UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-Q
| x |
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006
OR
| ¨ |
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
FOR THE TRANSITION PERIOD FROM TO
| Commission File Number |
Registrant |
State of Incorporation | IRS Employer Identification Number | |||
| 1-7810 | Energen Corporation | Alabama | 63-0757759 | |||
| 2-38960 | Alabama Gas Corporation | Alabama | 63-0022000 |
605 Richard Arrington Jr. Boulevard North
Birmingham, Alabama 35203-2707
Telephone Number 205/326-2700
http://www.energen.com
Alabama Gas Corporation, a wholly owned subsidiary of Energen Corporation, meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is therefore filing this Form with reduced disclosure format pursuant to General Instruction H(2).
Indicate by a check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities and Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. YES x NO ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non- accelerated filer (as defined in Rule 12b-2 of the Act).
| Energen Corporation |
Large accelerated filer x |
Accelerated filer ¨ |
Non-accelerated filer ¨ | |||
| Alabama Gas Corporation |
Large accelerated filer ¨ |
Accelerated filer ¨ |
Non-accelerated filer x |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
| Energen Corporation |
YES ¨ NO x | |
| Alabama Gas Corporation |
YES ¨ NO x |
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of November 1, 2006.
| Energen Corporation |
$0.01 par value | 72,355,003 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 SEPTEMBER 30, 2006
2
CONSOLIDATED CONDENSED STATEMENTS OF INCOME
ENERGEN CORPORATION
(Unaudited)
| Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||||
| (in thousands, except per share data) |
2006 | 2005 | 2006 | 2005 | ||||||||||||
| Operating Revenues |
||||||||||||||||
| Oil and gas operations |
$ | 171,516 | $ | 126,260 | $ | 510,213 | $ | 363,568 | ||||||||
| Natural gas distribution |
71,195 | 64,421 | 503,014 | 429,746 | ||||||||||||
| Total operating revenues |
242,711 | 190,681 | 1,013,227 | 793,314 | ||||||||||||
| Operating Expenses |
||||||||||||||||
| Cost of gas |
32,311 | 27,386 | 284,192 | 214,665 | ||||||||||||
| Operations and maintenance |
78,836 | 67,818 | 231,720 | 195,127 | ||||||||||||
| Depreciation, depletion and amortization |
35,676 | 34,215 | 104,472 | 98,741 | ||||||||||||
| Taxes, other than income taxes |
19,338 | 19,523 | 73,450 | 65,867 | ||||||||||||
| Accretion expense |
881 | 668 | 2,691 | 1,965 | ||||||||||||
| Total operating expenses |
167,042 | 149,610 | 696,525 | 576,365 | ||||||||||||
| Operating Income |
75,669 | 41,071 | 316,702 | 216,949 | ||||||||||||
| Other Income (Expense) |
||||||||||||||||
| Interest expense |
(12,267 | ) | (11,600 | ) | (37,810 | ) | (34,794 | ) | ||||||||
| Other income |
448 | 822 | 1,410 | 1,694 | ||||||||||||
| Other expense |
(207 | ) | (104 | ) | (708 | ) | (638 | ) | ||||||||
| Total other expense |
(12,026 | ) | (10,882 | ) | (37,108 | ) | (33,738 | ) | ||||||||
| Income From Continuing Operations Before Income Taxes |
63,643 | 30,189 | 279,594 | 183,211 | ||||||||||||
| Income tax expense |
22,346 | 11,116 | 101,194 | 67,619 | ||||||||||||
| Income From Continuing Operations |
41,297 | 19,073 | 178,400 | 115,592 | ||||||||||||
| Discontinued Operations, net of taxes |
||||||||||||||||
| Income (loss) from discontinued operations |
2 | 3 | (6 | ) | (3 | ) | ||||||||||
| Gain on disposal of discontinued operations |
53 | 10 | 53 | 120 | ||||||||||||
| Income From Discontinued Operations |
55 | 13 | 47 | 117 | ||||||||||||
| Net Income |
$ | 41,352 | $ | 19,086 | $ | 178,447 | $ | 115,709 | ||||||||
| Diluted Earnings Per Average Common Share |
||||||||||||||||
| Continuing operations |
$ | 0.56 | $ | 0.26 | $ | 2.42 | $ | 1.57 | ||||||||
| Discontinued operations |
— | — | — | — | ||||||||||||
| Net Income |
$ | 0.56 | $ | 0.26 | $ | 2.42 | $ | 1.57 | ||||||||
| Basic Earnings Per Average Common Share |
||||||||||||||||
| Continuing operations |
$ | 0.57 | $ | 0.26 | $ | 2.45 | $ | 1.58 | ||||||||
| Discontinued operations |
— | — | — | 0.01 | ||||||||||||
| Net Income |
$ | 0.57 | $ | 0.26 | $ | 2.45 | $ | 1.59 | ||||||||
| Dividends Per Common Share |
$ | 0.11 | $ | 0.10 | $ | 0.33 | $ | 0.30 | ||||||||
| Diluted Average Common Shares Outstanding |
73,191 | 73,878 | 73,671 | 73,725 | ||||||||||||
| Basic Average Common Shares Outstanding |
72,228 | 73,024 | 72,839 | 72,998 | ||||||||||||
The accompanying notes are an integral part of these condensed financial statements.
3
CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
| (in thousands) |
September 30, 2006 |
December 31, 2005 | ||||
| ASSETS |
||||||
| Current Assets |
||||||
| Cash and cash equivalents |
$ | 5,675 | $ | 8,714 | ||
| Accounts receivable, net of allowance for doubtful accounts of $13,964 at September 30, 2006, |
188,415 | 285,765 | ||||
| Inventories, at average cost |
||||||
| Storage gas inventory |
79,121 | 71,179 | ||||
| Materials and supplies |
9,321 | 7,926 | ||||
| Liquified natural gas in storage |
3,367 | 3,795 | ||||
| Regulatory asset |
47,943 | 6,633 | ||||
| Deferred income taxes |
91 | 72,113 | ||||
| Prepayments and other |
29,449 | 22,366 | ||||
| Total current assets |
363,382 | 478,491 | ||||
| Property, Plant and Equipment |
||||||
| Oil and gas properties, successful efforts method |
2,081,515 | 1,930,291 | ||||
| Less accumulated depreciation, depletion and amortization |
535,294 | 466,643 | ||||
| Oil and gas properties, net |
1,546,221 | 1,463,648 | ||||
| Utility plant |
1,045,507 | 999,011 | ||||
| Less accumulated depreciation |
414,751 | 401,232 | ||||
| Utility plant, net |
630,756 | 597,779 | ||||
| Other property, net |
9,180 | 6,584 | ||||
| Total property, plant and equipment, net |
2,186,157 | 2,068,011 | ||||
| Other Assets |
||||||
| Regulatory asset |
11,110 | 33,436 | ||||
| Deferred charges and other |
76,705 | 38,288 | ||||
| Total other assets |
87,815 | 71,724 | ||||
| TOTAL ASSETS |
$ | 2,637,354 | $ | 2,618,226 | ||
The accompanying notes are an integral part of these condensed financial statements.
