Spire Alabama 10-Q 2002 Q4 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 SEPTEMBER 30, 2002

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 XNO ____

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of October 11, 2002

Energen Corporation	$0.01 par value	34,634,508 shares
Alabama Gas Corporation	$0.01 par value	1,972,052 shares

INDUSTRY GLOSSARY For a more complete definition of certain terms defined below, please refer to Rule 4-10(a) of Regulation S-X, promulgated pursuant to the Securities Act of 1933 and the Securities Exchange Act of 1934, each as amended.
Basis	The difference between the futures price for a commodity and the corresponding cash spot price. The differential commonly is related to factors such as product quality, location and contract pricing.
Basin-specific	A type of derivative contract whereby the contract's settlement price is based on specific geographic basin indices.
Cash Flow Hedge	The designation of a derivative instrument to reduce the exposure to variability in cash flows from the forecasted sale of oil or gas production whereby the gains (losses) on the derivative transaction are anticipated to offset the losses (gains) on the forecasted sale.
Collar	A financial arrangement that effectively establishes a price range for the commodity. The producer only bears the risk of fluctuation between the minimum (or floor) price and the maximum (or ceiling) price.
Development Costs	The costs necessary to gain access to, prepare and equip wells drilled to produce proved oil and gas reserves following discovery.
Exploratory Well	A well drilled to a previously untested geologic structure to determine the presence of oil or gas.
Futures Contract	An exchange-traded legal contract to buy or sell a standard quantity and quality of a commodity at a specified future date and price. Such contracts offer liquidity and minimal credit risk exposure but lack the flexibility of swap contracts.
Hedging	The use of derivative commodity instruments such as futures, swaps and collars to help reduce financial exposure to commodity price volatility.
Liquified Natural Gas (LNG)	Natural gas that is liquified by reducing the temperature to 260 degrees Fahrenheit. LNG typically is used to supplement traditional natural gas supplies during periods of peak demand.
Natural Gas Liquids (NGL)	Liquid hydrocarbons that are extracted and separated from the natural gas stream. NGL products include ethane, propane, butane, natural gasoline and other hydrocarbons.
Proved Developed Reserves	The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves	Estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves	The portion of proved reserves which can be expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.
Reserve to Production Ratio	Ratio determined by dividing the remaining recoverable reserves by estimated annual production volumes expressed in years of supply.
Swap	A contractual arrangement in which two parties, called counterparties, effectively agree to exchange or "swap" variable and fixed rate payment streams based on a specified commodity volume. The contracts allow for flexible terms such as specific quantities, settlement dates and location but also expose the parties to counterparty credit risk.
Throughput	Total volumes of natural gas sold or transported.
ENERGEN CORPORATION AND ALABAMA GAS CORPORATION
FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2002
TABLE OF CONTENTS
		Page
PART I: FINANCIAL INFORMATION
Item 1.	Financial Statements
	(a) Consolidated Statements of Income of Energen Corporation	1
	(b) Consolidated Balance Sheets of Energen Corporation	2
	(c) Consolidated Statements of Cash Flows of Energen Corporation	4
	(d) Statements of Income of Alabama Gas Corporation	5
	(e) Balance Sheets of Alabama Gas Corporation	6
	(f) Statements of Cash Flows of Alabama Gas Corporation	8
	(g) Notes to Unaudited Financial Statements	9
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
Item 4.	Controls and Procedures.................................................................................	23
	PART II: OTHER INFORMATION
Item 6.	Exhibits and Reports on Form 8-K	24
SIGNATURES		25
CERTIFICATIONS		26

PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
CONSOLIDATED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
	Three months ended		Nine months ended
	September 30,		September 30,
(in thousands, except per share data)	2002	2001		2002	2001
Operating Revenues
Oil and gas operations	$  66,727	$  51,382	$ 177,341		$ 168,650
Natural gas distribution	50,225	60,671		322,458	434,736
Total operating revenues	116,952	112,053		499,799	603,386
Operating Expenses
Cost of gas	17,897	28,902		144,038	260,348
Operations and maintenance	48,859	45,559		140,811	137,117
Depreciation, depletion and amortization	27,980	24,511		79,214	65,357
Taxes, other than income taxes	9,382	9,429		36,749	46,254
Total operating expenses	104,118	108,401		400,812	509,076
Operating Income	12,834	3,652		98,987	94,310
Other Income (Expense)
Interest expense	(10,987)	(10,716)		(32,828)	(31,830)
Other income	3,885	3,804		10,583	11,765
Other expense	(4,020)	(3,292)		(10,614)	(10,495)
Total other expense	(11,122)	(10,204)		(32,859)	(30,560)
Income (Loss) From Continuing Operations Before Income Taxes	1,712	(6,552)		66,128	63,750
Income tax expense (benefit)	1,509	(3,008)		14,114	10,778
Income (Loss) From Continuing Operations	203	(3,544)		52,014	52,972
Discontinued Operations, net of taxes
Income (loss) from operations	39	356		(270)	1,205
Gain (loss) on disposal	(36)	-		270	-
Income From Discontinued Operations	3	356		0	1,205
Net Income (Loss)	$       206	$  (3,188)		$  52,014	$  54,177
Diluted Earnings Per Average Common Share
Continuing Operations	$      0.01	$    (0.11)		$      1.55	$      1.70
Discontinued Operations	0.00	0.01		0.00	0.04
Net Income (Loss)	$      0.01	$   (0.10)		$      1.55	$      1.74
Basic Earnings Per Average Common Share
Continuing Operations	$      0.01	$   (0.11)		$      1.56	$      1.72
Discontinued Operations	0.00	$     0.01		0.00	0.04
Net Income (Loss)	$      0.01	$   (0.10)		$      1.56	$      1.76
Dividends Per Common Share	$      0.18	$   0.175		$      0.53	$   0.515
Diluted Average Common Shares Outstanding	34,731	31,244		33,543	31,171
Basic Average Common Shares Outstanding	34,425	30,948		33,245	30,814

