FORM 10-Q

|X|

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES

EXCHANGE ACT OF 1934 FOR THE QUARTER ENDED MARCH 31, 2004

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

Indicate the number of shares outstanding of each of the issuers' classes of common stock, as of May 5, 2004

Energen Corporation

$0.01 par value

36,342,788 shares

Alabama Gas Corporation

$0.01 par value

  1,972,052 shares

ENERGEN CORPORATION AND ALABAMA GAS CORPORATION

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2004

TABLE OF CONTENTS

Page

PART I: FINANCIAL INFORMATION

Item 1.

Financial Statements

(a) Consolidated Condensed Statements of Income of Energen Corporation

 3

(b) Consolidated Condensed Balance Sheets of Energen Corporation

 4

(c) Consolidated Condensed Statements of Cash Flows of Energen Corporation

 6

(d) Condensed Statements of Income of Alabama Gas Corporation

 7

(e) Condensed Balance Sheets of Alabama Gas Corporation

 8

(f) Condensed Statements of Cash Flows of Alabama Gas Corporation

10

(g) Notes to Unaudited Condensed Financial Statements

11

Item 2.

Management's Discussion and Analysis of Financial Condition and
Results of Operations

20

Selected Business Segment Data of Energen Corporation

25

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

26

Item 4.

Controls and Procedures

27

PART II: OTHER INFORMATION

Item 2.

Changes in Securities, Use of Proceeds and Issuer Purchases of Equity Securities

28

Item 4.

Submission of Matters to a Vote of Security Holders

28

Item 6.

Exhibits and Reports on Form 8-K

28

SIGNATURES

29

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONSOLIDATED CONDENSED STATEMENTS OF INCOME

ENERGEN CORPORATION

(Unaudited)

Three months ended

March 31,

(in thousands, except per share data)

2004

2003

Operating Revenues

Oil and gas operations

$    96,227

$   88,519

Natural gas distribution

255,202

221,139

     Total operating revenues

351,429

309,658

Operating Expenses

Cost of gas

138,738

111,972

Operations and maintenance

53,147

50,817

Depreciation, depletion and amortization

28,736

28,735

Taxes, other than income taxes

24,278

21,520

Accretion expense

490

494

     Total operating expenses

245,389

213,538

Operating Income

106,040

96,120

Other Income (Expense)

Interest expense

(10,318)

(10,822)

Other income

862

3,120

Other expense

(1,025)

(3,089)

     Total other expense

(10,481)

(10,791)

Income From Continuing Operations Before Income Taxes

95,559

85,329

Income tax expense

35,362

32,006

Income From Continuing Operations

60,197

53,323

Discontinued Operations, net of taxes

Income from discontinued operations

1

673

Gain (loss) on disposal

(13)

585

Income (Loss) From Discontinued Operations

(12)

1,258

Net Income

$     60,185

$      54,581

Diluted Earnings Per Average Common Share

Continuing operations

$     1.65

$      1.52

Discontinued operations

-

0.04

Net Income

$        1.65

$       1.56

Basic Earnings Per Average Common Share

Continuing operations

$     1.66

$       1.54

Discontinued operations

-

0.03

Net Income

$      1.66

$        1.57

Dividends Per Common Share

$       0.185

$       0.18

Diluted Average Common Shares Outstanding

36,566

35,034

Basic Average Common Shares Outstanding

36,173

34,729

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

(in thousands)

March 31, 2004

December 31, 2003

ASSETS

Current Assets

Cash and cash equivalents

$      88,198

$       2,127

Accounts receivable, net of allowance for doubtful
    accounts of $10,353 at March 31, 2004, and
    $9,852 at December 31, 2003