4
CONSOLIDATED CONDENSED BALANCE SHEETS
ENERGEN CORPORATION
(Unaudited)
| (in thousands, except share and per share data) |
September 30, 2006 |
December 31, 2005 |
||||||
| LIABILITIES AND SHAREHOLDERS’ EQUITY |
||||||||
| Current Liabilities |
||||||||
| Long-term debt due within one year |
$ | — | $ | 15,000 | ||||
| Notes payable to banks |
42,000 | 153,000 | ||||||
| Accounts payable |
152,912 | 306,618 | ||||||
| Accrued taxes |
49,799 | 44,324 | ||||||
| Customers’ deposits |
19,471 | 20,767 | ||||||
| Amounts due customers |
16,950 | 6,181 | ||||||
| Accrued wages and benefits |
26,034 | 33,634 | ||||||
| Regulatory liability |
10,091 | 53,496 | ||||||
| Royalties payable |
25,140 | 27,569 | ||||||
| Other |
36,274 | 27,720 | ||||||
| Total current liabilities |
378,671 | 688,309 | ||||||
| Long-term debt |
682,949 | 683,236 | ||||||
| Deferred Credits and Other Liabilities |
||||||||
| Asset retirement obligation |
52,333 | 50,270 | ||||||
| Accrued benefit liability |
14,700 | 15,739 | ||||||
| Regulatory liability |
126,677 | 119,808 | ||||||
| Deferred income taxes |
217,519 | 148,040 | ||||||
| Other |
13,637 | 20,146 | ||||||
| Total deferred credits and other liabilities |
424,866 | 354,003 | ||||||
| Commitments and Contingencies |
||||||||
| Shareholders’ equity |
||||||||
| Preferred stock, cumulative $0.01 par value, 5,000,000 shares authorized |
— | — | ||||||
| Common shareholders’ equity |
||||||||
| Common stock, $0.01 par value; 150,000,000 shares authorized, 73,579,172 shares issued at September 30, 2006, and 73,493,337 shares issued at December 31, 2005 |
736 | 735 | ||||||
| Premium on capital stock |
408,581 | 394,861 | ||||||
| Capital surplus |
2,802 | 2,802 | ||||||
| Retained earnings |
757,629 | 603,314 | ||||||
| Accumulated other comprehensive gain (loss), net of tax |
||||||||
| Unrealized gain (loss) on hedges |
31,840 | (92,112 | ) | |||||
| Minimum pension liability |
(7,735 | ) | (13,707 | ) | ||||
| Deferred compensation on restricted stock |
— | (2,123 | ) | |||||
| Deferred compensation plan |
11,756 | 11,907 | ||||||
| Treasury stock, at cost (2,203,231 shares at September 30, 2006, and 1,066,935 shares at December 31, 2005) |
(54,741 | ) | (12,999 | ) | ||||
| Total shareholders’ equity |
1,150,868 | 892,678 | ||||||
| TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY |
$ | 2,637,354 | $ | 2,618,226 | ||||
The accompanying notes are an integral part of these condensed financial statements.
5
CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS
ENERGEN CORPORATION
(Unaudited)
| Nine months ended September 30, (in thousands) |
2006 | 2005 | ||||||
| Operating Activities |
||||||||
| Net income |
$ | 178,447 | $ | 115,709 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation, depletion and amortization |
104,472 | 98,769 | ||||||
| Deferred income taxes |
62,298 | 46,960 | ||||||
| Change in derivative fair value |
(72 | ) | 22,476 | |||||
| Gain on sale of assets |
(125 | ) | (1,590 | ) | ||||
| Other, net |
3,216 | 7,212 | ||||||
| Net change in: |
||||||||
| Accounts receivable, net |
129,062 | 28,865 | ||||||
| Inventories |
(8,909 | ) | (21,943 | ) | ||||
| Accounts payable |
(36,839 | ) | (13,700 | ) | ||||
| Amounts due customers |
(30,767 | ) | 25,169 | |||||
| Other current assets and liabilities |
(903 | ) | 4,799 | |||||
| Net cash provided by operating activities |
399,880 | 312,726 | ||||||
| Investing Activities |
||||||||
| Additions to property, plant and equipment |
(207,135 | ) | (177,642 | ) | ||||
| Acquisitions, net of cash acquired |
(4,334 | ) | (5,457 | ) | ||||
| Proceeds from sale of assets |
184 | 10,338 | ||||||
| Other, net |
(1,783 | ) | (1,102 | ) | ||||
| Net cash used in investing activities |
(213,068 | ) | (173,863 | ) | ||||
| Financing Activities |
||||||||
| Payment of dividends on common stock |
(24,132 | ) | (21,978 | ) | ||||
| Issuance of common stock |
356 | 3,952 | ||||||
| Purchase of treasury stock |
(40,895 | ) | (2,168 | ) | ||||
| Payment of long-term debt |
(15,400 | ) | (28,060 | ) | ||||
| Proceeds from issuance of long-term debt |
— | 80,000 | ||||||
| Debt issuance costs |
— | (1,865 | ) | |||||
| Net change in short-term debt |
(111,000 | ) | (135,000 | ) | ||||
| Other |
1,220 | — | ||||||
| Net cash used in financing activities |
(189,851 | ) | (105,119 | ) | ||||
| Net change in cash and cash equivalents |
(3,039 | ) | 33,744 | |||||
| Cash and cash equivalents at beginning of period |
8,714 | 4,489 | ||||||
| Cash and Cash Equivalents at End of Period |
$ | 5,675 | $ | 38,233 | ||||
The accompanying notes are an integral part of these condensed financial statements.
6
CONDENSED STATEMENTS OF INCOME
ALABAMA GAS CORPORATION
(Unaudited)
| Three months ended September 30, |
Nine months ended September 30, |
|||||||||||||||
| (in thousands) |
2006 | 2005 | 2006 | 2005 | ||||||||||||
| Operating Revenues |
$ | 71,195 | $ | 64,421 | $ | 503,014 | $ | 429,746 | ||||||||
| Operating Expenses |
||||||||||||||||
| Cost of gas |
32,311 | 28,047 | 284,192 | 216,360 | ||||||||||||
| Operations and maintenance |
30,348 | 30,898 | 94,614 | 90,986 | ||||||||||||
| Depreciation |
11,201 | 10,668 | 32,880 | 31,724 | ||||||||||||
| Income taxes |
||||||||||||||||
| Current |
(10,525 | ) | (9,788 | ) | 15,308 | 17,378 | ||||||||||
| Deferred, net |
5,677 | 4,351 | 2,186 | 2,181 | ||||||||||||
| Taxes, other than income taxes |
6,256 | 5,833 | 33,811 | 29,667 | ||||||||||||
| Total operating expenses |
75,268 | 70,009 | 462,991 | 388,296 | ||||||||||||
| Operating Income (Expense) |
(4,073 | ) | (5,588 | ) | 40,023 | 41,450 | ||||||||||
| Other Income (Expense) |
||||||||||||||||
| Allowance for funds used during construction |
286 | 195 | 764 | 568 | ||||||||||||
| Other income |
399 | 372 | 1,070 | 1,069 | ||||||||||||
| Other expense |
(207 | ) | (104 | ) | (701 | ) | (629 | ) | ||||||||
| Total other income |
478 | 463 | 1,133 | 1,008 | ||||||||||||
| Interest Charges |
||||||||||||||||
| Interest on long-term debt |
3,220 | 3,291 | 9,702 | 10,263 | ||||||||||||
| Other interest expense |
858 | 394 | 2,289 | 928 | ||||||||||||
| Total interest charges |
4,078 | 3,685 | 11,991 | 11,191 | ||||||||||||
| Net Income (Loss) |
$ | (7,673 | ) | $ | (8,810 | ) | $ | 29,165 | $ | 31,267 | ||||||
The accompanying notes are an integral part of these condensed financial statements.
