	(127,404)	(81,614)
Proceeds from sale of assets	7,926	2,600
Other, net	(825)	(807)
Net cash used in investing activities	(120,303)	(79,821)
Financing Activities
Payment of dividends on common stock	(15,676)	(14,896)
Issuance of common stock	17,859	6,664
Purchase of treasury stock	(1,098)	(3,231)
Reduction of long-term debt	(24,267)	(1,147)
Proceeds from issuance of long-term debt	147,824	-
Payment of note payable issued to purchase U.S. Treasury securities	-	(140,917)
Net change in short-term debt	(113,000)	19,917
Net cash provided by (used in) financing activities	11,642	(133,610)
Net change in cash and cash equivalents	60	(134,674)
Cash and cash equivalents at beginning of period	3,823	145,390
Cash and Cash Equivalents at End of Period	$     3,883	$     10,716

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

STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
		Three months ended			Nine months ended
		June 30,			June 30,
(in thousands)	2001		2000	2001		2000

Operating Revenues	$ 103,779	$ 69,111	$ 493,191	$ 313,085
Operating Expenses
Cost of gas	57,907	26,439	300,319	135,190
Operations and maintenance	27,204	26,236	80,692	77,131
Depreciation	7,825	7,243	23,026	21,380
Income taxes
Current	648	1,207	18,187	21,946
Deferred, net	(365)	(743)	(889)	(3,869)
Deferred investment tax credits, net	(112)	(112)	(336)	(336)
Taxes, other than income taxes	7,486	5,906	32,332	23,535
Total operating expenses	100,593	66,176	453,331	274,977
Operating Income	3,186	2,935	39,860	38,108
Other Income (Expense)
Allowance for funds used during construction	591	365	1,617	681
Other, net	(161)	262	(468)	365
Total other income	430	627	1,149	1,046
Interest Charges
Interest on long-term debt	2,066	2,135	6,256	6,406
Other interest expense	972	311	2,802	957
Total interest charges	3,038	2,446	9,058	7,363
Net Income	$ 578	$ 1,116	$ 31,951	$ 31,791

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

BALANCE SHEETS
ALABAMA GAS CORPORATION
	June 30, 2001	September 30, 2000
(in thousands)	(Unaudited)
ASSETS
Property, Plant and Equipment
Utility plant	$     741,160	$     709,004
Less accumulated depreciation	371,641	353,997
Utility plant, net	369,519	355,007
Other property, net	220	241
Current Assets
Cash and cash equivalents	685	866
Accounts receivable
Gas	58,330	48,300
Merchandise	1,801	2,192
Other	1,111	1,472
Allowance for doubtful accounts	(8,300)	(5,800)
Inventories, at average cost
Storage gas inventory	51,218	36,437
Materials and supplies	5,441	5,400
Liquified natural gas in storage	3,059	3,267
Deferred gas costs	3,567	3,556
Amounts due from customers	15,937	-
Deferred income taxes	12,311	12,360
Prepayments and other	1,297	3,438
Total current assets	146,457	111,488
Deferred Charges and Other Assets	4,390	4,546
TOTAL ASSETS	$   520,586	$   471,282

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

BALANCE SHEETS
ALABAMA GAS CORPORATION
	June 30, 2001	September 30, 2000
(in thousands, except share data)	(Unaudited)
CAPITAL AND LIABILITIES
Capitalization
Common shareholder's equity
Common stock, $0.01 par value; 3,000,000 shares         authorized, 1,972,052 shares outstanding at         June 30, 2001, and September 30, 2000	$           20	$          20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	186,245	164,767
Total common shareholder's equity	220,749	199,271
Cumulative preferred stock, $0.01 par value, 120,000 shares     authorized, issuable in series-$4.70 Series	-	-
Long-term debt	115,000	115,000
Total capitalization	335,749	314,271
Current Liabilities
Long-term debt due within one year	-	4,650
Notes payable to banks	45,000	20,500
Accounts payable	46,479	40,532
Accrued taxes	35,271	21,621
Customers' deposits	15,572	15,512
Amounts due customers	4,187	14,914
Accrued wages and benefits	12,392	9,221
Other	7,596	10,230
Total current liabilities	166,497	137,180
Deferred Credits and Other Liabilities
Deferred income taxes	15,862	15,938
Accumulated deferred investment tax credits	1,429	1,765
Regulatory liability	304	1,352
Customer advances for construction and other	745	776
Total deferred credits and other liabilities	18,340	19,831
Commitments and Contingencies
TOTAL CAPITAL AND LIABILITIES	$   520,586	$   471,282