147,827

172,915

Inventories, at average cost

    Storage gas inventory

17,046

40,654

    Materials and supplies

7,919

7,677

    Liquified natural gas in storage

3,266

3,475

Deferred income taxes

46,927

38,145

Prepayments and other

36,925

25,073

    Total current assets

348,108

290,066

Property, Plant and Equipment

Oil and gas properties, successful efforts method

1,215,490

1,197,340

Less accumulated depreciation, depletion and amortization

326,071

310,368

    Oil and gas properties, net

889,419

886,972

Utility plant

896,989

883,225

Less accumulated depreciation

349,483

341,787

    Utility plant, net

547,506

541,438

Other property, net

4,962

5,041

    Total property, plant and equipment, net

1,441,887

1,433,451

Other Assets

Regulatory asset

18,082

18,082

Deferred charges and other

31,933 

39,833

    Total other assets

50,015 

57,915

TOTAL ASSETS

$   1,840,010 

$   1,781,432

CONSOLIDATED CONDENSED BALANCE SHEETS

ENERGEN CORPORATION

(Unaudited)

(in thousands, except share data)

March 31, 2004

December 31, 2003

CAPITAL AND LIABILITIES

Current Liabilities

Long-term debt due within one year

$      10,000

$      10,000

Notes payable to banks

-

11,000

Accounts payable

141,860

135,319

Accrued taxes

48,312

28,551

Customers' deposits

18,710

17,884

Amounts due customers

-

8,571

Accrued wages and benefits

19,913

24,957

Regulatory liability

48,915

54,146

Other

44,899

37,303

    Total current liabilities

332,609

327,731

Deferred Credits and Other Liabilities

Asset retirement obligation

26,885

26,515

Minimum pension liability

19,571

17,911

Regulatory liability

106,705

113,427

Deferred income taxes

46,939

33,200

Other

12,071

10,774

    Total deferred credits and other liabilities

212,171

201,827

Commitments and Contingencies

Capitalization

Preferred stock, cumulative $0.01 par value, 5,000,000
    shares authorized

- - 

- -

Common shareholders' equity

    Common stock, $0.01 par value; 75,000,000 shares authorized, 36,344,722 shares outstanding at March 31, 2004, and 36,223,531 shares outstanding at December 31, 2003

363

362

    Premium on capital stock

374,440

367,765

    Capital surplus

2,802

2,802

    Retained earnings

413,467

360,001

    Accumulated other comprehensive loss, net of tax

Unrealized loss on hedges

(35,533)

(21,714)

Minimum pension liability

(8,881)

(8,881)

Deferred compensation on restricted stock

(3,431)

(1,258)

Deferred compensation plan

18,300

17,063

Treasury stock, at cost (446,731 shares at March 31, 2004,
    and 415,869 shares at December 31, 2003)

(19,171)

(17,108)

    Total common shareholders' equity

742,356

699,032

Long-term debt

552,874

552,842

    Total capitalization

1,295,230

1,251,874

TOTAL CAPITAL AND LIABILITIES

$   1,840,010

$   1,781,432

CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

ENERGEN CORPORATION

(Unaudited)

Three months ended March 31, (in thousands)

2004

2003

Operating Activities

Net income

$     60,185

$     54,581

Adjustments to reconcile net income to net cash

provided by (used in) operating activities:

    Depreciation, depletion and amortization

28,736

29,437

    Deferred income taxes

12,777

8,982

    Deferred investment tax credits

(112)

(112)

    Change in derivative fair value

2,532

1,620

    (Gain) loss on sale of assets

78

(9,167)

    Loss on properties held-for-sale

-

8,247

Net change in:

     Accounts receivable

11,336

(46,200)

     Inventories

23,575

13,041

     Accounts payable

(15,804)

26,687

     Amounts due customers

(11,360)

(3,103)

     Other current assets and liabilities

21,781

23,789

Other, net

1,859

(2,671)

    Net cash provided by operating activities

135,583 

105,131 

Investing Activities

Additions to property, plant and equipment

(34,934)

(68,444)

Proceeds from sale of assets

-

15,460

Other, net

(81)

74

    Net cash used in investing activities

(35,015)

(52,910)

Financing Activities

Payment of dividends on common stock

(6,719)

(6,275)

Issuance of common stock

3,522

4,319

Purchase of treasury stock

(300)

(294)

Net change in short-term debt

(11,000)

(48,000)

    Net cash used in financing activities

(14,497) 

(50,250) 