7
ALABAMA GAS CORPORATION
(Unaudited)
| (in thousands) |
September 30, 2006 |
December 31, 2005 |
||||||
| ASSETS |
||||||||
| Property, Plant and Equipment |
||||||||
| Utility plant |
$ | 1,045,507 | $ | 999,011 | ||||
| Less accumulated depreciation |
414,751 | 401,232 | ||||||
| Utility plant, net |
630,756 | 597,779 | ||||||
| Other property, net |
164 | 169 | ||||||
| Current Assets |
||||||||
| Cash and cash equivalents |
4,283 | 7,169 | ||||||
| Accounts receivable |
||||||||
| Gas |
69,444 | 194,447 | ||||||
| Other |
5,877 | 7,524 | ||||||
| Affiliated companies |
— | 3,215 | ||||||
| Allowance for doubtful accounts |
(13,200 | ) | (10,800 | ) | ||||
| Inventories, at average cost |
||||||||
| Storage gas inventory |
79,121 | 71,179 | ||||||
| Materials and supplies |
4,283 | 4,144 | ||||||
| Liquified natural gas in storage |
3,367 | 3,795 | ||||||
| Deferred income taxes |
12,840 | 13,284 | ||||||
| Regulatory asset |
47,943 | 6,633 | ||||||
| Prepayments and other |
13,587 | 11,203 | ||||||
| Total current assets |
227,545 | 311,793 | ||||||
| Other Assets |
||||||||
| Regulatory asset |
11,110 | 33,436 | ||||||
| Prepaid pension asset |
28,688 | — | ||||||
| Deferred charges and other |
6,519 | 6,857 | ||||||
| Total other assets |
46,317 | 40,293 | ||||||
| TOTAL ASSETS |
$ | 904,782 | $ | 950,034 | ||||
The accompanying notes are an integral part of these condensed financial statements.
8
CONDENSED BALANCE SHEETS
ALABAMA GAS CORPORATION
(Unaudited)
| (in thousands, except share data) |
September 30, 2006 |
December 31, 2005 | ||||
| LIABILITIES AND CAPITALIZATION |
||||||
| Capitalization |
||||||
| Preferred stock, cumulative $0.01 par value, 120,000 shares authorized |
$ | — | $ | — | ||
| Common shareholder’s equity |
||||||
| Common stock, $0.01 par value; 3,000,000 shares authorized, 1,972,052 shares issued at |
20 | 20 | ||||
| Premium on capital stock |
31,682 | 31,682 | ||||
| Capital surplus |
2,802 | 2,802 | ||||
| Retained earnings |
243,247 | 236,957 | ||||
| Total common shareholder’s equity |
277,751 | 271,461 | ||||
| Long-term debt |
209,254 | 209,654 | ||||
| Total capitalization |
487,005 | 481,115 | ||||
| Current Liabilities |
||||||
| Long-term debt due within one year |
— | 5,000 | ||||
| Notes payable to banks |
42,000 | 55,000 | ||||
| Accounts payable |
92,328 | 112,443 | ||||
| Affiliated companies |
5,474 | — | ||||
| Accrued taxes |
35,686 | 32,770 | ||||
| Customers’ deposits |
19,471 | 20,767 | ||||
| Amounts due customers |
16,950 | 6,181 | ||||
| Accrued wages and benefits |
9,763 | 11,449 | ||||
| Regulatory liability |
10,091 | 53,496 | ||||
| Other |
14,310 | 8,694 | ||||
| Total current liabilities |
246,073 | 305,800 | ||||
| Deferred Credits and Other Liabilities |
||||||
| Deferred income taxes |
41,708 | 39,949 | ||||
| Regulatory liability |
126,677 | 119,808 | ||||
| Other |
3,319 | 3,362 | ||||
| Total deferred credits and other liabilities |
171,704 | 163,119 | ||||
| Commitments and Contingencies |
||||||
| TOTAL LIABILITIES AND CAPITALIZATION |
$ | 904,782 | $ | 950,034 | ||
The accompanying notes are an integral part of these condensed financial statements.
9
CONDENSED STATEMENTS OF CASH FLOWS
ALABAMA GAS CORPORATION
(Unaudited)
| Nine months ended September 30, (in thousands) |
2006 | 2005 | ||||||
| Operating Activities |
||||||||
| Net income |
$ | 29,165 | $ | 31,267 | ||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
| Depreciation and amortization |
32,880 | 31,724 | ||||||
| Deferred income taxes |
2,186 | 2,181 | ||||||
| Other, net |
(2,259 | ) | 1,430 | |||||
| Net change in: |
||||||||
| Accounts receivable |
109,070 | 47,857 | ||||||
| Inventories |
(7,653 | ) | (22,184 | ) | ||||
| Accounts payable |
(43,315 | ) | (22,862 | ) | ||||
| Amounts due customers |
(30,767 | ) | 25,169 | |||||
| Other current assets and liabilities |
69 | 5,760 | ||||||
| Net cash provided by operating activities |
89,376 | 100,342 | ||||||
| Investing Activities |
||||||||
| Additions to property, plant and equipment |
(58,111 | ) | (52,921 | ) | ||||
| Other, net |
(1,565 | ) | (1,102 | ) | ||||
| Net cash used in investing activities |
(59,676 | ) | (54,023 | ) | ||||
| Financing Activities |
||||||||
| Dividends |
(22,875 | ) | (21,970 | ) | ||||
| Payment of long-term debt |
(5,400 | ) | (28,060 | ) | ||||
| Proceeds from issuance of long-term debt |
— | 80,000 | ||||||
| Debt issuance costs |
— | (1,708 | ) | |||||
| Net advances from affiliates |
8,689 | 8,755 | ||||||
| Net change in short-term debt |
(13,000 | ) | (82,000 | ) | ||||
| Net cash used in financing activities |
(32,586 | ) | (44,983 | ) | ||||
| Net change in cash and cash equivalents |
(2,886 | ) | 1,336 | |||||
| Cash and cash equivalents at beginning of period |
7,169 | 3,467 | ||||||
| Cash and Cash Equivalents at End of Period |
$ | 4,283 | $ | 4,803 | ||||
The accompanying notes are an integral part of these condensed financial statements.
10
NOTES TO UNAUDITED CONDENSED FINANCIAL STATEMENTS
ENERGEN CORPORATION AND ALABAMA GAS CORPORATION
1. BASIS OF PRESENTATION
The unaudited condensed financial statements and notes should be read in conjunction with the financial statements and notes thereto for the years ended December 31, 2005, 2004 and 2003 included in the 2005 Annual Report of Energen Corporation (the Company) and Alabama Gas Corporation (Alagasco) on Form 10-K. Alagasco has 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 America 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 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 impairments on 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 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 SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), using the modified prospective application method for new awards effective January 1, 2006. The Company previously adopted the fair value recognition provisions of SFAS No. 123 as amended, “Accounting for Stock-Based Compensation,” prospectively for stock-based compensation effective January 1, 2003. As a result, the adoption of SFAS No. 123R did not have a significant impact to the Company since the expensing provisions were voluntarily adopted in 2003.
SFAS No. 123R requires that all share-based compensation awards be measured at fair value at the date of grant and expensed over the requisite vesting period. SFAS No. 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if the actual forfeitures differ from those estimates. Prior to the adoption of SFAS No. 123R, the Company accounted for forfeitures upon occurrence. This change in method did not have a significant impact to the Company upon adoption of SFAS No. 123R.