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

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands)	September 30, 2002	December 31, 2001
ASSETS
Current Assets
Cash and cash equivalents	$        4,758	$       6,482
Accounts receivable, net of allowance for doubtful     accounts of $9,353 at September 30, 2002, and     $11,623 at December 31, 2001	69,508	77,106
Inventories, at average cost
Storage gas inventory	37,455	50,978
Materials and supplies	9,325	8,894
Liquified natural gas in storage	3,615	3,146
Deferred gas costs	2,308	17,776
Deferred income taxes	32,313	29,636
Prepayments and other	20,704	6,948
Total current assets	179,986	200,966
Property, Plant and Equipment
Oil and gas properties, successful efforts method	1,046,290	844,962
Less accumulated depreciation, depletion and amortization	257,470	228,867
Oil and gas properties, net	788,820	616,095
Utility plant	809,799	769,259
Less accumulated depreciation	399,669	384,430
Utility plant, net	410,130	384,829
Other property, net	4,684	4,755
Total property, plant and equipment, net	1,203,634	1,005,679
Other Assets
Deferred income taxes	10,567	8,406
Deferred charges and other	41,226	25,305
Total other assets	51,793	33,711
TOTAL ASSETS	$   1,435,413	$   1,240,356

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

CONSOLIDATED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
(in thousands, except share data)	September 30, 2002	December 31, 2001
CAPITAL AND LIABILITIES
Current Liabilities
Long-term debt due within one year	$      13,000	$      16,072
Notes payable to banks	110,000	24,000
Accounts payable	53,122	58,783
Accrued taxes	26,509	32,183
Customers' deposits	15,848	16,399
Amounts due customers	29,465	14,896
Accrued wages and benefits	21,688	22,711
Other	37,409	29,564
Total current liabilities	307,041	214,608
Deferred Credits and Other Liabilities
Accrued pension obligation	21,100	-
Other	6,308	7,410
Total deferred credits and other liabilities	27,408	7,410
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,        34,548,037 shares outstanding at September 30, 2002, and        31,248,547 shares outstanding at December 31, 2001	346	312
Premium on capital stock	315,294	235,976
Capital surplus	2,802	2,802
Retained earnings	264,877	230,554
Accumulated other comprehensive income (loss), net of tax	(4,336)	7,168
Deferred compensation on restricted stock	(948)	(1,513)
Deferred compensation plan	7,646	7,222
Treasury stock, at cost (304,228 shares at September 30, 2002,     and 341,465 shares at December 31, 2001)	(7,646)	(8,316)
Total common shareholders' equity	578,035	474,205
Long-term debt	522,929	544,133
Total capitalization	1,100,964	1,018,338
TOTAL CAPITAL AND LIABILITIES	$   1,435,413	$   1,240,356

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
Nine months ended September 30,(in thousands)	2002	2001
Operating Activities
Net income	$    52,014	$    54,177
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization	83,180	67,036
Deferred income taxes	8,544	1,804
Deferred investment tax credits	(336)	(336)
Change in derivative fair value	(7,807)	(428)
Gain on sale of assets	(3,373)	(72)
Net change in:
Accounts receivable	7,598	66,862
Inventories	12,623	(36,760)
Deferred gas costs	15,468	35,343
Accounts payable	(7,467)	(35,068)
Amounts due customers	(1,613)	(10,805)
Other current assets and liabilities	(591)	1,840
Other, net	(128)	(7,789)
Net cash provided by operating activities	158,112	135,804
Investing Activities
Additions to property, plant and equipment	(108,118)	(171,069)
Acquisition	(117,043)	-
Proceeds from sale of assets	14,335	11,347
Other, net	(600)	(715)
Net cash used in investing activities	(211,426)	(160,437)
Financing Activities
Payment of dividends on common stock	(17,690)	(15,905)
Issuance of common stock	7,556	12,177
Purchase of treasury stock	-	(2,516)
Reduction of long-term debt	(21,204)	(31,583)
Proceeds from issuance of long-term debt	-	75,000
Debt issuance costs	-	(3,801)
Net change in short-term debt	82,928	(15,000)
Net cash provided by financing activities	51,590	18,372
Net change in cash and cash equivalents	(1,724)	(6,261)
Cash and cash equivalents at beginning of period	6,482	11,594
Cash and Cash Equivalents at End of Period	$     4,758	$     5,333

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

STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
		Three months ended			Nine months ended
		September 30,			September 30,
(in thousands)	2002		2001	2002		2001

Operating Revenues	$  50,225	$  60,671	$ 322,458	$ 434,736
Operating Expenses
Cost of gas	18,307	29,253	145,231	261,893
Operations and maintenance	28,053	25,120	80,641	78,975
Depreciation	8,492	7,907	25,035	23,379
Income taxes
Current	(9,735)	(1,192)	7,666	14,107
Deferred, net	4,905	(2,210)	6,795	(2,417)
Deferred investment tax credits, net	(112)	(112)	(336)	(336)
Taxes, other than income taxes	4,280	4,925	22,926	28,793
Total operating expenses	54,190	63,691	287,958	404,394
Operating Income (Loss)	(3,965)	(3,020)	34,500	30,342
Other Income (Expense)
Allowance for funds used during construction	312	481	837	1,564
Other income	1,135	1,218	3,832	3,846
Other expense	(1,623)	(1,357)	(4,493)	(4,412)
Total other income (expense)	(176)	342	176	998
Interest Charges
Interest on long-term debt	3,265	2,547	9,917	6,680
Other interest expense	294	711	953	2,685
Total interest charges	3,559	3,258	10,870	9,365
Net Income (Loss)	$    (7,700)	$    (5,936)	$   23,806	$  21,975

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

BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands)	September 30, 2002	December 31, 2001
ASSETS
Property, Plant and Equipment
Utility plant	$   809,799	$   769,259
Less accumulated depreciation	399,669	384,430
Utility plant, net	410,130	384,829
Other property, net	188	308
Current Assets
Cash and cash equivalents	2,478	3,372
Accounts receivable
Gas	43,330	59,504
Merchandise	1,207	1,506
Other	907	626
Affiliated companies	3,336	-
Allowance for doubtful accounts	(8,850)	(11,100)
Inventories, at average cost
Storage gas inventory	37,455	50,978
Materials and supplies	5,530	5,363
Liquified natural gas in storage	3,615	3,146
Deferred gas costs	2,308	17,776
Deferred income taxes	20,799	22,820
Prepayments and other	18,515	1,378
Total current assets	130,630	155,369
Deferred Charges and Other Assets	26,629	8,715
TOTAL ASSETS	$   567,577	$   549,221