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

STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Nine months ended June 30, (in thousands)	2001	2000
Operating Activities
Net income	$      31,951	$      31,791
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation	23,026	21,380
Deferred income taxes, net	(889)	(3,869)
Deferred investment tax credits	(336)	(336)
Net change in:
Accounts receivable	(6,778)	(18,913)
Inventories	(14,614)	(6,208)
Deferred gas costs	(11)	(1,163)
Accounts payable	(5,034)	8,916
Other current assets and liabilities	(10,134)	4,547
Other, net	(1,821)	(1,077)
Net cash provided by operating activities	15,360	35,068
Investing Activities
Additions to property, plant and equipment	(35,780)	(40,018)
Other, net	(120)	18
Net cash used in investing activities	(35,900)	(40,000)
Financing Activities
Reduction of long-term debt	(4,650)	-
Net advances from affiliates	10,981	8,262
Dividends	(10,472)	-
Net change in short-term debt	24,500	-
Net cash provided by financing activities	20,359	8,262
Net change in cash and cash equivalents	(181)	3,330
Cash and cash equivalents at beginning of period	866	533
Cash and Cash Equivalents at End of Period	$    685	$     3,863

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

NOTES TO UNAUDITED FINANCIAL STATEMENTS

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

1. BASIS OF PRESENTATION

All 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. The unaudited financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended September 30, 2000, 1999, and 1998, included in the 2000 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Certain reclassifications were made to conform prior years' financial statements to the current-quarter presentation. 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 fiscal year.

2. REGULATORY

As an Alabama utility, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC) which, in 1983, established the Rate Stabilization and Equalization (RSE) rate-setting process. RSE was extended with modifications in 1990, 1987 and 1985. On October 7, 1996, RSE was extended, without change through January 1, 2002. Under the terms of that extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation. Under RSE as extended, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and fiscal year-to-date performance, whether Alagasco's return on average equity for the fiscal 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 fiscal year, effective December 1, and cannot ex ceed 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. If the change in O&M expense per customer falls within 1.25 percentage points above or below the Consumer Price Index For All Urban Customers (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. Under RSE as extended, a $9.1 million and a $4.5 million annual increase in revenues became effective December 1, 2000 and 1999, respectively.

Alagasco calculates a temperature adjustment to customers' bills to remove the effect of departures from normal temperatures on Alagasco's earnings. The calculation is performed monthly, and the adjustments to customers' bills are made in the same billing cycle in which the weather variation occurs. Substantially all the customers to whom the temperature adjustment applies are residential, small commercial and small industrial. Alagasco's rate schedules for natural gas distribution charges contain a Gas Supply Adjustment 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 fiscal year 1998, 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 fiscal year; or (2) individual industrial and commercial customer revenue losses that exceed $250,000 during the fiscal year, if such losses cause Alagasco's return on equity to fall below 13.15 percent. The APSC approved the establishment of the ESR in the amount of $3.9 million; the maximum approved funding level is $4 million. Following a year in which a charge against theESR is made, the APSC provides for accretions to the ESR of no more than $40,000 monthly until the maximum funding level is achieved.

In accordance with APSC-directed regulatory accounting procedures, Alagasco in 1989 began returning to customers excess utility deferred taxes which resulted from a reduction in the federal statutory tax rate from 46 percent to 34 percent using the average rate assumption method. This method provides for the return to ratepayers of excess deferred taxes over the lives of the related assets. In 1993 those excess taxes were reduced as a result of a federal tax rate increase from 34 percent to 35 percent. Remaining excess utility deferred taxes are being returned to ratepayers over approximately 10 years. At June 30, 2001, and September 30, 2000, a regulatory liability related to income taxes of $0.3 million and $1.4 million, respectively, was included in the consolidated financial statements.

As of November 1, 1998, Alagasco offered a Voluntary Early Retirement Program to certain eligible employees. The APSC allowed these costs to be amortized over a three-year period. As of June 30, 2001, and September 30, 2000, a regulatory asset of $0.4 million and $1.2 million, respectively, was included in the consolidated financial statements for costs associated with this early retirement program.

3. DERIVATIVE COMMODITY INSTRUMENTS

The Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (subsequently amended by SFAS Nos. 137 and 138), Accounting for Derivative Instruments and Hedging Activities, on October 1, 2000. This statement 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 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 recorde d 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 to hedge its exposure to price fluctuations on oil and gas 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 and basis hedges with major energy derivative product specialists. The Company has identified certain oil and gas derivatives which qualify as cash flow hedges under SFAS No. 133.