The Company previously recognized all stock-based employee compensation expense over the stated vesting periods for each award. For awards granted prior to January 1, 2006, the Company recorded any unrecognized expense on the date of an employee’s retirement. For new awards granted to retirement eligible employees effective January 1, 2006, the Company began recognizing the entire compensation expense in the period of grant. If this method of expense recognition had been applied to all awards, compensation expense would have been reduced during the three months ended September 30, 2006 and 2005, by approximately $1.1 million and $0.4 million, respectively. For the year-to-date ended September 30, 2006 and 2005, compensation expense recognized by this method would have been reduced by $2.9 million and $1.2 million, respectively. The Company utilized the long-form method of calculating the available pool of windfall tax benefit. For the three months and nine months ended September 30, 2006, the Company recognized an excess tax benefit of $0.1 million and $1 million, respectively, related to its stock-based compensation.
The following table illustrates the effect on net income and diluted and basic earnings per share as if the Company had applied the fair value recognition provisions of SFAS No. 123, superseded by SFAS No. 123R, for the three months and nine months ended September 30, 2005, to all outstanding and unvested employee share-based awards:
11
| (in thousands, except per share data) |
Three months ended September 30, 2005 |
Nine months ended September 30, 2005 |
||||||
| Net income |
||||||||
| As reported |
$ | 19,086 | $ | 115,709 | ||||
| Stock-based compensation expense included in reported net income, net of tax |
3,077 | 6,769 | ||||||
| Stock-based compensation expense determined under the fair value based method, net of tax |
(2,175 | ) | (5,157 | ) | ||||
| Pro forma |
$ | 19,988 | $ | 117,321 | ||||
| Diluted earnings per average common share |
||||||||
| As reported |
$ | 0.26 | $ | 1.57 | ||||
| Pro forma |
$ | 0.27 | $ | 1.59 | ||||
| Basic earnings per average common share |
||||||||
| As reported |
$ | 0.26 | $ | 1.59 | ||||
| Pro forma |
$ | 0.27 | $ | 1.61 | ||||
1997 Stock Incentive Plan and 1988 Stock Option Plan:
Performance Share Awards: The Energen 1997 Stock Incentive Plan provided for the grant of performance share awards, with each unit equal to the market value of one share of common stock, to eligible employees based on predetermined Company performance criteria at the end of a four-year award period. This criteria is considered a market condition as defined by SFAS No. 123R. On January 25, 2006, the Company amended its 1997 Stock Incentive Plan to provide that payment of earned performance share awards be made in the form of Company common stock, with no portion of an award paid in cash. This amendment affected 29 participants. Prior to the amendment, payment of performance awards could be made in cash or in a combination of Company common stock or cash. The impact of this modification was not significant to the Company.
1997 Stock Incentive Plan performance share awards granted or modified after the adoption of SFAS No. 123R have been valued in a Monte Carlo model. The Monte Carlo model uses historical volatility and other variables to estimate the probability of satisfying the market condition of the award. For performance share awards granted prior to the adoption of SFAS No. 123R, the Company estimated fair value based on the quoted market price of the Company’s common stock and adjusted each period for the expected payout ratio.
A summary of performance share award activity as of September 30, 2006, and transactions during the nine months then ended, is presented below:
| 1997 Stock Incentive Plan | ||||||
| Shares | Weighted Average Price | |||||
| Nonvested at December 31, 2005 |
477,720 | $ | 40.26 | |||
| Granted |
111,990 | 43.81 | ||||
| Forfeitures |
(847 | ) | 43.81 | |||
| Nonvested at September 30, 2006 |
588,863 | $ | 41.35 | |||
The Company recorded expense of $2,370,000 and $3,511,000 for the three months ended September 30, 2006 and 2005, respectively, for performance share awards with a related deferred income tax benefit of $896,000 and $1,328,000, respectively. For the year-to-date ended September 30, 2006 and 2005, the Company recorded $6,616,000 and $7,636,000, respectively, for performance share awards with a related deferred income tax benefit of $2,502,000 and $2,887,000, respectively. As of September 30, 2006, there was $7.8 million of total unrecognized compensation cost related to performance share awards. These awards have a weighted average requisite service period of 1.16 years from the date of grant.
Stock Options: The 1997 Stock Incentive Plan and the Energen 1988 Stock Option Plan provided for the grant of incentive stock options, non-qualified stock options, or a combination thereof to officers and key employees. Options granted under the Plans provide for the purchase of Company common stock at not less than the fair market value on the date the option is granted. The sale or transfer of the shares is limited during certain periods.
12
Under the 1988 Stock Option Plan, 1,080,000 shares of Company common stock reserved for issuance have been granted. Under the 1997 Stock Incentive Plan, 5,600,000 shares of Company common stock were reserved for issuance with 2,006,055 remaining for issuance as of September 30, 2006. All outstanding options are incentive or non-qualified, vest within three years from date of grant, and expire 10 years from the grant date.
A summary of stock option activity as of September 30, 2006, and transactions during the nine months then ended, is presented below:
| 1997 Stock Incentive Plan | 1988 Stock Option Plan | |||||||||||
| Shares | Weighted Average Exercise Price |
Shares | Weighted Average Exercise Price | |||||||||
| Outstanding at December 31, 2005 |
613,400 | $ | 14.04 | 28,000 | $ | 9.13 | ||||||
| Exercised |
(82,480 | ) | 10.63 | (7,000 | ) | 9.13 | ||||||
| Outstanding at September 30, 2006 |
530,920 | $ | 14.57 | 21,000 | $ | 9.13 | ||||||
| Exercisable at September 30, 2006 |
448,160 | $ | 12.64 | 21,000 | $ | 9.13 | ||||||
The Company used the Black-Scholes pricing model to calculate the fair values of the options awarded. Option awards were granted with an exercise price equal to the market price of the Company’s stock on the date of grant. For purposes of this valuation the following assumptions were used to derive the fair values: a seven-year option life based on historical experience; an annualized volatility rate, based on historical volatility, of 32.72 percent and 34.67 percent for the years ended December 31, 2004 and 2003, respectively; a risk-free interest rate of 3.64 percent and 2.36 percent for the years ended December 31, 2004 and 2003, respectively; and a dividend yield of 1.81 percent on options without dividend equivalents for the year ended December 31, 2004. Options with dividend equivalents assume no dividend yield for all periods presented. The weighted-average grant-date fair value for options granted without dividend equivalents during the year ended December 31, 2004 was $7.11. The weighted-average grant-date fair value for options granted with dividend equivalents during the year ended December 31, 2003 was $6.05. There were no options granted during 2005 or year-to-date in 2006. The Company recorded expense of $49,000 and $116,000 during the three months ended September 30, 2006 and 2005, respectively, for options with a related deferred income tax benefit of $10,000 and $26,000, respectively. For the year-to-date ended September 30, 2006 and 2005, the Company recorded expense of $147,000 and $349,000, respectively, for options with a related deferred income tax benefit of $30,000 and $78,000, respectively.
The total intrinsic value of stock options exercised during the three months and the nine months ended September 30, 2006, was $1,263,000 and $1,513,000, respectively. During the three months and the nine months ended September 30, 2006, the total intrinsic value of stock appreciation rights exercised was $452,000 and $914,000, respectively. During the nine months ended September 30, 2006, the Company received cash of $430,000 from the exercise of stock options and paid $914,000 in settlement of stock appreciation rights. Total intrinsic value for outstanding options as of September 30, 2006, was $15.4 million and $13.7 million for exercisable options. The fair value of options vested during the year-to-date ended September 30, 2006 was $3.3 million. As of September 30, 2006, there was $49,000 of unrecognized compensation cost related to outstanding nonvested stock options, all of which will be recognized during 2006.