Net change in cash and cash equivalents

86,071

1,971 

Cash and cash equivalents at beginning of period

2,127

4,804 

Cash and Cash Equivalents at End of Period

$      88,198

$      6,775 

CONDENSED STATEMENTS OF INCOME

ALABAMA GAS CORPORATION

(Unaudited)

Three months ended

March 31,

(in thousands)

2004

2003

Operating Revenues

$ 255,202

$   221,139

Operating Expenses

Cost of gas

139,206

112,564

Operations and maintenance

28,597

28,448

Depreciation

9,610

8,925

Income taxes

    Current

20,802

19,503

    Deferred, net

1,458

1,043

    Deferred investment tax credits, net

(112)

(112)

Taxes, other than income taxes

15,775

14,002

     Total operating expenses

215,336

184,373

Operating Income

39,866

36,766

Other Income (Expense)

Allowance for funds used during construction

300

323

Other income

704

1,241

Other expense

(1,016)

(1,323)

     Total other income (expense)

(12)

241

Interest Charges

Interest on long-term debt

2,987

3,237

Other interest expense

548

323

    Total interest charges

3,535

3,560

Net Income

$ 36,319

$    33,447

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

(in thousands)

March 31, 2004

December 31, 2003

ASSETS

Property, Plant and Equipment

Utility plant

$   896,989

$   883,225

Less accumulated depreciation

349,483

341,787

    Utility plant, net

547,506

541,438

Other property, net

329

331

Current Assets

Cash and cash equivalents

5,922

1,440

Accounts receivable

    Gas

112,265

134,376

    Merchandise

1,559

1,210

    Other

1,513

1,018

    Affiliated companies

18,923

-

    Allowance for doubtful accounts

(9,400)

(9,100)

Inventories, at average cost

    Storage gas inventory

17,046

40,654

    Materials and supplies

4,852

5,527

    Liquified natural gas in storage

3,266

3,475

Deferred income taxes

18,301

17,650

Regulatory asset

-

251

Prepayments and other

34,316

22,056

    Total current assets

208,563

218,557

Other Assets

Regulatory asset

18,082

18,082

Deferred charges and other

10,876

19,285

    Total other assets

28,958

37,367

TOTAL ASSETS

$   785,356

$   797,693

CONDENSED BALANCE SHEETS

ALABAMA GAS CORPORATION

(Unaudited)

(in thousands, except share data)

March 31, 2004

December 31, 2003

CAPITAL AND LIABILITIES

Capitalization

Preferred stock, cumulative $0.01 par value, 120,000 shares
    authorized, issuable in series-$4.70 Series

$              -

$           -

Common shareholder's equity

    Common stock, $0.01 par value; 3,000,000 shares
       authorized, 1,972,052 shares outstanding at
       March 31, 2004, and December 31, 2003

           20

         20

    Premium on capital stock

31,682

31,682

    Capital surplus

2,802

2,802

    Retained earnings

245,487

215,869

    Total common shareholder's equity

279,991

250,373

Long-term debt

169,533

169,533

    Total capitalization

449,524

419,906

Current Liabilities

Notes payable to banks

-

11,000

Accounts payable

56,079

56,020

Amounts due to affiliates

-

37,290

Accrued taxes

43,513

22,145

Customers' deposits

18,710

17,884

Amounts due customers

-

8,571

Accrued wages and benefits

5,528

6,247

Regulatory liability

48,915

54,146

Other

10,825

9,039

    Total current liabilities

183,570

222,342

Deferred Credits and Other Liabilities

Deferred income taxes

34,362

32,178

Minimum pension liability

8,285

6,988

Regulatory liability

106,705

113,427

Other

2,910

2,852

     Total deferred credits and other liabilities

152,262

155,445

Commitments and Contingencies

-

-

TOTAL CAPITAL AND LIABILITIES

$   785,356

$   797,693

CONDENSED STATEMENTS OF CASH FLOWS

ALABAMA GAS CORPORATION

(Unaudited)

Three months ended March 31, (in thousands)

2004

2003

Operating Activities

Net income

$     36,319

$     33,447

Adjustments to reconcile net income to net cash

provided by (used in) operating activities:

    Depreciation and amortization

9,610

8,925

    Deferred income taxes, net

1,458

1,043

    Deferred investment tax credits

(112)

(112)

Net change in:

    Accounts receivable

7,815

(24,393)

    Inventories

24,492

13,530

    Accounts payable

310

31,735

    Amounts due customers

(11,360)

(3,103)

    Other current assets and liabilities

22,137

17,204

Other, net

1,200

(143)

    Net cash provided by operating activities

91,869

78,133

Investing Activities

Additions to property, plant and equipment

(13,490)

(14,613)

Other, net

17

26

    Net cash used in investing activities

(13,473)

(14,587)

Financing Activities

Dividends

(6,701)

-

Net advances from (to) affiliates

(56,213)

(50,194)

Net change in short-term debt

(11,000)

(13,000)

    Net cash used in financing activities

(73,914)

(63,194)

Net change in cash and cash equivalents

4,482

352

Cash and cash equivalents at beginning of period

1,440

2,818

Cash and Cash Equivalents at End of Period

$        5,922

$        3,170

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

The unaudited financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2003 and 2002, the three months ended December 31, 2001, and the year ended September 30, 2001, included in the 2003 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. On December 5, 2001, the Board of Directors of the Company approved a change in the Company's fiscal year end from September 30 to December 31, effective January 1, 2002. A transition report was filed on Form 10-Q for the period October 1, 2001, to December 31, 2001. Alagasco is on a September 30 fiscal year for rate-setting purposes (rate year) and reports on a calendar year for the Securities and Exchange Commission and all other financial accounting reporting purposes. The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of Amer ica for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the disclosures required for complete financial statements. The year-end consolidated condensed balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America. The Company's natural gas distribution business is seasonal in character and influenced by weather conditions. Results of operations for interim periods are not necessarily indicative of the results that may be expected for the year.

The quarterly information reflects the application of Statement of Financial Accounting Standard (SFAS) No. 144, "Accounting for Impairment or Disposal of Long-Lived Assets". SFAS No. 144 requires that gains and losses from the sale of certain oil and gas properties and write-downs of certain properties held-for-sale be reported as discontinued operations, with income or loss from operations of the associated properties reported as income or loss from discontinued operations in the current and prior periods. All other adjustments to the unaudited financial statements that are, in the opinion of management, necessary for a fair statement of the results of operations for the interim periods have been recorded. Such adjustments consisted of normal recurring items. Certain reclassifications were made to conform prior years' financial statements to the current-quarter presentation.

2. STOCK-BASED COMPENSATION

The Company adopted the fair value recognition provisions of SFAS No. 123 (as amended), "Accounting for Stock-Based Compensation," prospectively for all stock-based employee compensation effective as of January 1, 2003. Awards under the Company's plan vest over periods ranging from one to four years; therefore, the cost related to stock-based employee compensation included in the determination of net income for the three months ended March 31, 2004 and 2003, approximates that which would have been recognized if the fair value method had been applied to all awards since the original effective date of SFAS No. 123. The following table illustrates the effect on net income and diluted and basic earnings per share as if the fair value based method had been applied to all outstanding and unvested awards in each period:

March 31,

(in thousands)

2004

2003

Net income

As reported

$ 60,185

$ 54,581

Stock-based compensation expense included in reported net income, net of tax

1,043

682

Stock-based compensation expense determined under fair value based method, net of tax

(916)

(833)

Pro forma

$ 60,312

$ 54,430

Diluted earnings per average common share

As reported

$ 1.65

$ 1.56

Pro forma

$ 1.65

$ 1.55

Basic earnings per average common share

As reported

$ 1.66

$ 1.57

Pro forma

$ 1.67

$ 1.57

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

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

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

Energen Resources Corporation, Energen's oil and gas subsidiary, periodically enters into derivative commodity instruments that qualify as cash flow hedges under SFAS No. 133 to hedge its exposure to price fluctuations on oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its exposure to price fluctuations on its gas supply. Such instruments include regulated natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) and over-the-counter swaps, collars and basis hedges with major energy derivative product specialists. The counterparties to the commodity instruments are investment banks and energy-trading firms. In some contracts, the amount of credit allowed before Energen Resources or Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company's debt. In cases where this arrangement exists, generally the Company's credit ratings must be maintained at investment grade status to have available counterparty credit.