As of June 30, 2001, $2.6 million, net of tax, of deferred net gains 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 hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. The Company recorded an after-tax gain of $180,000 for the three-months ended June 30, 2001, and a $2.5 million after-tax loss year-to-date for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, Energen Resources recorded an after-tax gain of $146,000 for the quarter and a $0.5 million after-tax gain year-to-date on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of June 30, 2001, the Compan y had 141 MBbl of oil swaps at an average NYMEX price of $28.60 per barrel that did not meet the definition of a cash flow hedge. These derivative instruments are considered by management to be solid economic hedges with any related volatility of interim financial results due to technical compliance with SFAS No. 133. The Company expects to have physical sales to offset these gains or losses during the 2001 fiscal year. As of June 30, 2001, the Company had $3.4 million included in deferred income taxes on the consolidated balance sheet related to other comprehensive income.

As of June 30, 2001, Energen Resources had entered into contracts and swaps for 9.1 Bcf of its remaining fiscal year 2001 gas production at an average NYMEX price of $2.77 per Mcf and 280 MBbl of its oil production at an average NYMEX price of $28.91 per barrel. Energen Resources also had basin-specific hedges in place for 150 MBbl of oil at an average contract price of $23.53 per barrel. In addition, the Company had hedged the basis difference on 6.1 Bcf of its remaining fiscal year 2001 gas production. Realized prices are anticipated to be lower than NYMEX prices due to basis difference and other factors.

For fiscal 2002, Energen Resources had entered into swaps for 9.3 Bcf of its gas production at an average NYMEX price of $3.84 per Mcf and had basin-specific hedges in place for 3.6 Bcf of gas production at an average contract price of $4.30 per Mcf. Energen Resources also had 0.8 Bcf of gas production hedged at a collar price of $4.25 to $6.15 per Mcf. In addition, the Company had hedged the basis difference on 6 Bcf of its fiscal 2002 gas production. Subsequent to June 30, 2001, Energen Resources entered into additional swaps for fiscal year 2002, resulting in a total of 100 MBbl of its oil production at an average NYMEX price of $27.05 per barrel. Production estimates for fiscal year 2002 total 76.4 Bcfe, including 51 Bcf of gas, 2.6 MMBbl of oil and 1.6 MMBbl of natural gas liquids. These estimates include 4.4 Bcfe of production from anticipated acquisitions and exploration activity.

As of June 30, 2001, Energen Resources had entered into basin-specific swaps for 1.9 Bcf of its gas production at an average contract price of $3.77 per Mcf for fiscal year 2003. For fiscal 2004 and 2005, Energen Resources had entered into swaps for 1.8 Bcf and 1.6 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively.

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 is not determined to be highly effective as a hedge or it has ceased to be a highly effective hedge. The maximum term over which Energen Resources is hedging exposures to the variability of cash flows is through September 30, 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 of June 30, 2001, Alagasco had no outstanding derivative instruments.

4. ACCOUNTING FOR LONG-LIVED ASSETS

SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of, requires that an impairment loss be recognized when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flow of the asset. The Statement also provides that all long-lived assets to be disposed of be reported at the lower of the carrying amount or fair value. Accordingly, during the third quarter of fiscal 2000, Energen Resources recorded a pre-tax writedown of $3.5 million as additional depreciation, depletion and amortization expense as a result of a downward reserve revision in a small oil and gas field, adjusting the carrying amount of the properties to their fair value based upon expected future discounted cash flows.

5. RECENT PRONOUNCEMENTS OF THE FASB

In June 2001, the FASB issued SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires business combinations to be accounted for using the purchase method for all combinations initiated subsequent to June 30, 2001. SFAS No. 142 requires that goodwill and other intangible assets no longer be amortized and be tested for impairment annually. The consolidated financial statements do not include existing goodwill or other intangible assets. The Company is required to adopt this statement for goodwill and intangible assets acquired after June 30, 2001.

In July 2001, the FASB approved issuance of SFAS No. 143, Accounting for Asset Retirement Obligations. SFAS No. 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. This standard is effective for fiscal years beginning after June 15, 2002. The impact of this pronouncement on the Company currently is being evaluated and is not expected to be material.

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		Nine months ended
	June 30,		June 30,
(in thousands)	2001	2000	2001	2000
Operating revenues
Natural gas distribution	$ 103,779	$ 69,111	$ 493,191	$ 313,085
Oil and gas operations	57,933	47,456	177,898	139,947
Total	$ 161,712	$ 116,567	$ 671,089	$ 453,032
Operating income (loss)
Natural gas distribution	$ 3,357	$ 3,287	$ 56,822	$ 55,849
Oil and gas operations	20,381	10,469	64,163	34,279
Eliminations and corporate expenses	(409)	(598)	(1,220)	(1,212)
Total	$ 23,329	$ 13,158	$ 119,765	$ 88,916