The following table summarizes options outstanding as of September 30, 2006:
| 1997 Stock Incentive Plan |
1988 Stock Option Plan | |||||||||
| Range of Exercise Prices |
Shares | Weighted Average Contractual Life |
Range of Exercise Prices |
Shares | Weighted Average Contractual Life | |||||
| $9.13-$9.41 |
90,224 | 2.22 years | $9.13 | 21,000 | 1.17 years | |||||
| $13.72 |
104,000 | 4.08 years | — | — | — | |||||
| $11.32 |
68,416 | 5.08 years | — | — | — | |||||
| $14.86 |
185,520 | 6.33 years | — | — | — | |||||
| $21.38 |
82,760 | 7.33 years | — | — | — | |||||
| $9.13-$21.38 |
530,920 | 5.19 years | $9.13 | 21,000 | 1.17 years | |||||
The weighted average remaining contractual life of currently exercisable stock options is 4.63 years as of September 30, 2006.
13
Restricted Stock: In addition, the 1997 Stock Incentive Plan provided for the grant of restricted stock which have been valued based on the quoted market price of the Company’s common stock at the date of grant. A summary of restricted stock activity as of September 30, 2006, and transactions during the nine months then ended is presented below:
| 1997 Stock Incentive Plan | ||||||
| Shares | Weighted Average Price | |||||
| Nonvested at December 31, 2005 |
242,444 | $ | 20.48 | |||
| Granted |
23,500 | 38.11 | ||||
| Vested |
(71,364 | ) | 18.54 | |||
| Nonvested at September 30, 2006 |
194,580 | $ | 23.31 | |||
The Company recorded expense of $329,000 and $482,000 for the three months ended September 30, 2006 and 2005, respectively, related to restricted stock, with a related deferred income tax benefit of $124,000 and $182,000, respectively. For the year-to-date ended September 30, 2006 and 2005, the Company recorded expense of $1,423,000 and $1,385,000, respectively, related to restricted stock, with a related deferred income tax benefit of $538,000 and $524,000, respectively. As of September 30, 2006, there was $1.6 million of total unrecognized compensation cost related to nonvested restricted stock awards recorded in premium on capital stock. These awards have a requisite service period of 1.04 years from the date of grant. The Company has typically funded options, restricted stock obligations and performance share obligations through original issue shares.
2004 Stock Appreciation Rights Plan: The Energen 2004 Stock Appreciation Rights Plan provided for the payment of cash incentives measured by the long-term appreciation of Company stock. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. These awards have a three year requisite service period. Awards granted prior to January 1, 2006 were valued using the intrinsic value method. There were no awards granted in 2005 or year-to-date in 2006. For the three months ended September 30, 2006 and 2005, the Company recorded expense of $318,000 and $784,000, respectively, associated with stock appreciation rights. For the year-to-date ended September 30, 2006 and 2005, the Company recorded expense of $435,000 and $1,393,000, respectively, associated with stock appreciation rights.
2005 Petrotech Incentive Plan: The Energen Resources’ 2005 Petrotech Incentive Plan provided for the grant of restricted stock units which may include market conditions. These awards are liability awards which settle in cash and are re-measured each reporting period until settlement. Effective January 1, 2006, the fair value of the restricted stock units with a market condition was calculated using a Monte Carlo approach. Restricted stock units with service conditions were valued based on the Company’s stock price at the end of the period adjusted to remove the present value of future dividends. Prior to the implementation of SFAS 123R, these awards were valued using the Company’s common stock price at each period end.
During 2006, Energen Resources awarded 26,440 performance units of which 22,905 included a market condition. Energen Resources awarded 23,460 performance units in 2005 of which 11,730 included a market condition. The Company recognized expense of $208,000 and $477,000 during the three months and nine months ended September 30, 2006, respectively, related to these performance units.
1997 Deferred Compensation Plan: The 1997 Deferred Compensation Plan allowed officers and non-employee directors to defer certain compensation. Amounts deferred by a participant under the 1997 Deferred Compensation Plan are credited to accounts maintained for a participant in either a stock account or an investment account. The stock account tracks the performance of the Company’s common stock, including reinvestment of dividends. The investment account tracks the performance of certain mutual funds. The Company has funded, and presently plans to continue funding, a trust in a manner that generally tracks participants’ accounts under the 1997 Deferred Compensation Plan. While intended for payment of benefits under the 1997 Deferred Compensation Plan, the trust’s assets remain subject to the claims of the Company’s creditors. Amounts earned under the Deferred Compensation Plan and invested in Company common stock held by the trust have been recorded as treasury stock, along with the related deferred compensation obligation in the Consolidated Statements of Shareholders’ Equity.
14
Shareholder Rights Plan: On June 24, 1998, the Company adopted a Shareholder Rights Plan (the 1998 Plan) designed to protect shareholders from coercive or unfair takeover tactics. Under certain circumstances, the 1998 Plan provides shareholders with the right to acquire the Company’s Series 1998 Junior Participating Preferred Stock (or, in certain cases, securities of an acquiring person) at a significant discount. Terms and conditions are set forth in a Rights Agreement between the Company and its Rights Agent. Under the 1998 Plan, one half of a right is associated with each outstanding share of common stock. Rights outstanding under the 1998 Plan at December 31, 2005, were convertible into 734,933 shares of Series 1998 Junior Participating Preferred Stock (1/100 share of preferred stock for each full right) subject to adjustment upon occurrence of certain take-over related events. No rights were exercised or exercisable during the period. The price at which the rights would be exercised is $35 per right, subject to adjustment upon occurrence of certain take-over related events. In general, absent certain take-over related events as described in the Plan, the rights may be redeemed prior to the July 27, 2008 expiration for $0.01 per right.
3. REGULATORY
All of Alagasco’s utility operations are conducted in the state of Alabama. Alagasco is subject to regulation by the Alabama Public Service Commission (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 operations. 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. 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, 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 return. 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, 2005, Alagasco had a $3.3 million reduction in revenues to bring the return on average equity to midpoint within the allowed range of return. Alagasco did not have a reduction in rates related to the return on average equity for the rate year ended 2006. A $15.8 million and a $12.3 million annual increase in revenues became effective December 1, 2005 and 2004, respectively. 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. Alagasco’s O&M expense fell within the index range for the rate year ended September 30, 2005. The increase in O&M expense per customer was above the index range for the rate year ended September 30, 2006; as a result, the utility had a $1.5 million pre-tax decrease in revenues with a corresponding rate reduction effective December 1, 2006, under the provisions of 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. This adjustment, however, is subject to certain limitations including regulatory limits on adjustments to increase customers’ bills, the impact of non-temperature weather conditions such as wind velocity or cloud cover and the impact of any elasticity of demand as a result of high commodity prices. 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.
15
4. DERIVATIVE COMMODITY INSTRUMENTS
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, “Accounting for Derivative Instruments and Hedging Activities,” 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 may 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 collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. In cases where this arrangement exists, generally the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Company’s or Alagasco’s credit rating results in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company or Alagasco in the event credit ratings are below investment grade. At September 30, 2006, Energen Resources was in a net gain position with all but one of its counterparties and was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of September 30, 2006. The Company believes the creditworthiness of these counterparties is satisfactory.
Energen Resources applies SFAS No. 133 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 effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured 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 operating revenues 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 operating revenues in the period of change.