As of March 31, 2004, $32.7 million, net of tax, of deferred net losses on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to operating revenues in earnings during the next 12-month period. The actual amounts that will be reclassified to earnings over the next year could vary materially from this amount due to changes in market conditions. Gains and losses on derivative instruments that are not accounted for as cash flow hedges as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. For the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, the Company recorded a $148,000 after-tax gain for the three months ended March 31, 2004. Also, Energen Resources recorded an after-tax loss of $1.4 million for the quarter on contracts which did not meet the definitio n of cash flow hedges under SFAS No. 133. As of March 31, 2004, the Company had 4.91 billion cubic feet (Bcf) of gas hedges and 270,000 barrels (Bbl) of oil hedges which expire by year-end that did not meet the definition of a cash flow hedge but are considered by the Company to be viable economic hedges. As of March 31, 2004, and December 31, 2003, the Company had $21.8 million and $13.9 million, respectively, included in current and noncurrent deferred income taxes on the consolidated balance sheets related to OCI.

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

Production Period

Total Hedged Volumes

Price

Description

Natural Gas

2004

12.7 Bcf

$4.77 Mcf

NYMEX Swaps

18.8 Bcf

$4.30 Mcf

Basin Specific Swaps

1.8 Bcf

$4.05 - $4.44 Mcf

NYMEX Collars

2005

1.2 Bcf

$3.75 Mcf

NYMEX Swaps

10.2 Bcf

$4.26 Mcf

Basin Specific Swaps

Oil

2004

1,268 MBbl

$28.39 Bbl

NYMEX Swaps

916 MBbl

$27.68 Bbl

West Texas Sour (WTS) Swaps

2005

660 MBbl

$30.79 Bbl

NYMEX Swaps

Oil Basis Differential

2004

315 MBbl

*

Basis Swaps

2005

180 MBbl

*

Basis Swaps

Natural Gas Liquids

2004

27.9 MMGal

$0.41 Gal

Liquids Swaps

2005

30.2 MMGal

$0.49 Gal

Liquids Swaps

* Average contract prices not meaningful due to the varying nature of each contract.

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

On December 4, 2000, the APSC authorized Alagasco to engage in energy risk-management activities to manage the utility's cost of gas supply. As required by SFAS No. 133, Alagasco recognizes all derivatives as either assets or liabilities on the balance sheet. Any gains or losses are passed through to customers using the mechanisms of the GSA in compliance with Alagasco's APSC-approved tariff. In accordance with SFAS No. 71, Alagasco had recorded a current regulatory liability of $28.3 million representing the fair value of derivatives as of March 31, 2004. As of December 31, 2003, Alagasco had recorded a current regulatory asset of $0.3 million, a current regulatory liability of $17 million and a noncurrent regulatory liability of $8.7 million representing the fair value of derivatives.

5. RECONCILIATION OF EARNINGS PER SHARE

Three months ended

Three months ended

(in thousands, except per share amounts)

March 31, 2004

March 31, 2003

Per Share

Per Share

Income

Shares

Amount

Income

Shares

Amount

Basic EPS

$   60,185

36,173

$   1.66

$ 54,581

34,729

$ 1.57 

Effect of Dilutive Securities

132

105

247

193

14

7

Diluted EPS

$   60,185

36,566

$   1.65

$ 54,581

35,034

$ 1.56 

For the three months ended March 31, 2004 and 2003, the Company had no options or shares of non-vested restricted stock that were excluded from the computation of diluted EPS.

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

March 31,

(in thousands)

2004

2003

Operating revenues from continuing operations

    Oil and gas operations

$ 96,227

$ 88,519

    Natural gas distribution

255,202

221,139

        Total

$ 351,429

$ 309,658

Operating income (loss) from continuing operations

    Oil and gas operations

$ 44,133

$ 39,175

    Natural gas distribution

62,014

57,200

     Subtotal

106,147

96,375

    Eliminations and corporate expenses

(107)

(255)

        Total