(in thousands)	June 30, 2001	September 30, 2000
Identifiable assets
Natural gas distribution	$ 520,586		$ 471,282
Oil and gas operations	694,599		738,424
Eliminations and other	(3,669)		(6,665)
Total	$ 1,211,516		$ 1,203,041

7. RECONCILIATION OF EARNINGS PER SHARE

		Three months ended				Three months ended
(in thousands, except per share amounts)		June 30, 2001				June 30, 2000
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount
Basic EPS	$  10,373		30,830	$  0.34	$  4,458		30,081	$  0.15
Effect of Dilutive Securities
Long-range performance shares			148				134
Stock options			229				118
Restricted stock			10				13
Diluted EPS	$  10,373		31,217	$  0.33	$  4,458		30,346	$  0.15

		Nine months ended				Nine months ended
(in thousands, except per share amounts)		June 30, 2001				June 30, 2000
				Per Share				Per Share
	Income		Shares	Amount	Income		Shares	Amount
Basic EPS	$  71,084		30,651	$  2.32	$  54,760		30,081	$  1.82
Effect of Dilutive Securities
Long-range performance shares			142				129
Stock options			205				92
Restricted stock			7				13
Diluted EPS	$  71,084		31,005	$  2.29	$  54,760		30,315	$  1.81

8. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) consisted of the following:

	Three months ended	Nine months ended
(in thousands)	June 30, 2001	June 30, 2001
Net Income	$    10,373	$    71,084
Other comprehensive income
Unrealized gain on cash flow hedges, net of tax of $23.7 million and $3.4 million, respectively	36,996	5,338
Comprehensive Income	$   47,369	$    76,422

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

	Accumulated Other
(in thousands)	Comprehensive Income (Loss)
Balance September 30, 2000	$            -
Transition adjustment on cash flow hedging activities, net of tax of $35.4 million	(55,416)
Current period change in fair value of derivative instruments, net of tax of $5.4 million	8,512
Reclassification adjustment, net of tax of $33.4 million	52,242
Balance June 30, 2001	$    5,338

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

RESULTS OF OPERATIONS

Energen's net income totaled $10.4 million ($0.33 per diluted share) for the three months ended June 30, 2001, and compared favorably to net income of $4.5 million ($0.15 per diluted share) recorded in the same period last year. Energen Resources Corporation, Energen's oil and gas subsidiary, realized net income of $10 million in the current fiscal quarter as compared with $3.8 million in the same period last year primarily as a result of significantly higher realized commodity prices partially offset by increased lease operating expense. Prior-period earnings included a $2.2 million after-tax writedown under Statement of Financial Account Standards (SFAS) No. 121. Energen's natural gas utility, Alagasco, reported net income of $0.6 million in the third quarter of 2001 as compared to $1.1 million in the same period last year. Negatively affecting the utility's third quarter results was increased bad debt expense as a result of significantly colder weather and higher natural gas prices duri ng the past winter as well as a decline in industrial gas usage due to an economic slow-down.

For the 2001 fiscal year-to-date, Energen's net income totaled $71.1 million ($2.29 per diluted share) compared with $54.8 million ($1.81 per diluted share) for the same period in the prior year. Energen Resources' net income increased significantly during the current period totaling $39.6 million compared with $23.5 million of net income for the first nine months of fiscal 2000. The major factors influencing the year-to-date for Energen Resources were the same as those for the quarter. Alagasco's earnings of $32 million in the current year-to-date remained stable with net income of $31.8 million from the same period in the previous year. This is a result of the utility's ability to earn on an increased level of equity representing investment in utility plant offset by the same factors influencing the third fiscal quarter.

Natural Gas Distribution

Natural gas distribution revenues increased $34.7 million for the quarter and $180.1 million on a year-to-date basis largely due to an increase in the commodity cost of gas as well as to an increase in weather-related sales volumes. Natural gas commodity purchase costs increased 35.8 percent and 136.7 percent for the quarter and year-to-date, respectively. For the quarter, weather that was 40.1 percent colder than the same period last year contributed to a 16.8 percent increase in residential sales volumes and a 12.7 percent increase in small commercial and industrial customer sales volumes. Transportation volumes decreased 29.3 percent primarily due to the prior-year closing of a steel manufacturing plant and reduced consumption resulting from an economic downturn during the current period. For the year-to-date, weather that was 29.9 percent colder than the same period last year contributed to a 21 percent increase in residential sales volumes and a 19 percent increase in small commer cial and industrial customer sales volumes. For the same reasons that influenced the quarter, in addition to price related alternate fuel use, large transportation customers had a 24.3 percent decrease in throughput. Higher commodity gas prices along with increased gas purchase volumes contributed to a 119 percent increase in cost of gas for the quarter and a 122.1 percent increase year-to-date. The GSA rider in Alagasco's rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco calculates a temperature adjustment to certain customers' bills on a real-time basis to substantially remove the effect of departures from normal temperatures. The customers to whom the temperature adjustment applies primarily are residential, small commercial and small industrial.