As of September 30, 2006, $34.2 million, net of tax, of deferred net gains on derivative instruments recorded in accumulated other comprehensive income are expected to be reclassified to operating revenues during the next 12-month period. The actual amount 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 hedge transactions, as well as the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, are included in operating revenues in the consolidated financial statements. For the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges, Energen Resources recorded a $0.4 million after-tax gain for the three months ended September 30, 2006, and a $0.9 million after-tax loss year-to-date. As of September 30, 2006, all of the Company’s hedges met the definition of a cash flow hedge. The Company had net $19.5 million deferred tax liability and a net $56.5 million deferred tax asset included in current and noncurrent deferred income taxes on the consolidated balance sheets related to derivative items included in OCI as of September 30, 2006 and December 31, 2005, respectively. At September 30, 2006, and December 31, 2005, the Company had $51.7 million of current gains recorded in accounts receivable and $145.9 million of current losses recorded in accounts payable, respectively, and $5.7 million and $11.9 million, respectively, of non-current losses recorded in deferred credits and other liabilities related to derivative contracts. The Company also had $2 million of non-current gains recorded in deferred charges and other related to derivative contracts as of September 30, 2006.
Energen Resources entered into the following transactions for the remainder of 2006 and subsequent years:
| Production Period |
Total Hedged Volumes |
Average Contract Price |
Description | |||
| Natural Gas | ||||||
| 2006 |
3.9 Bcf |
$8.03 Mcf |
NYMEX Swaps | |||
| 5.4 Bcf |
$6.45 Mcf |
Basin Specific Swaps | ||||
| 2007 |
11.4 Bcf |
$9.43 Mcf |
NYMEX Swaps | |||
| 22.7 Bcf |
$8.14 Mcf |
Basin Specific Swaps | ||||
| Oil | ||||||
| 2006 |
691 MBbl |
$52.58 Bbl |
NYMEX Swaps | |||
| 2007 |
2,716 MBbl |
$70.01 Bbl |
NYMEX Swaps | |||
| 2008 |
1,920 MBbl |
$66.89 Bbl |
NYMEX Swaps | |||
| 2009 |
900 MBbl |
$56.25 Bbl |
NYMEX Swaps | |||
| Oil Basis Differential | ||||||
| 2006 |
469 MBbl |
* |
Basis Swaps | |||
| 2007 |
1,768 MBbl |
* |
Basis Swaps | |||
| 2008 |
1,020 MBbl |
* |
Basis Swaps | |||
| Natural Gas Liquids | ||||||
| 2006 |
7.6 MMGal |
$0.56 Gal |
Liquids Swaps | |||
| 2007 |
41.8 MMGal |
$0.93 Gal |
Liquids Swaps | |||
| * |
Average contract prices are not meaningful due to the varying nature of each contract. |
16
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 at the inception of the hedge, 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 and measured. 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 Resources has hedged exposures to the variability of cash flows is through December 31, 2009.
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 with a corresponding regulatory asset or liability. 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, “Accounting for the Effects of Certain Types of Regulation,” at September 30, 2006, Alagasco recognized a $29.5 million loss as a liability in accounts payable with a corresponding current regulatory asset of $29.5 million representing the fair value of derivatives. At December 31, 2005, Alagasco recognized a $6.3 million loss as a liability in accounts payable with a corresponding current regulatory asset of $6.3 million representing the fair value of derivatives.
5. RECONCILIATION OF EARNINGS PER SHARE
| (in thousands, except per share amounts) |
Three months ended September 30, 2006 |
Three months ended September 30, 2005 | ||||||||||||||
| Income | Shares | Per Share Amount |
Income | Shares | Per Share Amount | |||||||||||
| Basic EPS |
$ | 41,352 | 72,228 | $ | 0.57 | $ | 19,086 | 73,024 | $ | 0.26 | ||||||
| Effect of Dilutive Securities |
||||||||||||||||
| Performance share awards |
504 | 378 | ||||||||||||||
| Stock options |
337 | 345 | ||||||||||||||
| Restricted stock |
122 | 131 | ||||||||||||||
| Diluted EPS |
$ | 41,352 | 73,191 | $ | 0.56 | $ | 19,086 | 73,878 | $ | 0.26 | ||||||
| (in thousands, except per share amounts) |
Nine months ended September 30, 2006 |
Nine months ended September 30, 2005 | ||||||||||||||
| Income | Shares | Per Share Amount |
Income | Shares | Per Share Amount | |||||||||||
| Basic EPS |
$ | 178,447 | 72,839 | $ | 2.45 | $ | 115,709 | 72,998 | $ | 1.59 | ||||||
| Effect of Dilutive Securities |
||||||||||||||||
| Performance share awards |
411 | 320 | ||||||||||||||
| Stock options |
316 | 304 | ||||||||||||||
| Restricted stock |
105 | 103 | ||||||||||||||
| Diluted EPS |
$ | 178,447 | 73,671 | $ | 2.42 | $ | 115,709 | 73,725 | $ | 1.57 | ||||||
17
For the three months and nine months ended September 30, 2006 and 2005, the Company had no options that were excluded from the computation of diluted EPS. For the three months ended September 30, 2006 and 2005, the Company had no shares of non-vested restricted stock that were excluded from the computation of diluted EPS. For the nine months ended September 30, 2006, the Company had 13,500 shares of non-vested restricted stock that were excluded from the computation of diluted EPS, as their effect were non-dilutive. There were no shares of non-vested restricted stock excluded from the computation of diluted EPS for the year-to-date ended September 30, 2005.
6. SEGMENT INFORMATION
The Company principally is engaged in two business segments: the purchase, distribution and sale of natural gas in central and north Alabama (natural gas distribution) and the acquisition, development, exploration and production of oil and gas in the continental United States (oil and gas operations).