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

BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
(in thousands, except share data)	September 30, 2002	December 31, 2001
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         September 30, 2002, and December 31, 2001	20	20
Premium on capital stock	31,682	31,682
Capital surplus	2,802	2,802
Retained earnings	184,795	172,147
Total common shareholder's equity	219,299	206,651
Long-term debt	179,533	185,000
Total capitalization	398,832	391,651
Current Liabilities
Long-term debt due within one year	5,000	5,000
Notes payable to banks	-	19,000
Accounts payable	33,838	37,077
Accrued taxes	29,717	29,505
Customers' deposits	15,848	16,399
Amounts due customers	29,465	14,896
Accrued wages and benefits	4,189	10,509
Other	10,063	7,289
Total current liabilities	128,120	139,675
Deferred Credits and Other Liabilities
Deferred income taxes	20,724	15,531
Accrued pension obligation	18,151	-
Accumulated deferred investment tax credits	868	1,204
Customer advances for construction and other	882	1,160
Total deferred credits and other liabilities	40,625	17,895
Commitments and Contingencies
TOTAL CAPITAL AND LIABILITIES	$   567,577	$   549,221

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

STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
Nine months ended September 30,(in thousands)	2002	2001
Operating Activities
Net income	$     23,806	$     21,975
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:
Depreciation and amortization	25,035	23,379
Deferred income taxes, net	6,795	(2,417)
Deferred investment tax credits	(336)	(336)
Net change in:
Accounts receivable	13,942	42,525
Inventories	12,887	(35,200)
Deferred gas costs	15,468	35,343
Accounts payable	(185)	(54,216)
Amounts due customers	14,569	(10,805)
Other current assets and liabilities	(20,924)	4,929
Other, net	(764)	(1,513)
Net cash provided by operating activities	90,293	23,664
Investing Activities
Additions to property, plant and equipment	(49,547)	(44,015)
Other, net	168	(481)
Net cash used in investing activities	(49,379)	(44,496)
Financing Activities
Dividends	(11,159)	(15,897)
Net advances to affiliates	(6,182)	(21,120)
Reduction of long-term debt	(5,467)	-
Proceeds from issuance of long-term debt	-	75,000
Debt issuance costs	-	(3,709)
Net change in short-term debt	(19,000)	(21,000)
Net cash provided by (used in) financing activities	(41,808)	13,274
Net change in cash and cash equivalents	(894)	(7,558)
Cash and cash equivalents at beginning of period	3,372	9,113
Cash and Cash Equivalents at End of Period	$        2,478	$        1,555

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. Certain reclassifications were made to conform prior years' financial statements to the current-quarter presentation.

The unaudited financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended September 30, 2001, 2000, and 1999, included in the 2001 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 will continue on a September 30 fiscal year for rate-setting purposes (rate year) and will report on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. 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.

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 in 2002, 1996, 1990, 1987 and 1985. On June 10, 2002, the APSC extended RSE for a six-year period, through January 1, 2008. Under the APSC order, Alagasco's allowed range of return 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 returns of all major energy utilities operating under a similar methodology. Under RSE as extended, the APSC conducts quarterly reviews to determine, based on Alagasco's projections and year-to-date performance, whether Alagasco's return on average equity at the end of the rate year will be within the allowed range. Reductions in rates can be made quarterly to bring the projected return within the allowed range; incr eases, 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 Sept ember 30, 2002; as a result, the utility had a decrease in net income of $0.2 million through the cost control provision of RSE. A $16.3 million and a $9.1 million annual increase in revenues became effective December 1, 2001 and 2000, respectively, under RSE as extended.

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 October 1997 in the amount of $3.9 million with an approved maximum funding level of $4 million, to which Alagasco may charge the full amount of: (1) extraordinary O&M expenses, resulting fromforce majeure events such as storms, severe weather, and outages, when one or a combination of two such events result 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. During 2001, Alagasco charged $1.2 million against the ESR related to extraordinary bad debt expense and revenue losses from certain large industrial customers. 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 September 30, 2002, an d December 31, 2001, the ESR balance of $2.9 million and $2.7 million, respectively, was included in amounts due customers on the consolidated financial statements.

At September 30, 2002, Alagasco had a $18.2 million accrued obligation related to its salaried and union pension plans. In accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," Alagasco has established a regulatory asset of $14.2 million recorded in deferred charges and other for the portion of the accrued obligation to be recovered through rates in future periods.

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 (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 b e 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 cash flow derivative commodity instruments to hedge its exposure to price fluctuations on oil and gas production. In addition, Alabama Gas Corporation 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 Alabama Gas 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 inves tment 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, a component of shareholders' equity. 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 affected derivative contracts. The deferred revenues related to the non-performing hedges are recorded in accumulated other comprehensive income until such time as they are 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. Energen's net income reflected a non-cash benefit of $1.6 million, net of tax, for the three-month period ended September 30, 2002, and a $5.6 million, net of tax, non-cash benefit for the year-to-date. Net income in the year ended December 31, 2002, will reflect a total non-cash benefit of $5.7 million, net of tax, related to the Enron hedge position.

As of September 30, 2002, $0.6 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income, including $0.1 million of gains, net of tax, related to the Enron transactions, 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. The Company recorded an after-tax loss of $210,000 for the three-months ended September 30, 2002, and a $854,000 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 loss of $942,000 for the quarter and a $407,000 after-tax loss year-to-date on contracts which did not meet the defin ition of cash flow hedges under SFAS No. 133. As of September 30, 2002, the Company had 0.6 billion cubic feet (Bcf) of gas basis hedges, 4.5 Bcf of gas collars, 0.3 million barrels (MMBbl) of oil basis hedges and 0.2 MMBbl of oil swaps all of which expire by year-end that did not meet the definition of a cash flow hedge, however, the Company considers these hedges to be viable economic hedges. As of September 30, 2002, and December 31, 2001, the Company had a $0.4 million asset and a $5.9 million liability, respectively, included in deferred income taxes on the consolidated balance sheets related to OCI.