As discussed more fully in Note 2, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On October 7, 1996, the APSC issued an order extending the Company's current rate-setting mechanism through January 1, 2002. Under the terms of that extension, RSE will continue after January 1, 2002, unless, after notice to the Company and a hearing, the Commission votes to either modify or discontinue its operation.

Operations and maintenance (O&M) expense increased 3.7 percent in the current quarter and 4.6 percent for the year-to-date primarily due to increased bad debt expense, additional weather-related distribution system operating costs and higher insurance costs largely offset by reduced marketing costs. A slight increase in depreciation expense in the current quarter and year-to-date primarily was due to normal growth of the utility's 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.

Oil and Gas Operations

Revenues from oil and gas operations rose 22.1 percent to $57.9 million for the three months ended June 30, 2001, and 27.1 percent to $177.9 million for the year-to-date largely as a result of significantly higher commodity prices. In the third fiscal quarter, realized gas prices increased 25.2 percent to $3.23 per Mcf, while realized oil prices rose 20.9 percent to $24.43 per barrel. Natural gas liquids prices increased 6 percent to an average price of $16.79 per barrel. For the year-to-date, realized gas prices increased 33.2 percent to $3.25 per Mcf, realized oil prices increased 33.8 percent to $23.48 per barrel and natural gas liquids prices increased 27.9 percent to an average price of $19.52 per barrel.

Natural gas production in the third quarter decreased slightly to 11.4 Bcf, while oil volumes increased 7.8 percent to 567 MBbl and natural gas liquids increased 9.9 percent to 376 MBbl. For the year-to-date, natural gas production decreased 5 percent to 34.8 Bcf and oil volumes decreased 6.5 percent to 1,616 MBbl due to normal production declines and certain property acquisition/swap adjustments. Natural gas liquids production increased 3.3 percent to 1,070 MBbl. Natural gas comprised approximately 70 percent of Energen Resources' production for the current quarter and the year-to-date.

Energen Resources enters into derivative commodity instruments to hedge its exposure to the impact of price fluctuations on oil and gas 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 and basis hedges with major energy derivative product specialists. All hedge transactions are subject to the Company's risk management policy, approved by the Board of Directors, which does not permit speculative positions. As of June 30, 2001, Energen Resources had entered into contracts and swaps for 9.1 Bcf of its remaining fiscal year 2001 gas production at an average NYMEX price of $2.77 per Mcf and 280 MBbl of its oil production at an average NYMEX price of $28.91 per barrel. Energen Resources also had basin-specific hedges in place for 150 MBbl of oil at an average contract price of $23.53 per barrel. In addition, the Company had hedged the basis difference on 6.1 Bcf of its remain ing fiscal year 2001 gas production. Realized prices are anticipated to be lower than NYMEX prices due to basis difference and other factors.

For fiscal 2002, Energen Resources had entered into swaps for 9.3 Bcf of its gas production at an average NYMEX price of $3.84 per Mcf and had basin-specific hedges in place for 3.6 Bcf of gas production at an average contract price of $4.30 per Mcf. Energen Resources also had 0.8 Bcf of gas production hedged at a collar price of $4.25 to $6.15 per Mcf. In addition, the Company had hedged the basis difference on 6 Bcf of its fiscal 2002 gas production. Subsequent to June 30, 2001, Energen Resources entered into additional swaps for fiscal year 2002, resulting in a total of 100 MBbl of its oil production at an average NYMEX price of $27.05 per barrel. Production estimates for fiscal year 2002 total 76.4 Bcfe, including 51 Bcf of gas, 2.6 MMBbl of oil and 1.6 MMBbl of natural gas liquids. These estimates include 4.4 Bcfe of production from anticipated acquisitions and exploration activity.

As of June 30, 2001, Energen Resources had entered into basin-specific swaps for 1.9 Bcf of its gas production at an average contract price of $3.77 per Mcf for fiscal year 2003. For fiscal 2004 and 2005, Energen Resources had entered into swaps for 1.8 Bcf and 1.6 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively.