| (in thousands) |
Three months ended September 30, |
Nine months ended September 30, |
||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
| Operating revenues from continuing operations |
||||||||||||||||
| Oil and gas operations |
$ | 171,516 | $ | 126,921 | $ | 510,213 | $ | 365,263 | ||||||||
| Natural gas distribution |
71,195 | 64,421 | 503,014 | 429,746 | ||||||||||||
| Eliminations and other |
— | (661 | ) | — | (1,695 | ) | ||||||||||
| Total |
$ | 242,711 | $ | 190,681 | $ | 1,013,227 | $ | 793,314 | ||||||||
| Operating income (loss) from continuing operations |
||||||||||||||||
| Oil and gas operations |
$ | 85,239 | $ | 52,368 | $ | 260,916 | $ | 156,714 | ||||||||
| Natural gas distribution |
(8,921 | ) | (11,025 | ) | 57,517 | 61,009 | ||||||||||
| Eliminations and corporate expenses |
(649 | ) | (272 | ) | (1,731 | ) | (774 | ) | ||||||||
| Total |
$ | 75,669 | $ | 41,071 | $ | 316,702 | $ | 216,949 | ||||||||
| Other income (expense) |
||||||||||||||||
| Oil and gas operations |
$ | (7,985 | ) | $ | (7,869 | ) | $ | (25,995 | ) | $ | (24,017 | ) | ||||
| Natural gas distribution |
(3,600 | ) | (3,222 | ) | (10,858 | ) | (10,183 | ) | ||||||||
| Eliminations and other |
(441 | ) | 209 | (255 | ) | 462 | ||||||||||
| Total |
$ | (12,026 | ) | $ | (10,882 | ) | $ | (37,108 | ) | $ | (33,738 | ) | ||||
| Income from continuing operations before income taxes |
$ | 63,643 | $ | 30,189 | $ | 279,594 | $ | 183,211 | ||||||||
| (in thousands) |
September 30, 2006 |
December 31, 2005 |
||||||||||||||
| Identifiable assets |
||||||||||||||||
| Oil and gas operations |
$ | 1,704,842 | $ | 1,637,244 | ||||||||||||
| Natural gas distribution |
904,782 | 946,819 | ||||||||||||||
| Subtotal |
2,609,624 | 2,584,063 | ||||||||||||||
| Eliminations and other |
27,730 | 34,163 | ||||||||||||||
| Total |
$ | 2,637,354 | $ | 2,618,226 | ||||||||||||
18
7. COMPREHENSIVE INCOME (LOSS)
Comprehensive income (loss) consisted of the following:
| (in thousands) |
Three months ended September 30, 2006 |
Three months ended September 30, 2005 |
|||||
| Net Income |
$ | 41,352 | $ | 19,086 | |||
| Other comprehensive income (loss) |
|||||||
| Current period change in fair value of derivative instruments, net of tax of $42.4 million and ($82.9) million |
69,160 | (135,263 | ) | ||||
| Reclassification adjustment, net of tax of $1.7 million and $17 million |
2,732 | 27,680 | |||||
| Minimum pension liability, net of tax of $3.2 million and ($1.4) million |
5,972 | (2,582 | ) | ||||
| Comprehensive Income (Loss) |
$ | 119,216 | $ | (91,079 | ) | ||
| (in thousands) |
Nine months ended September 30, 2006 |
Nine months ended September 30, 2005 |
|||||
| Net Income |
$ | 178,447 | $ | 115,709 | |||
| Other comprehensive income (loss) |
|||||||
| Current period change in fair value of derivative instruments, net of tax of $66.3 million and ($122.5) million |
108,097 | (199,829 | ) | ||||
| Reclassification adjustment, net of tax of 9.7 million and $32.1 million |
15,855 | 52,416 | |||||
| Minimum pension liability, net of tax of $3.2 million and ($1.4) million |
5,972 | (2,582 | ) | ||||
| Comprehensive Income (Loss) |
$ | 308,371 | $ | (34,286 | ) | ||
Accumulated other comprehensive loss consisted of the following:
| (in thousands) |
September 30, 2006 |
December 31, 2005 |
||||||
| Unrealized loss on hedges, net of tax of $19.5 million and ($56.5) million |
$ | 31,840 | $ | (92,112 | ) | |||
| Minimum pension liability, net of tax of ($4.2) million and ($7.4) million |
(7,735 | ) | (13,707 | ) | ||||
| Accumulated Other Comprehensive Income (Loss) |
$ | 24,105 | $ | (105,819 | ) | |||
19
8. LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS
The Company applies SFAS No. 144, which retains the previous asset impairment requirements of SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of,” for loss recognition when the carrying value of an asset exceeds the sum of the undiscounted estimated future cash flows of the asset. In addition, SFAS No. 144 requires that gains and losses on the sale of certain oil and gas properties and impairments on 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. The results of operations for held-for-sale properties are reclassified and reported as discontinued operations for prior periods in accordance with SFAS No. 144. Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. All assets held-for-sale must be reported at the lower of the carrying amount or fair value. Energen Resources had no property sales during the three months ended September 30, 2006 and 2005 or the year-to-date ended September 30, 2006. In the nine months ended September 30, 2005, Energen Resources recorded a pre-tax gain of $194,000 primarily from a property sale located in the Permian Basin.
The following are the results of operations from discontinued operations:
| (in thousands, except per share data) |
Three months ended September 30, |
Nine months ended September 30, |
||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||
| Oil and gas revenues |
$ | 2 | $ | — | $ | — | $ | 71 | ||||||
| Pretax income (loss) from discontinued operations |
$ | 2 | $ | 5 | $ | (10 | ) | $ | (4 | ) | ||||
| Income tax expense (benefit) |
— | 2 | (4 | ) | (1 | ) | ||||||||
| Income (Loss) From Discontinued Operations |
2 | 3 | (6 | ) | (3 | ) | ||||||||
| Gain (loss) on disposal of discontinued operations |
86 | 16 | 86 | 194 | ||||||||||
| Income tax expense (benefit) |
33 | 6 | 33 | 74 | ||||||||||
| Gain on Disposal of Discontinued Operations |
53 | 10 | 53 | 120 | ||||||||||
| Total Income From Discontinued Operations |
$ | 55 | $ | 13 | $ | 47 | $ | 117 | ||||||
| Diluted Earnings Per Average Common Share |
||||||||||||||
| Income (Loss) from Discontinued Operations |
$ | — | $ | — | $ | — | $ | — | ||||||
| Gain (Loss) on Disposal of Discontinued Operations |
— | — | — | — | ||||||||||
| Total Income (Loss) from Discontinued Operations |
$ | — | $ | — | $ | — | $ | — | ||||||
| Basic Earnings Per Average Common Share |
||||||||||||||
| Income (Loss) from Discontinued Operations |
$ | — | $ | — | $ | — | $ | — | ||||||
| Gain (Loss) on Disposal of Discontinued Operations |
— | — | — | 0.01 | ||||||||||
| Total Income (Loss) from Discontinued Operations |
$ | — | $ | — | $ | — | $ | 0.01 | ||||||
9. EMPLOYEE BENEFIT PLANS
The components of net pension expense for the Company’s two defined benefit non-contributory pension plans were:
| (in thousands) |
Plan A | Plan B | ||||||||||||||
| Three Months Ended September 30, |
Three Months Ended September 30, |
|||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
| Components of net periodic benefit cost: |
||||||||||||||||
| Service cost |
$ | 1,562 | $ | 1,544 | $ | 157 | $ | 155 | ||||||||
| Interest cost |
1,934 | 1,886 | 355 | 351 | ||||||||||||
| Expected long-term return on assets |
(2,432 | ) | (2,199 | ) | (565 | ) | (540 | ) | ||||||||
| Actuarial loss |
815 | 687 | 47 | 31 | ||||||||||||
| Prior service cost amortization |
11 | 59 | 94 | 94 | ||||||||||||
| Settlement charge |
— | — | 326 | — | ||||||||||||
| Net periodic expense |
$ | 1,890 | $ | 1,977 | $ | 414 | $ | 91 | ||||||||
20
| (in thousands) |
Plan A | Plan B | ||||||||||||||
| Nine months Ended September 30, |
Nine months Ended September 30, |
|||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
| Components of net periodic benefit cost: |
||||||||||||||||
| Service cost |
$ | 4,687 | $ | 4,633 | $ | 470 | $ | 464 | ||||||||
| Interest cost |
5,803 | 5,659 | 1,064 | 1,054 | ||||||||||||
| Expected long-term return on assets |
(7,298 | ) | (6,597 | ) | (1,693 | ) | (1,619 | ) | ||||||||
| Actuarial loss |
2,446 | 2,061 | 140 | 283 | ||||||||||||
| Prior service cost amortization |
33 | 176 | 283 | 92 | ||||||||||||
| Settlement charge |
— | — | 326 | — | ||||||||||||
| Net periodic expense |
$ | 5,671 | $ | 5,932 | $ | 590 | $ | 274 | ||||||||
The settlement charge of $0.3 million for Plan B represents an acceleration of unrecognized losses. In September 2006 and October 2006, the Company made discretionary contributions of $10 million and $7 million, respectively, to Plan A. The Company is not required to make pension contributions and does not currently plan to make any additional discretionary contributions during 2006.