As of September 30, 2002, Energen Resources had for its 2002 gas production basin-specific hedges in place for 0.5 Bcf of gas production hedged at an average contract price of $3.77 per million cubic feet (Mcf), 3.6 Bcf of gas production hedged at an average NYMEX price of $3.67 per Mcf, 1.8 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.25 per Mcf, 1.8 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.30 per Mcf and 2.1 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.62 per Mcf. Energen Resources also had hedges in place for 675 thousand barrels (MBbl) of its oil production at an average NYMEX price of $27.06 per barrel. In addition, the Company had hedged the basis difference on 0.6 Bcf of its 2002 gas production and 322 MBbl of its 2002 oil production. Subsequent to September 30, 2002, Energen Resources entered into additional hedges for 2002, resulting in a total of 1.45 Bcf of its gas basis hedged. Realized prices are anticipa ted to be lower than NYMEX prices due to basis differences and other factors. Production estimates from continuing operations for 2002 total 76.1 Bcfe, almost all of which are from proved reserves owned by the Company, and include 46.8 Bcf of gas, 3.1 MMBbl of oil and 1.8 MMBbl of natural gas liquids; another 0.6 Bcfe is expected to be generated by discontinued operations.

As of September 30, 2002, Energen Resources had entered into basin-specific swaps for 1.4 Bcf of its gas production in 2003 at an average contract price of $3.77 per Mcf, swaps for 5.3 Bcf of its 2003 gas production at an average NYMEX price of $4.07 per Mcf and hedges for 4.8 Bcf of gas production at a basin-specific collar price of $3.72 to $4.70 per Mcf. Energen Resources also had hedges in place for 735 MBbl of its estimated 2003 oil production at an average NYMEX price of $26.52 per barrel. In addition, the Company hedged the basis difference of 375 MBbl of its estimated 2003 oil production and 4.8 Bcf of its 2003 estimated gas production. For 2004 and 2005, Energen Resources had entered into swaps for 1.7 Bcf and 1.2 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively. Subsequent to September 30, 2002, Energen Resources entered into additional hedges for 2003, resulting in a total of 26.1 Bcf (excluding basin-specific collars and swaps) of its 2003 gas production at an average NYMEX price of $4.09 and 1,500 MBbl of its estimated 2003 oil production at an average NYMEX price of $26.26. In addition, the Company entered into gas and oil basis hedges resulting in a total of 11.7 Bcf of its estimated 2003 gas production hedged and 735 MBbl of its 2003 oil production hedged.

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 eff ective 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 address energy price fluctuations in the utility's cost of gas. As of September 30, 2002, and December 31, 2001, Alagasco had recorded a $16.2 million asset and a $378,000 asset, respectively, representing the fair value of derivatives. Alagasco recognizes all derivatives at their fair value as either assets or liabilities on the balance sheet. In accordance with Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation," any gains or losses are passed through to customers using the mechanisms of the GSA in accordance with its APSC-approved tariff.

4. RECONCILIATION OF EARNINGS PER SHARE

				Three months ended				Three months ended
(in thousands, except per share amounts)				September 30, 2002				September 30, 2001
						Per Share				Per Share
			Income		Shares	Amount	Income		Shares	Amount
Basic EPS		$     206			34,425	$  0.01	$ (3,188)		30,948	$ (0.10)
Effect of Dilutive Securities
Long-range performance shares					148				155
Stock options					155				139
Restricted stock					3				2
Diluted EPS		$     206			34,731	$  0.01	$ (3,188)		31,244	$ (0.10)
				Nine months ended				Nine months ended
(in thousands, except per share amounts)				September 30, 2002				September 30, 2001
						Per Share				Per Share
			Income		Shares	Amount	Income		Shares	Amount
Basic EPS	$   52,014				33,245	$  1.56	$  54,177		30,814	$  1.76
Effect of Dilutive Securities
Long-range performance shares					147				165
Stock options					149				189
Restricted stock					2				3
Diluted EPS	$   52,014				33,543	$  1.55	$  54,177		31,171	$  1.74

For the three months and the year-to-date ended September 30, 2002, the Company had 136,300 options and 38,827 shares of non-vested restricted stock that were excluded from the computation of diluted EPS, as their effect was non-dilutive.
5. 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
	September 30,		September 30,
(in thousands)	2002	2001	2002	2001
Operating revenues
Oil and gas operations	$   66,727	$   51,382	$ 177,341	$ 168,650
Natural gas distribution	50,225	60,671	322,458	434,736
Total	$ 116,952	$ 112,053	$ 499,799	$ 603,386
Operating income (loss)
Oil and gas operations	$   22,161	$    10,644	$   51,710	$   53,844
Natural gas distribution	(8,907)	(6,534)	48,625	41,696
Eliminations and corporate expenses	(420)	(458)	(1,348)	(1,230)
Total	$   12,834	$      3,652	$   98,987	$   94,310

(in thousands)	September 30, 2002	December 31, 2001
Identifiable assets
Oil and gas operations	$    871,687	$     687,776
Natural gas distribution	564,241	549,221
Eliminations and other	(515)	3,359
Total	$ 1,435,413	$ 1,240,356

6. COMPREHENSIVE INCOME (LOSS) Comprehensive income (loss) consisted of the following:
	Three months ended	Three months ended
(in thousands)	September 30, 2002	September 30, 2001
Net Income (Loss)	$       206	$   (3,188)
Other comprehensive income (loss)
Current period change in fair value of derivative instruments,      net of tax of ($2.0) million and $6.3 million	(3,168)	9,852
Reclassification adjustment, net of tax of ($1.3) million and       $0.2 million	(2,069)	342
Minimum pension liability, net of tax of ($0.9) million	(1,654)	-
Comprehensive Income (Loss)	$   (6,685)	$     7,006