In addition to the derivatives described above, the Company has three-way pricing, physical sales contracts in place for 13.4 Bcf of its estimated gas production in fiscal year 2002. These contracts provide for Energen Resources to receive a basin-specific weighted average price between $2.82 and $3.94 per Mcf. If the market price falls between $2.40 and $2.82 per Mcf, Energen Resources will receive $2.82 per Mcf. If the market price falls below $2.40 per Mcf, Energen Resources will receive the market price plus a premium of $0.33-$0.45, depending on the contracts. In fiscal year 2003, the Company has three-way pricing, physical sales contracts in place for 11.9 Bcf of its estimated gas production. These contracts provide for Energen Resources to receive a basin-specific weighted average price between $2.72 and $3.94 per Mcf. If the market price falls between $2.40 and $2.72 per Mcf, Energen Resources will receive $2.72 per Mcf. If the market price falls below $2.40 per Mcf, Energen Resour ces will receive the market price plus a premium of $0.23-$0.35, depending on the contracts.

Energen Resources, in the ordinary course of business, may be involved in the sale of developed and undeveloped non-strategic properties. Gains or losses on the sale of such properties are included in operating revenues. Energen Resources recorded a pre-tax loss of $143,000 for the current fiscal quarter as compared to a pre-tax gain of $743,000 in the prior fiscal quarter on the sale of various properties. Year-to-date, property sales resulted in a pre-tax gain of $716,000 as compared to a pre-tax gain of $1.5 million in the same period last year.

O&M expense increased $3.1 million for the quarter and $8.2 million for the year-to-date. Lease operating expenses increased by $2.6 million for the quarter and $8.7 million for the year-to-date primarily due to higher operational costs. Exploration expense increased by $564,000 due to timing for the quarter but was lower by $726,000 for the year-to-date primarily due to decreased exploratory efforts.

Energen Resources' depreciation, depletion and amortization (DD&A) expense for the quarter declined $3.5 million primarily due to a SFAS No. 121 pre-tax writedown of $3.5 million recorded in the third quarter of the prior year. For the year-to-date, DD&A expense decreased $6.8 million primarily due to the writedown in the previous third quarter, an increase in the reserve base driven by higher commodity prices as well as decreased production as compared to the prior year. Excluding the effect of the prior year writedown, the average depletion rate for the third quarter was $0.77 as compared to $0.79 for the same period last year and for the year-to-date was $0.72 as compared to $0.78 in the prior fiscal period.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $1.4 million higher this quarter and $7.4 million higher for the year-to-date primarily as a result of the significantly increased market prices of natural gas, oil and natural gas liquids.

Non-Operating Items

Interest expense for the Company increased $1.1 million in the quarter and $3.3 million year-to-date. Influencing the increase in interest expense for the current quarter and year-to-date is $150 million of medium-term notes (MTNs) issued in December 2000 to repay borrowings under Energen's short-term credit facilities incurred with the growth at Energen Resources. The increase in short-term debt at Alagasco also contributed to the increase in interest expense for both the quarter and year-to-date.

The Company's effective tax rates are lower than statutory federal tax rates primarily due to the recognition of nonconventional fuels tax credits and the amortization of investment tax credits. Nonconventional fuels tax credits are generated annually on qualified production through December 31, 2002, and are expected to be recognized fully in the financial statements.

Income tax expense increased in quarter comparisons primarily as a result of higher consolidated pre-tax income. In year-to-date comparisons, income tax expense increased as a result of higher consolidated pre-tax income and lower nonconventional fuels tax credits of $2.3 million largely due to the timing of the credit recognition on an interim basis. The estimated effective tax rate utilized in computing year-to-date income tax expense reflects an expected financial recognition of $13.5 million of nonconventional fuels tax credits for fiscal year 2001.

FINANCIAL POSITION AND LIQUIDITY

Cash flow from operations for the current year-to-date was $108.7 million compared to $78.8 million in the same period in the prior year. Operating cash flow in the current year-to-date benefited from significantly higher realized oil, gas and natural gas liquids prices at Energen Resources. Changes in working capital items, which were highly influenced by throughput, colder-than-normal weather, increased gas costs and timing of payments, combined to create the remaining changes.

The Company had a net investment of $120.3 million through the nine months ended June 30, 2001, primarily in additions of property, plant and equipment. Energen Resources invested $91.6 million in capital expenditures year-to-date in the acquisition and development of oil and gas properties, including $30.4 million for a property acquisition in the Permian Basin during the second fiscal quarter of 2001. Utility capital expenditures totaled $37.6 million year-to-date and represented system distribution expansion and support facilities. The Company had cash proceeds of $7.9 million resulting from the sale of certain properties during the fiscal year-to-date.

The Company's financing activities provided $11.6 million year-to-date in net cash flows. In December 2000, the Company issued $150 million of long-term debt redeemable December 15, 2010. The 7.625 percent MTNs were priced at 99.199 percent to yield 7.742 percent. The $147.8 million in proceeds were used to repay borrowings under Energen's short-term credit facilities incurred to finance Energen Resources' acquisition strategy.

