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UNITED STATES |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 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). Energen Corporation $0.01 par value 34,634,508 shares Alabama Gas Corporation $0.01 par value 1,972,052 shares
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
605 Richard Arrington Jr. Boulevard North
Birmingham, Alabama 35203-2707
Telephone Number 205/326-2700
http://www.energen.com
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
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. |
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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. |
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Basin-specific |
A type of derivative contract whereby the contract's settlement price is based on specific geographic basin indices. |
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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. |
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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. |
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Development Costs |
The costs necessary to gain access to, prepare and equip wells drilled to produce proved oil and gas reserves following discovery. |
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Exploratory Well |
A well drilled to a previously untested geologic structure to determine the presence of oil or gas. |
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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. |
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Hedging |
The use of derivative commodity instruments such as futures, swaps and collars to help reduce financial exposure to commodity price volatility. |
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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. |
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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. |
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Proved Developed Reserves |
The portion of proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. |
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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. |
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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. |
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Reserve to Production Ratio |
Ratio determined by dividing the remaining recoverable reserves by estimated annual production volumes expressed in years of supply. |
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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. |
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Throughput |
Total volumes of natural gas sold or transported. |
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ENERGEN CORPORATION AND ALABAMA GAS CORPORATION |
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FORM 10-Q FOR THE QUARTER ENDED SEPTEMBER 30, 2002 |
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TABLE OF CONTENTS |
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Page |
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PART I: FINANCIAL INFORMATION |
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Item 1. |
Financial Statements |
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(a) Consolidated Statements of Income of Energen Corporation |
1 |
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(b) Consolidated Balance Sheets of Energen Corporation |
2 |
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(c) Consolidated Statements of Cash Flows of Energen Corporation |
4 |
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(d) Statements of Income of Alabama Gas Corporation |
5 |
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(e) Balance Sheets of Alabama Gas Corporation |
6 |
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(f) Statements of Cash Flows of Alabama Gas Corporation |
8 |
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(g) Notes to Unaudited Financial Statements |
9 |
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Item 2. |
Management's Discussion and Analysis of Financial Condition and |
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Selected Business Segment Data of Energen Corporation |
21 |
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Item 3. |
Quantitative and Qualitative Disclosures about Market Risk |
22 |
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Item 4. |
Controls and Procedures................................................................................. |
23 |
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PART II: OTHER INFORMATION |
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Item 6. |
Exhibits and Reports on Form 8-K |
24 |
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SIGNATURES |
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25 |
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CERTIFICATIONS |
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26 |
PART I. FINANCIAL INFORMATION |
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ITEM 1. FINANCIAL STATEMENTS |
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CONSOLIDATED STATEMENTS OF INCOME |
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ENERGEN CORPORATION |
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(Unaudited) |
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Three months ended |
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Nine months ended |
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September 30, |
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September 30, |
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(in thousands, except per share data) |
2002 |
2001 |
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2002 |
2001 |
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Operating Revenues |
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Oil and gas operations |
$ 66,727 |
$ 51,382 |
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$ 177,341 |
$ 168,650 |
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Natural gas distribution |
50,225 |
60,671 |
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322,458 |
434,736 |
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Total operating revenues |
116,952 |
112,053 |
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499,799 |
603,386 |
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Operating Expenses |
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Cost of gas |
17,897 |
28,902 |
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144,038 |
260,348 |
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Operations and maintenance |
48,859 |
45,559 |
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140,811 |
137,117 |
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Depreciation, depletion and amortization |
27,980 |
24,511 |
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79,214 |
65,357 |
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Taxes, other than income taxes |
9,382 |
9,429 |
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36,749 |
46,254 |
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Total operating expenses |
104,118 |
108,401 |
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400,812 |
509,076 |
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Operating Income |
12,834 |
3,652 |
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98,987 |
94,310 |
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Other Income (Expense) |