	Nine months ended	Nine months ended
(in thousands)	September 30, 2002	September 30, 2001
Net Income	$   52,014	$   54,177
Other comprehensive income (loss)
Current period change in fair value of derivative instruments,      net of tax of ($3.2) million and $33.0 million	(5,005)	51,667
Reclassification adjustment, net of tax of ($3.1) million and       $22.2 million	(4,845)	34,782
Minimum pension liability, net of tax of ($0.9) million	(1,654)	-
Comprehensive Income	$   40,510	$  140,626

Accumulated other comprehensive income (loss) consisted of the following:
(in thousands)			September 30, 2002		December 31, 2001
Unrealized gain (loss) on hedges, net of tax of       ($0.4) million and $5.9 million			$       (588)		$    9,262
Minimum pension liability, net of tax of     ($2.0) million and ($1.1) million			(3,748)		(2,094)
Accumulated Other Comprehensive Income (Loss)			$    (4,336)		$    7,168
7. DISCONTINUED OPERATIONS On January 1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses accounting and reporting standards for long-lived assets. This statement requires that gains and losses on the sale of certain oil and gas properties and writedowns of certain properties held-for-sale be reported as discontinued operations, with income or loss from the operations of the associated properties reported as income or loss from discontinued operations. The Statement also provides that all assets classified as held-for-sale be reported at the lower of the carrying amount or fair value. Accordingly, during the second quarter of 2002, Energen Resources recorded a pre-tax writedown of $2.8 million on certain non-strategic gas properties located in the Gulf Coast region, adjusting the carrying amount of the properties to their fair value based upon expected future discounted cash flows. The net carrying amount of these gas properties at Septembe r 30, 2002, totaled $2.5 million. Subsequent to September 30, 2002, a purchase and sale agreement has been signed for the properties; no material gain or loss is expected. The Company periodically reviews its portfolio of assets for potential dispositions and receives unsolicited offers to buy certain of its assets. The following are the results of operations from discontinued operations:
	Three months ended					Nine months ended
	September 30,					September 30,
(in thousands, except per share data)		2002		2001			2002	2001
Oil and gas revenues		$      101		$   1,831			$    1,744	$     5,690
Pretax income (loss) from discontinued operations		$        65		$      592			$      (442)	$    1,983
Income tax expense (benefit)		(26)		(236)			172	(778)
Income (Loss) From Discontinued Operations		39		356			(270)	1,205
Impairment charge on held-for-sale property		-		-			(2,815)	-
(Loss) gain on disposal		(59)		-			3,257	-
Income tax expense (benefit)		23		-			(172)	-
Gain on Disposal		(36)		-			270	-
Total Income (Loss) From Discontinued Operations		$          3		$       356			$           -	$    1,205
Diluted Earnings Per Average Common Share
Income (Loss) from Discontinued Operations		$          -		$      0.01			$     (0.01)	$     0.04
Gain on Disposal		-		-			0.01	-
Total Income (Loss) from Discontinued Operations		$          -		$      0.01			$           -	$     0.04
Basic Earnings Per Average Common Share
Income (Loss ) from Discontinued Operations		$          -		$      0.01			$     (0.01)	$     0.04
Gain on Disposal		-		-			0.01	-
Total Income (Loss) from Discontinued Operations		$          -		$      0.01			$            -	$     0.04
8. 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 Company estimates a total acquisition cost of approximately $183.5 million; this estimate reflects an effective date of January 1, 2002, with appropriate purchase price adjustments from that date forward until completion of the transaction, resulting from interim cash flows and related tax items. More than 97 percent of the acquired reserves are oil, and this acquisition added an estimated 37.8 million barrels of proved oil equivalent reserves to Energen Resources' Permian Basin holdings. The reserves have a reserve to production ratio of 24, and approximately 60 percent are proved developed. 9. CONCENTRATION OF CREDIT RISK Revenues and related accounts receivable from exploration and production operations primarily are generated from the sale of produced natural gas and oil to natural gas and oil marketing companies. Such sales are typically made on an unsecured credit basis with payment due during the month following the month of delivery. This concentration of sales to the energy marketing industry has the potential to affect the Company's overall exposure to credit risk, either positively or negatively, in that our oil and gas purchasers may be affected similarly by changes in economic, industry or other conditions. The credit rating agencies recently have downgraded the credit ratings of a number of energy marketers and their affiliates, including certain oil and gas purchasers of the Company. The Company is monitoring this situation and, in certain instances, may require credit assurances such as a deposit, letter of credit or parent guarantee. The three largest oil and gas purchasers buy approximately 19%, 15% and 13%, r espectively, of Energen Resources' estimated 2002 production. Energen Resources' other purchasers each buy less than 10% of production. Natural gas distribution operating revenues and related accounts receivable are generated from state-regulated utility natural gas sales and transportation to approximately 465,000 residential, commercial and industrial customers located in central and north Alabama. A change in economic conditions may affect the ability of customers to meet their obligations; however, the Company believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure. 10. RECENT PRONOUNCEMENTS OF THE FASB In July 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations," which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The Company is required to adopt this statement on January 1, 2003. The impact of this pronouncement on the Company currently is being evaluated. The FASB issued SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities" in June 2002. This statement requires that a liability for costs associated with exit or disposal activities be recognized at fair value in the period the liability is incurred. The Company is required to adopt this statement for disposal or exit activities initiated after December 31, 2002. The impact of this pronouncement on the Company currently is being evaluated.