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 and exploitation of producing properties with development potential while building on the strength of the Company's utility foundation. The primary objective of this strategy, implemented beginning with fiscal year 1996, is to realize average compound EPS growth of 10 percent a year over each rolling five-year period. In the first five fiscal years under this strategy, Energen's EPS grew at an average compound rate of 14.7 percent a year.

To finance Energen Resources' investment program, the Company will continue to utilize its short-term credit facilities to supplement internally generated cash flow, with long-term debt providing permanent financing. In December 2000, the Company issued $150 million of Series B MTNs, the proceeds from which were used to repay short-term debt. Energen has available short-term credit facilities of $250 million to help accommodate its growth plans. Energen's management plans to utilize commodity price-driven increases in cash flows to help finance Energen Resources' acquisition and exploitation strategy and to help reduce Energen's debt-to-total capitalization ratio to 50 percent over the next five years.

In fiscal year 2001, Energen Resources plans to invest approximately $130 million in capital expenditures, including $30.4 million for the property acquisition in the Permian Basin and $96 million in exploitation activities. Energen Resources' exploratory exposure in fiscal 2001 is estimated to be $2 million. Capital investment at Energen Resources in fiscal year 2002 is expected to approximate $175 million for acquisitions, $55 million for exploitation and $10 million for exploration and related development. Energen Resources' capital investment for oil and gas activities over the five-year period ending September 30, 2005, is estimated to range from $950 million to $1 billion. During this period, the Company expects to issue approximately $100 million in additional long-term debt to replace short-term obligations and provide permanent financing for Energen Resources' acquisition strategy. Energen Resources' continued ability to invest in property acquisitions will be influenced significa ntly by industry trends, as the producing property acquisition market historically has been cyclical. From time to time, Energen Resources also may be engaged in negotiations to sell, trade or otherwise dispose of properties.

During fiscal year 2001, Alagasco plans to invest approximately $57 million in utility capital expenditures for normal distribution and support systems including approximately $20 million for revenue-producing facilities and $3 million for remaining replacement costs of its liquifaction equipment. Alagasco also maintains an investment in storage gas which is expected to average approximately $40 million in 2001. During the last fiscal quarter of 2001, Alagasco plans to issue $75 million of long-term debt to replace short-term financing and supplement internally generated cash flow. Alagasco plans to invest approximately $58 million in utility capital expenditures during fiscal year 2002. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. Over the Company's five-year planning period ending September 30, 2005, Alagasco anticipates capital investments of approximately $265 million.

The Company expects earnings will range from $2.25 to $2.30 per diluted share in fiscal year 2001. This estimate includes the Company's expectation that Alagasco's earnings will fall below earlier projections due primarily to increased weather-related bad debt expense and reduced consumption by LC&I customers related to alternate fuel use and an economic slowdown. For fiscal year 2001, management expects Alagasco to earn a 12.4 percent return on average equity of approximately $212 million. The Company's earnings estimates for the remainder of fiscal year 2001 also are based on assumptions that Energen Resources' unhedged gas production will receive an average NYMEX price of $3 per Mcf and that its unhedged oil production will receive an average NYMEX price of $26 per barrel. The price for natural gas liquids is assumed to average $17.60 per barrel.

The Company's hedge position for fiscal 2002 will help minimize the earnings impact of weaker natural gas commodity costs. The Company's earnings estimates for fiscal year 2002 of $2.45 to $2.55 per diluted share are based on assumptions that Energen Resources' unhedged gas production will receive an average NYMEX price of $3.50 per Mcf and that its unhedged oil production will receive an average NYMEX price of $25 per barrel. The price for natural gas liquids is assumed to average $16.88 per barrel. In fiscal year 2002, Energen Resources estimates that a $1 per barrel change in oil prices from the $25 per barrel assumption, together with a corresponding change in the price of natural gas liquids, will have an approximate $2 million effect on net income. Similarly, a 10-cents per Mcf change in gas prices from the $3.50 per Mcf assumption, up to $4 per Mcf, is estimated to have a $1.75 million effect on net income, while a 10-cents per Mcf change on gas prices above $4 per Mcf will have a $ 1 million effect on net income for fiscal year 2002. Alagasco expects to earn a 13.4 percent return on average equity in fiscal year 2002.

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. We undertake 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 affect materially the Com pany's financial position and results of operation; 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. In addition, the Company cannot guarantee the absence of errors in input data, calculations and formulas used in its estimates, assumptions and forecasts.

SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
	Three months ended			Nine months ended
	June 30,			June 30,
(in thousands, except sales price data)		2001	2000		2001	2000
Natural Gas Distribution
Operating revenues
Residential		$ 66,933	$ 42,684		$ 333,866	$ 205,540
Commercial and industrial - small		28,403	16,560		129,939	74,629
Transportation		7,460	8,245		26,190	28,302
Other		983	1,622		3,196	4,614
Total		$ 103,779	$ 69,111		$ 493,191	$ 313,085
Gas delivery volumes (MMcf)
Residential		4,975	4,261		29,080	24,028
Commercial and industrial - small		2,516	2,232		12,530	10,531
Transportation		12,837	18,145		39,749	52,493
Total		20,328	24,638		81,359	87,052
Other data
Depreciation and amortization		$ 7,825	$ 7,243		$ 23,026	$ 21,380
Capital expenditures		$ 13,363	$ 16,267		$ 37,604	$ 40,882
Operating income		$ 3,357	$ 3,287		$ 56,822	$ 55,849
Oil and Gas Operations
Operating revenues
Natural gas		$ 36,866	$ 29,764		$ 113,007	$ 89,332
Oil		13,841	10,639		37,953	30,356
Natural gas liquids		6,320	5,414		20,884	15,808
Other		906	1,639		6,054	4,451
Total		$ 57,933	$ 47,456		$ 177,898	$ 139,947
Sales Volumes
Natural gas (MMcf)		11,400	11,521		34,813	36,629
Oil (MBbl)		567	526		1,616	1,729
Natural gas liquids (MBbl)		376	342		1,070	1,036
Average sales price
Natural gas (Mcf)		$ 3.23	$ 2.58		$ 3.25	$ 2.44
Oil (barrel)		$ 24.43	$ 20.21		$ 23.48	$ 17.55
Natural gas liquids (barrel)		$ 16.79	$ 15.84		$ 19.52	$ 15.26
Other data
Depreciation, depletion and amortization		$ 13,510	$ 16,967		$ 38,799	$ 45,567
Capital expenditures		$ 25,765	$ 14,804		$ 91,566	$ 41,291
Exploration expenditures		$ 1,533	$ 969		$ 2,797	$ 3,523
Operating income		$ 20,381	$ 10,469		$ 64,163	$ 34,279

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.

The Company adopted Statement of Financial Accounting Standard (SFAS) No. 133 (subsequently amended by SFAS Nos. 137 and 138), Accounting for Derivative Instruments and Hedging Activities, on October 1, 2000. This statement 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 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 record ed 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 to hedge its exposure to price fluctuations on oil and gas 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 and basis hedges with major energy derivative product specialists. The Company has identified certain oil and gas derivatives which qualify as cash flow hedges under SFAS No. 133.

As of June 30, 2001, $2.6 million, net of tax, of deferred net gains 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 hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. The Company recorded an after-tax gain of $180,000 for the three-months ended June 30, 2001, and a $2.5 million after-tax loss year-to-date for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges. Also, Energen Resources recorded an after-tax gain of $146,000 for the quarter and a $0.5 million after-tax gain year-to-date on contracts which did not meet the definition of cash flow hedges under SFAS No. 133. As of June 30, 2001, the Company ha d 141 MBbl of oil swaps at an average NYMEX price of $28.60 per barrel that did not meet the definition of a cash flow hedge. These derivative instruments are considered by management to be solid economic hedges with any related volatility of interim financial results due to technical compliance with SFAS No. 133. The Company expects to have physical sales to offset these gains or losses during the 2001 fiscal year. As of June 30, 2001, the Company had $3.4 million included in deferred income taxes on the consolidated balance sheet related to other comprehensive income.

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 is not determined to be highly effective as a hedge or it has ceased to be a highly e ffective hedge. The maximum term over which Energen Resources is hedging exposures to the variability of cash flows is through September 30, 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 of June 30, 2001, Alagasco had no outstanding derivative instruments.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a. Exhibits

None

b. Reports on Form 8-K

No reports on Form 8-K were filed for the three months ended June 30, 2001.

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 10, 2001	By   /s/ Wm. Michael Warren, Jr.
	Wm. Michael Warren, Jr.
	Chairman, President and Chief Executive
	Officer of Energen, Chairman and Chief
	Executive Officer of Alabama Gas
	Corporation
August 10, 2001	By   /s/ G. C. Ketcham
	G. C. Ketcham
	Executive Vice President, Chief
	Financial Officer and Treasurer of
	Energen and Alabama Gas Corporation
August 10, 2001	By   /s/ Grace B. Carr
	Grace B. Carr
	Controller of Energen
August 10, 2001	By   /s/ Paula H. Rushing
	Paula H. Rushing
	Vice President-Finance of Alabama Gas
	Corporation

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