ALABAMA GAS CORP - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549

FORM 10-Q

\|X\|	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
	EXCHANGE ACT OF 1934 FOR THE QUARTER ENDED SEPTEMBER 30, 2002

\| \|	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 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 from force 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 rec