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

Energen's net income totaled $0.2 million ($0.01 per diluted share) for the three months ended September 30, 2002, and compared favorably to a net loss of $3.2 million ($0.10 per diluted share) recorded in the same period last year. In the third quarter of 2002, Energen's income from continuing operations totaled $0.2 million ($0.01 per diluted share) and compared with a loss of $3.5 million ($0.11 per diluted share) in the same period a year ago. Energen Resources Corporation, Energen's oil and gas subsidiary, generated income from continuing operations of $8 million in the current quarter as compared with $2.6 million in the same quarter last year primarily as a result of significantly increased production from oil, natural gas and natural gas liquids, increased gas prices and a non-cash benefit of $1.6 million after-tax, or $0.04 per diluted share, associated with its previous hedge position with Enron North America Corp. (Enron). Negatively affecting income from continuing operations w ere increased depreciation, depletion and amortization (DD&A) expense, the timing of the recognition of non-conventional fuels tax credits on an interim basis and the mark-to-market of open hedge contracts scheduled to close this year. Energen's natural gas utility, Alagasco, reported a net loss of $7.7 million in the third quarter as compared to $5.9 million in the same period last year primarily due to the timing of revenue recovery between quarters.

For the 2002 fiscal year-to-date, Energen's net income totaled $52 million ($1.55 per diluted share) as compared with $54.2 million ($1.74 per diluted share) for the same period in the prior year. Income from continuing operations for the nine-months ended September 30, 2002 totaled $52 million ($1.55 per diluted share), and compared with $53 million ($1.70 per diluted share) in the same period last year. Energen Resources' income from continuing operations during the current period totaled $28.5 million as compared with $31.5 million for the first nine months of fiscal 2001. Significantly lower realized commodity sales prices and increased DD&A expense were partially offset by increased production. Alagasco's earnings of $23.8 million in the current year-to-date increased from net income of $22 million from the same period in the previous year. This is a result of the utility earning on an increased level of equity and the timing of revenue recovery between quarters. Also contributing to this increase was additional bad debt expense in the prior year related to significantly higher natural gas prices and colder weather as well as a decline in industrial gas usage in the previous period.

Oil and Gas Operations

Revenues from oil and gas operations rose 30 percent to $66.8 million for the three months ended September 30, 2002, largely as a result of increased production volumes related to an acquisition of oil properties in the Permian Basin. For the year-to-date, revenues for oil and gas operations increased 5.2 percent to $177 million primarily due to increased production volumes partially offset by lower average commodity prices. Including the non-cash benefit from the former Enron hedges, average gas prices increased 20.5 percent to $3.23 per million cubic feet (Mcf), while average oil prices decreased 6.6 percent to $23.72 per barrel in the current quarter. Natural gas liquids prices remained virtually unchanged with an average price of $12.68 per barrel. For the year-to-date, including the non-cash benefit from the former Enron hedges, average gas prices decreased 5.9 percent to $3.02 per Mcf, average oil prices decreased 4.1 percent to $23.24 per barrel and natural gas liquids prices decreased 27.9 percent to an average price of $11.88 per barrel.

Natural gas production from continuing operations in the third quarter increased 5.1 percent to 12.1 Bcf, while oil volumes rose 64.8 percent to 872 MBbl. Natural gas liquids production increased 14.8 percent to 473 MBbl. For the year to date, natural gas production increased 3.7 percent to 35.3 Bcf, oil volumes increased 50.9 percent to 2,268 MBbl and natural gas liquids production rose 20.6 percent to 1,305 MBbl. Natural gas comprised approximately 60 percent of Energen Resources' production for the current quarter and the year-to-date.

Energen Resources enters into cash flow 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, 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 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.

Energen Resources had certain swap agreements with Enron as the counterparty as of October 1, 2001, as more fully discussed in Note 3. These swap agreements ceased to qualify as cash flow hedges during October 2001 as a result of Enron's credit issues. As of September 30, 2002, Energen Resources had for its 2002 gas production basin-specific hedges in place for 0.5 Bcf of gas production hedged at an average contract price of $3.77 per Mcf, 3.6 Bcf of gas production hedged at an average NYMEX price of $3.67 per Mcf, 1.8 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.25 per Mcf, 1.8 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.30 per Mcf and 2.1 Bcf of gas production hedged at a NYMEX collar price of $3.30 to $4.62 per Mcf. Energen Resources also had hedges in place for 675 thousand barrels (MBbl) of its oil production at an average NYMEX price of $27.06 per barrel. In addition, the Company had hedged the basis difference on 0.6 Bcf of its 2002 gas production and 322 MBbl of its 2002 oil production. Subsequent to September 30, 2002, Energen Resources entered into additional hedges for 2002, resulting in a total of 1.45 Bcf of its gas basis hedged. Realized prices are anticipated to be lower than NYMEX prices due to basis differences and other factors. Production estimates from continuing operations for 2002 total 76.1 Bcfe, almost all of which are from proved reserves owned by the Company, and include 46.8 Bcf of gas, 3.1 MMBbl of oil and 1.8 MMBbl of natural gas liquids, with another 0.6 Bcfe generated by discontinued operations.

As of September 30, 2002, Energen Resources had entered into basin-specific swaps for 1.4 Bcf of its gas production in 2003 at an average contract price of $3.77 per Mcf, swaps for 5.3 Bcf of its 2003 gas production at an average NYMEX price of $4.07 per Mcf and 4.8 Bcf of gas production hedged at a basin-specific collar price of $3.72 to $4.70 per Mcf. Energen Resources also had hedges in place for 735 MBbl of its 2003 oil production at an average NYMEX price of $26.52 per barrel. In addition, the Company hedged the basis difference on 375 MBbl of its 2003 oil production and 4.8 Bcf of its 2003 gas production. For 2004 and 2005, Energen Resources had entered into swaps for 1.7 Bcf and 1.2 Bcf of its gas production at average NYMEX prices of $3.77 per Mcf and $3.75 per Mcf, respectively. Subsequent to September 30, 2002, Energen Resources entered into additional hedges for 2003, resulting in a total of 26.1 Bcf (excluding basin specific collars and swaps) of its 2003 gas production at an average NYMEX price of $4.09 and 1,500 MBbl of its 2003 oil production at an average NYMEX price of $26.26. In addition, the Company entered into gas and oil basis hedges resulting in a total of 11.7 Bcf of its 2003 gas production hedged and 735 MBbl of its estimated 2003 oil production hedged.

Operations and maintenance (O&M) expense increased $0.4 million for the quarter and $1.9 million for the year-to-date. Lease operating expenses increased by $0.5 million for the quarter and $0.9 million for the year-to-date primarily due to the acquisition of oil and gas properties. Exploration expense was lower by $1.1 million in the third quarter and $0.8 million for the year-to-date, largely due to decreased exploratory efforts.