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Interest expense |
(10,987) |
(10,716) |
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(32,828) |
(31,830) |
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Other income |
3,885 |
3,804 |
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10,583 |
11,765 |
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Other expense |
(4,020) |
(3,292) |
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(10,614) |
(10,495) |
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Total other expense |
(11,122) |
(10,204) |
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(32,859) |
(30,560) |
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Income (Loss) From Continuing Operations |
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Income tax expense (benefit) |
1,509 |
(3,008) |
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14,114 |
10,778 |
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Income (Loss) From Continuing Operations |
203 |
(3,544) |
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52,014 |
52,972 |
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Discontinued Operations, net of taxes |
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Income (loss) from operations |
39 |
356 |
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(270) |
1,205 |
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Gain (loss) on disposal |
(36) |
- |
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270 |
- |
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Income From Discontinued Operations |
3 |
356 |
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0 |
1,205 |
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Net Income (Loss) |
$ 206 |
$ (3,188) |
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$ 52,014 |
$ 54,177 |
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Diluted Earnings Per Average Common Share |
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Continuing Operations |
$ 0.01 |
$ (0.11) |
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$ 1.55 |
$ 1.70 |
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Discontinued Operations |
0.00 |
0.01 |
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0.00 |
0.04 |
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Net Income (Loss) |
$ 0.01 |
$ (0.10) |
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$ 1.55 |
$ 1.74 |
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Basic Earnings Per Average Common Share |
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Continuing Operations |
$ 0.01 |
$ (0.11) |
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$ 1.56 |
$ 1.72 |
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Discontinued Operations |
0.00 |
$ 0.01 |
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0.00 |
0.04 |
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Net Income (Loss) |
$ 0.01 |
$ (0.10) |
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$ 1.56 |
$ 1.76 |
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Dividends Per Common Share |
$ 0.18 |
$ 0.175 |
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$ 0.53 |
$ 0.515 |
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Diluted Average Common Shares Outstanding |
34,731 |
31,244 |
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33,543 |
31,171 |
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Basic Average Common Shares Outstanding |
34,425 |
30,948 |
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33,245 |
30,814 |
The accompanying Notes are an integral part of these financial statements.
CONSOLIDATED BALANCE SHEETS |
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ENERGEN CORPORATION |
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(Unaudited) |
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(in thousands) |
September 30, 2002 |
December 31, 2001 |
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ASSETS |
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Current Assets |
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Cash and cash equivalents |
$ 4,758 |
$ 6,482 |
Accounts receivable, net of allowance for doubtful |
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Inventories, at average cost |
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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 |
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Total current assets |
179,986 |
200,966 |
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Property, Plant and Equipment |
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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 |
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Other Assets |
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Deferred income taxes |
10,567 |
8,406 |
Deferred charges and other |
41,226 |
25,305 |
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Total other assets |
51,793 |
33,711 |
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TOTAL ASSETS |
$ 1,435,413 |
$ 1,240,356 |
CONSOLIDATED BALANCE SHEETS |
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ENERGEN CORPORATION |
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(Unaudited) |
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(in thousands, except share data) |
September 30, 2002 |
December 31, 2001 |
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CAPITAL AND LIABILITIES |
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Current Liabilities |
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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 |
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Total current liabilities |
307,041 |
214,608 |
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Deferred Credits and Other Liabilities |
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Accrued pension obligation |
21,100 |
- |
Other |
6,308 |
7,410 |
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Total deferred credits and other liabilities |
27,408 |
7,410 |
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Commitments and Contingencies |
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Capitalization |
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Preferred stock, cumulative $0.01 par value, 5,000,000 |
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Common shareholders' equity |
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Common stock, $0.01 par value; 75,000,000 shares authorized, |
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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, |
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Total common shareholders' equity |
578,035 |
474,205 |
Long-term debt |
522,929 |
544,133 |
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Total capitalization |
1,100,964 |
1,018,338 |
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TOTAL CAPITAL AND LIABILITIES |
$ 1,435,413 |
$ 1,240,356 |
CONSOLIDATED STATEMENTS OF CASH FLOWS |
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ENERGEN CORPORATION |
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(Unaudited) |
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Nine months ended September 30, (in thousands) |
2002 |
2001 |
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Operating Activities |
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Net income |
$ 52,014 |
$ 54,177 |
Adjustments to reconcile net income to net cash |
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provided by (used in) operating activities: |