Energen Resources' DD&A expense for the quarter rose $2.9 million as a result of increased production. For the year-to-date, DD&A expense increased $12.2 million largely due to increased production and increased DD&A rates. Increased DD&A rates were driven by market declines in commodity prices as compared to the previous year and ongoing development of the properties. The average depletion rate for the current quarter and the same period last year was $0.95 and for the year-to-date was $0.94 as compared to $0.83 in the same period a year ago.

Energen Resources' expense for taxes other than income taxes primarily reflected production-related taxes that were $0.6 million higher this quarter primarily as a result of increased production and $3.6 million lower for the year-to-date primarily as a result of decreased commodity market prices.

Energen Resources, in the ordinary course of business, may be involved in the sale of developed and undeveloped properties. The Company is required to reflect these dispositions of assets and the write down of certain properties held for sale as discontinued operations under the provisions of SFAS No. 144, which was adopted as of January 1, 2002. For the current quarter, Energen Resources recorded a pre-tax loss of $59,000 and a year-to-date pre-tax gain of $442,000 from the sale of properties and adjustments to the fair value of properties being held for sale.

Natural Gas Distribution

Natural gas distribution revenues decreased $10.5 million for the quarter and $112.3 million on a year-to-date basis largely due to a decrease in the commodity cost of gas as well as to a decrease in gas usage. Although weather was comparable with the previous period, Alagasco experienced a 3.9 percent decrease in residential sales volumes and a 6.2 percent decrease in small commercial and industrial customer sales volumes for the quarter. This decrease was largely due to lower use per customer during the current period. Transportation volumes increased 4.5 percent over the same period last year when higher gas prices and a general economic weakness resulted in decreased demand. For the year-to-date, weather that was 15.2 percent warmer than in the same period last year contributed to a 16.1 percent decrease in residential sales volumes as well as small commercial and industrial customer sales volumes. The previous year's cold winter and high gas costs also contributed to a decline in the number of residential customers during the current year-to-date period. Large transportation customers had a 10.8 percent increase in throughput for the year-to-date primarily due to significantly higher natural gas prices and a general economic weakness in the previous period. Significantly lower commodity gas prices along with decreased gas purchase volumes contributed to a 37.4 percent decrease in cost of gas for the quarter and a 44.5 percent decrease 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 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 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.

O&M expense increased 11.7 percent in the current quarter and 2.1 percent for the year-to-date primarily due to increased labor related costs and increased information technology related costs partially offset by decreased bad debt expense. A 7.4 percent increase in depreciation expense in the current quarter and a 7.1 percent increase year-to-date were 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.

Non-Operating Items

Interest expense for the Company increased $0.3 million in quarter-to-quarter comparisons and $1 million for the year-to-date. Interest expense was influenced by increased short-term debt at Energen, primarily related to Energen Resources' acquisition in the Permian Basin in April 2002, as well as Alagasco's issuance of $40 million of 6.25% Notes and $35 million of 6.75% Notes in August 2001.

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 effective tax rates are expected to continue to remain lower than statutory federal rates through December 31, 2002.

Income tax expense increased in quarter comparisons primarily as a result of lower recognition of non-conventional fuels tax credits of $1.7 million and a 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 $0.9 million. The decrease in nonconventional fuels tax credits for the quarter and year-to-date reflects the timing of the recognition on an interim basis. The estimated effective tax rate utilized in computing income tax expense reflects an expected financial recognition of $13.9 million of nonconventional fuels tax credits for 2002.

FINANCIAL POSITION AND LIQUIDITY

Cash flows from operations for the year-to-date were $158.1 million as compared to $135.8 million in the same period last year. Decreased net income during the period was offset 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 warmer-than-normal weather and decreased gas costs compared to the prior period.

The Company had a net investment of $211.4 million through the nine months ended September 30, 2002, primarily in additions of property, plant and equipment. Energen Resources invested $175.4 million in capital expenditures primarily related to the acquisition and development of oil and gas properties. In April 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 Company estimates the total acquisition approximated $183.5 million. Utility capital expenditures totaled $50.2 million in the year-to-date and primarily represented system distribution expansion and support facilities.

The Company provided $51.6 million for financing activities in the year-to-date primarily through increased borrowings under Energen's short-term credit facilities.

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 and development of producing properties while maintaining the strength of the Company's utility foundation. For the five years ended December 31, 2001, Energen's diluted EPS grew at an average compound rate of 13.1 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 such facilities, continued availability could be affected by future economic and business conditions. During the quarter, the Company called for redemption of $7.8 million in outstanding Series 1993 Notes using available short-term credit facilities. Energen's management plans to utilize increases in cash flows to help finance Energen Resources' acquisition and development strategy.

In 2002, Energen Resources plans to invest approximately $279 million in capital expenditures, including $183.5 million for the First Permian acquisition, as more fully described in Note 8, and $95 million in development well drilling and related development activities. Energen Resources' remaining exploratory exposure in 2002 is estimated to be $0.7 million. Capital investment at Energen Resources in 2003 is expected to approximate $79 million for development well drilling and $5 million for exploration and related development. Energen Resources' capital investment for oil and gas activities over the five-year period ending December 31, 2006, is estimated to be $875 million, including the First Permian acquisition. During this five-year period, the Company expects to issue approximately $75 million in additional long-term debt to replace short-term obligations and provide permanent financing for Energen Resources' acquisition strategy. The Company also will provide up to $14 million a year from the issuance of common stock through the dividend reinvestment and direct stock purchase plan, and through the employee savings plans. 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 estimate of expenditures mentioned above, as an acquisition oriented company Energen Resources continually evaluates acquisition opportunities which arise within the marketplace and from time to time may pursue certain opportunities that meet Energen's acquisition strategy. These activities may alter the aforementioned financing requirements. Additionally, Energen Resources may be engaged in negotiations to sell, trade or otherwise dispose of properties which may reduce or eliminate the amount of additional financing described above. Energen Resources is evaluating the possible sale of several properties with combined estimated sale proceeds up to $75 million, depending on the extent of properties sold. These properties are considered non-core and any decision to sell will depend on the attractiveness of current market conditions.