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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: |
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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) |
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Net cash provided by operating activities |
158,112 |
135,804 |
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Investing Activities |
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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) |
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Net cash used in investing activities |
(211,426) |
(160,437) |
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Financing Activities |
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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) |
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Net cash provided by financing activities |
51,590 |
18,372 |
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Net change in cash and cash equivalents |
(1,724) |
(6,261) |
Cash and cash equivalents at beginning of period |
6,482 |
11,594 |
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Cash and Cash Equivalents at End of Period |
$ 4,758 |
$ 5,333 |
STATEMENTS OF INCOME |
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ALABAMA GAS CORPORATION |
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(Unaudited) |
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Three months ended |
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Nine months ended |
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September 30, |
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September 30, |
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(in thousands) |
2002 |
2001 |
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2002 |
2001 |
Operating Revenues |
$ 50,225 |
$ 60,671 |
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$ 322,458 |
$ 434,736 |
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Operating Expenses |
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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 |
|
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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 |
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Total operating expenses |
54,190 |
63,691 |
|
287,958 |
404,394 |
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Operating Income (Loss) |
(3,965) |
(3,020) |
|
34,500 |
30,342 |
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Other Income (Expense) |
|
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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 |
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176 |
998 |
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Interest Charges |
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Interest on long-term debt |
3,265 |
2,547 |
|
9,917 |
6,680 |
Other interest expense |
294 |
711 |
|
953 |
2,685 |
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Total interest charges |
3,559 |
3,258 |
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10,870 |
9,365 |
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Net Income (Loss) |
$ (7,700) |
$ (5,936) |
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$ 23,806 |
$ 21,975 |
The accompanying Notes are an integral part of these financial statements.
BALANCE SHEETS |
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ALABAMA GAS CORPORATION |
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(Unaudited) |
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(in thousands) |
September 30, 2002 |
December 31, 2001 |
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ASSETS |
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Property, Plant and Equipment |
|
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Utility plant |
$ 809,799 |
$ 769,259 |
Less accumulated depreciation |
399,669 |
384,430 |
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Utility plant, net |
410,130 |
384,829 |
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Other property, net |
188 |
308 |
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Current Assets |
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Cash and cash equivalents |
2,478 |
3,372 |
Accounts receivable |
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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 |
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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 |
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Total current assets |
130,630 |
155,369 |
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Deferred Charges and Other Assets |
26,629 |
8,715 |
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TOTAL ASSETS |
$ 567,577 |
$ 549,221 |
BALANCE SHEETS |
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ALABAMA GAS CORPORATION |
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(Unaudited) |
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(in thousands, except share data) |
September 30, 2002 |
December 31, 2001 |
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CAPITAL AND LIABILITIES |
|
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Capitalization |
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Preferred stock, cumulative $0.01 par value, 120,000 shares |
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Common shareholder's equity |
|
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Common stock, $0.01 par value; 3,000,000 shares |
|
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Premium on capital stock |
31,682 |
31,682 |
Capital surplus |
2,802 |
2,802 |
Retained earnings |
184,795 |
172,147 |
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Total common shareholder's equity |
219,299 |
206,651 |
Long-term debt |
179,533 |
185,000 |
|
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Total capitalization |
398,832 |
391,651 |
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Current Liabilities |
|
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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 |
|
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Total current liabilities |
128,120 |
139,675 |
|
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Deferred Credits and Other Liabilities |
|
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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 |
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 |
NOTES TO UNAUDITED FINANCIAL STATEMENTS |
1. BASIS OF PRESENTATION
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 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. |
||||||
|
||||||
|
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 |
|
|
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 |
|
|
Reclassification adjustment, net of tax of ($3.1) million and |
|
|
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 |
|
|
||||||||
Minimum pension liability, net of tax of |
|
|
||||||||
|
|
|
||||||||
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.
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.
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.
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.
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.
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.
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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.
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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.
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.
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.
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SELECTED BUSINESS SEGMENT DATA |
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ENERGEN CORPORATION |
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(Unaudited) |
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Three months ended |
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Nine months ended |
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September 30, |
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September 30, |
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(in thousands, except sales price data) |
2002 |
2001 |
|
2002 |
2001 |
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|
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|
|
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|
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Oil and Gas Operations |
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|
|
|
||||
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 |
||||
|
|
|
|
|
|
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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 |
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|
|
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Natural gas (Mcf) |
$ 3.23 |
$ 2.68 |
|
$ 3.02 |
$ 3.21 |
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Oil (barrel) |
$ 23.72 |
$ 25.39 |
|
$ 23.24 |
$ 24.24 |
||||
Natural gas liquids (barrel) |
$ 12.68 |
$ 12.67 |
|
$ 11.88 |
$ 16.48 |
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Average sales price excluding effects of hedging |
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|
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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 |
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Other data |
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Depreciation, depletion and amortization |
$ 19,488 |
$ 16,604 |
|
$ 54,179 |
$ 41,978 |
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Capital expenditures |
$ 25,639 |
$ 45,320 |
|
$ 241,838 |
$ 126,799 |
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Exploration expenditures |
$ 355 |
$ 1,418 |
|
$ 2,295 |
$ 3,129 |
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Operating income |
$ 22,161 |
$ 10,644 |
|
$ 51,710 |
$ 53,844 |
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Natural Gas Distribution |
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Operating revenues |
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Residential |
$ 27,829 |
$ 33,243 |
|
$ 211,316 |
$ 289,634 |
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Commercial and industrial - small |
13,214 |
17,698 |
|
79,550 |
116,601 |
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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 |
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Gas delivery volumes (MMcf) |
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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 |
||||
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Other data |
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Depreciation and amortization |
$ 8,492 |
$ 7,907 |
|
$ 25,035 |
$ 23,379 |
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Capital expenditures |
$ 20,575 |
$ 15,469 |
|
$ 50,171 |
$ 42,947 |
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Operating income (loss) |
$ (8,907) |
$ (6,534) |
|
$ 48,625 |
$ 41,696 |
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
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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 |
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(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. |
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(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 |
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K |
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a. |
Exhibits |
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None |
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b. |
Reports on Form 8-K |
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Form 8-K dated July 24, 2002, commenting on the Company's financial relationships with Williams Companies Inc. and Dynegy, Inc. |
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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. |
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ENERGEN CORPORATION |
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ALABAMA GAS CORPORATION |
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November 13, 2002 |
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By /s/ Wm. Michael Warren, Jr. |
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Wm. Michael Warren, Jr. |
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Chairman, President and Chief Executive |
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Officer of Energen Corporation, Chairman |
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and Chief Executive Officer of Alabama |
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Gas Corporation |
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November 13, 2002 |
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By /s/ G. C. Ketcham |
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G. C. Ketcham |
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Executive Vice President, Chief |
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Financial Officer and Treasurer of |
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Energen Corporation and Alabama Gas |
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Corporation |
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November 13, 2002 |
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By /s/ Grace B. Carr |
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Grace B. Carr |
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Vice President and Controller of Energen |
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Corporation |
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November 13, 2002 |
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By /s/ Paula H. Rushing |
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Paula H. Rushing |
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Vice President-Finance of Alabama Gas |
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Corporation |
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CERTIFICATION |
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I, Wm. Michael Warren, Jr., certify that: |
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1. I have reviewed this quarterly report on Form 10-Q of Energen Corporation and Alabama Gas Corporation; |
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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. |
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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; |
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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: |
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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; |
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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 |
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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; |
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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): |
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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 |
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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 |
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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. |
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November 13, 2002 |
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By /s/ Wm. Michael Warren, Jr. |
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Wm. Michael Warren, Jr. |
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Chairman, President and Chief Executive |
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Officer of Energen Corporation, Chairman |
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and Chief Executive Officer of Alabama |
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Gas Corporation |
CERTIFICATION |
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I, G. C. Ketcham, certify that: |
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1. I have reviewed this quarterly report on Form 10-Q of Energen Corporation and Alabama Gas Corporation; |
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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. |
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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; |
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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: |
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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; |
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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 |
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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; |
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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): |
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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 |
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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 |
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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. |
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November 13, 2002 |
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By /s/ G. C. Ketcham |
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G. C. Ketcham |
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Executive Vice President, Chief |
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Financial Officer and Treasurer of |
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Energen Corporation and Alabama Gas |
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Corporation |
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