The utility's rate-setting mechanism is based in part on the number of residential customers and an inflation-based cost control measurement as discussed in Note 2. It allows a return on equity within an allowed range of 13.15 percent to 13.65 percent. Continued low inflation and/or the lack of customer growth could impact the utility's ability to manage its O&M expense per customer sufficiently for the inflation-based cost control requirements of RSE and may result in an average return on equity lower than the allowed range of return.

During 2002, Alagasco plans to invest approximately $69 million in utility capital expenditures for normal distribution and support systems, including approximately $20 million for revenue-producing projects and $10 million for information technology application projects. Alagasco also maintains an investment in storage gas which is expected to average approximately $30 million in 2002. Alagasco plans to invest approximately $56 million in utility capital expenditures during 2003. The utility anticipates funding these capital requirements through internally generated capital. Over the Company's five-year planning period ending December 31, 2006, Alagasco anticipates capital investments of approximately $275 million.

Energen Resources Corporation periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on oil and gas production. In addition, Alabama Gas Corporation 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 Alabama Gas 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 cred it.

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
		September 30,				September 30,
(in thousands, except sales price data)			2002	2001		2002	2001
Oil and Gas Operations
Operating revenues
Natural gas			$   39,035	$  30,810		$ 106,622	$  109,189
Oil			20,691	13,427		52,709	36,430
Natural gas liquids			6,004	5,219		15,503	17,831
Other			997	1,926		2,507	5,200
Total			$   66,727	$  51,382	$ 177,341		$ 168,650
Sales volumes from continuing operations
Natural gas (MMcf)			12,085	11,495		35,321	34,051
Oil (MBbl)			872	529		2,268	1,503
Natural gas liquids (MBbl)			473	412		1,305	1,082
Sales volume from continuing operations (MMcfe)			20,159	17,139		56,760	49,559
Total sales volume (MMcfe)			20,188	17,548		57,372	50,783
Average sales price including effects of hedging
Natural gas (Mcf)			$       3.23	$      2.68		$       3.02	$       3.21
Oil (barrel)			$     23.72	$    25.39		$     23.24	$     24.24
Natural gas liquids (barrel)			$     12.68	$    12.67		$     11.88	$     16.48
Average sales price excluding effects of hedging
Natural gas (Mcf)			$       2.89	$      2.71		$       2.75	$       4.76
Oil (barrel)			$     26.34	$    24.94		$     24.12	$     26.37
Natural gas liquids (barrel)			$     12.68	$    12.67		$     11.88	$     16.48
Other data
Depreciation, depletion and amortization			$   19,488	$  16,604		$   54,179	$   41,978
Capital expenditures	$   25,639			$  45,320		$ 241,838	$ 126,799
Exploration expenditures			$        355	$    1,418		$     2,295	$     3,129
Operating income			$   22,161	$  10,644		$   51,710	$   53,844
Natural Gas Distribution
Operating revenues
Residential			$   27,829	$  33,243		$ 211,316	$ 289,634
Commercial and industrial - small			13,214	17,698		79,550	116,601
Transportation			8,163	7,783		28,265	24,456
Other			1,019	1,947		3,327	4,045
Total			$   50,225	$  60,671		$ 322,458	$ 434,736
Gas delivery volumes (MMcf)
Residential			1,906	1,984		20,003	23,834
Commercial and industrial - small			1,430	1,524		8,991	10,716
Transportation			14,885	14,239		44,486	40,138
Total			18,221	17,747		73,480	74,688
Other data
Depreciation and amortization			$     8,492	$    7,907		$   25,035	$   23,379
Capital expenditures			$   20,575	$  15,469		$   50,171	$   42,947
Operating income (loss)			$    (8,907)	$   (6,534)		$   48,625	$   41,696
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 Corporation, Energen's oil and gas subsidiary, periodically enters into cash flow 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 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 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 specul ative 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 September 30, 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, a component of shareholders' equity. 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 writedown to fair value of the asset related to the affected derivative contracts. The deferred revenues related to the non-performing hedges are recorded in accumulated other comprehensive income until such time as they are 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. Energen's net income reflected a non-cash benefit of $1.6 million, net of tax, for the three-month period ended September 30, 2002, and a $5.6 million, net of tax, non-cash benefit for the year-to-date. Net income in the year ended December 31, 2002, will reflect a total non-cash benefit of $5.7 million, net of tax, related to the Enron hedge position. See Note 3 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 a date within 90 days before the filing of this quarterly report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective.
(b)	Our chief executive officer and chief financial officer have concluded that there were no significant changes in our internal controls or in other factors that could significantly affect those controls subsequent to the date of their most recent evaluation.

PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a.	Exhibits
	None
b.	Reports on Form 8-K
	Form 8-K dated July 24, 2002, commenting on the Company's financial relationships with Williams Companies Inc. and Dynegy, Inc.
	Form 8-K dated August 14, 2002, certification pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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
November 13, 2002	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
November 13, 2002	By   /s/ G. C. Ketcham
	G. C. Ketcham
	Executive Vice President, Chief
	Financial Officer and Treasurer of
	Energen Corporation and Alabama Gas
	Corporation
November 13, 2002	By   /s/ Grace B. Carr
	Grace B. Carr
	Vice President and Controller of Energen
	Corporation
November 13, 2002	By   /s/ Paula H. Rushing
	Paula H. Rushing
	Vice President-Finance of Alabama Gas
	Corporation

CERTIFICATION

I, Wm. Michael Warren, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energen Corporation and Alabama Gas Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report.

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weakness in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

November 13, 2002	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

CERTIFICATION

I, G. C. Ketcham, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energen Corporation and Alabama Gas Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report.

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weakness in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

November 13, 2002	By   /s/ G. C. Ketcham
	G. C. Ketcham
	Executive Vice President, Chief
	Financial Officer and Treasurer of
	Energen Corporation and Alabama Gas
	Corporation

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