The components of net periodic post-retirement benefit expense for the Company’s post-retirement benefit plans were:
| (in thousands) |
Salaried Employees | Union Employees | ||||||||||||||
| Three Months Ended September 30, |
Three Months Ended September 30, |
|||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
| Components of net periodic benefit cost: |
||||||||||||||||
| Service cost |
$ | 152 | $ | 231 | $ | 152 | $ | 124 | ||||||||
| Interest cost |
406 | 492 | 514 | 515 | ||||||||||||
| Expected long-term return on assets |
(480 | ) | (425 | ) | (734 | ) | (658 | ) | ||||||||
| Actuarial gain |
(172 | ) | (32 | ) | (48 | ) | (36 | ) | ||||||||
| Prior service cost amortization |
— | — | — | 1 | ||||||||||||
| Transition amortization |
170 | 171 | 309 | 321 | ||||||||||||
| Net periodic expense |
$ | 76 | $ | 437 | $ | 193 | $ | 267 | ||||||||
| (in thousands) |
Salaried Employees | Union Employees | ||||||||||||||
| Nine months Ended September 30, |
Nine months Ended September 30, |
|||||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||||
| Components of net periodic benefit cost: |
||||||||||||||||
| Service cost |
$ | 456 | $ | 694 | $ | 456 | $ | 373 | ||||||||
| Interest cost |
1,218 | 1,477 | 1,543 | 1,546 | ||||||||||||
| Expected long-term return on assets |
(1,441 | ) | (1,277 | ) | (2,202 | ) | (1,975 | ) | ||||||||
| Actuarial gain |
(518 | ) | (96 | ) | (145 | ) | (110 | ) | ||||||||
| Prior service cost amortization |
— | — | — | 3 | ||||||||||||
| Transition amortization |
512 | 512 | 926 | 964 | ||||||||||||
| Net periodic expense |
$ | 227 | $ | 1,310 | $ | 578 | $ | 801 | ||||||||
For the three months and nine months ended September 30, 2006, the Company made contributions aggregating $0.5 million and $1.5 million, respectively, to the post-retirement benefit plan assets. The Company expects to make additional discretionary contributions of approximately $0.5 million through the remainder of 2006.
21
10. COMMITMENTS AND CONTINGENCIES
Commitments and Agreements: Certain of Alagasco’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $208.4 million through October 2015. Alagasco also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are 149.9 Bcf through April 2015.
Alagasco purchases gas as an agent for certain of its large commercial and industrial customers. Alagasco has in certain instances provided commodity-related guarantees to the counterparties in order to facilitate these agency purchases. Liabilities existing for gas delivered to customers subject to these guarantees are included in the consolidated balance sheet. In the event the customer for whom the guarantee was entered fails to take delivery of the gas, Alagasco can sell such gas for the customer, with the customer liable for any resulting loss. Although the substantial majority of purchases under these guarantees are for the customers’ current monthly consumption and are at current market prices, in some instances, the purchases are for an extended term at a fixed price. At September 30, 2006, the fixed price purchases under these guarantees had a maximum term outstanding through July 2007 and an aggregate purchase price of $10.5 million with a market value of $7.9 million.
Legal Matters: Energen and its affiliates are, from time to time, parties to various pending or threatened legal proceedings. Certain of these lawsuits include claims for punitive damages in addition to other specified relief. Based upon information presently available, and in light of available legal and other defenses, contingent liabilities arising from threatened and pending litigation are not considered material in relation to the respective financial positions of Energen and its affiliates. It should be noted, however, that Energen and its affiliates conduct business in Alabama and other jurisdictions in which the magnitude and frequency of punitive and other damage awards may bear little or no relation to culpability or actual damages, thus making it difficult to predict litigation results.
Cochran County, Texas
In January 2005, a lawsuit was tried in Cochran County, Texas in which the plaintiff alleged preferential purchase right claims against Energen Resources with respect to certain properties acquired by Energen Resources in 2002. The jury rendered a verdict in Energen Resources’ favor on all counts. Subsequently, in March 2005, the Judge issued a decision overruling the jury verdict. Energen Resources’ appealed the Judge’s order to the Court of Appeals for the Seventh District of Texas. In May 2006, the Court of Appeals reversed the Judge’s decision and entered a judgment in favor of Energen Resources. The plaintiff filed a Petition for Review with the Texas Supreme Court which was denied on October 27, 2006.
Jefferson County, Alabama
In January 2006, RGGS Land and Minerals LTD, L.P. (RGGS) filed a lawsuit in Jefferson County, Alabama, alleging breach of contract with respect to Energen Resources’ calculation of certain allowed costs and failure to pay in a timely manner certain amounts due RGGS under a mineral lease. RGGS seeks a declaratory judgment with respect to the parties’ rights under the lease, reformation of the lease, monetary damages and termination of Energen Resources’ rights under the lease. The Occluded Gas Lease dated January 1, 1986 was originally between Energen Resources and United States Steel Corporation (U.S. Steel) as lessor. RGGS became the lessor under the lease as a result of a 2004 conveyance from U.S. Steel to RGGS. Approximately 120,000 acres in Jefferson and Tuscaloosa counties, Alabama, are subject to the lease. Separately on February 6, 2006, Energen Resources received notice of immediate lease termination from RGGS. As of December 31, 2005, Energen’s consolidated balance sheet included approximately $96 million in net oil and gas properties associated with the lease. During 2005, Energen Resources’ production associated with the lease was approximately 11 Bcf.
RGGS has adopted positions contrary to the seventeen years of course of dealing between Energen Resources and its original contracting partner, U.S. Steel. The Company believes that RGGS’ assertions are without merit and that the notice of lease termination is ineffective. Energen Resources intends to vigorously defend its rights under the lease. The Company remains in possession of the lease, believes that the likelihood of a judgment in favor of RGGS is remote, and has made no accrual with respect to the litigation or purported lease termination.
22
Enron Corporation (Enron)
Enron and Enron North America Corporation (ENA) and Energen Resources and Alagasco have agreed to a settlement and release of their respective claims in the Enron and ENA bankruptcy proceedings. Under the proposed settlement, which remains subject to Bankruptcy Court approval, Energen Resources will have allowed claims in the bankruptcy cases against Enron and ENA of $12.5 million each. The actual amounts and timings of any recoveries of the allowed claims remain subject to a number of variables and the Company has made no accrual for the estimated recoveries.
Other
Various other pending or threatened legal proceedings are in progress currently, and the Company has accrued a provision for estimated liability.
Environmental Matters: Various environmental laws and regulations apply to the operations of Energen Resources and Alagasco. Historically, the cost of environmental compliance has not materially affected the Company’s financial position, results of operations or cash flows and is not expected to do so in the future; however, new regulations, enforcement policies, claims for damages or other events could result in significant unanticipated costs.
Environmental compliance costs, including ongoing maintenance, monitoring and similar costs, are expensed as incurred. Environmental remediation costs are accrued when remedial efforts are probable and the cost can be reasonably estimated.
Alagasco is in the chain of title of nine former manufactured gas plant sites (four of which it still owns) and five manufactured gas distribution sites (one of which it still owns). An investigation of the sites does not indicate the present need for remediation activities. Management expects that, should remediation of any such sites be required in the future, Alagasco’s share, if any, of such costs will not materially affect the financial position, results of operations or cash flows of Alagasco.
11. REGULATORY ASSETS AND LIABILITIES
The following table details regulatory assets and liabilities on the balance sheets:
| (in thousands) |
September 30, 2006 | December 31, 2005 | ||||||||||
| Current | Noncurrent | Current | Noncurrent | |||||||||
| Regulatory assets: |
||||||||||||
| Pension asset |
$ | — | $ | — | $ | — | $ | 22,807 | ||||
| Accretion and depreciation for asset retirement obligation |
— | 10,920 | — | 10,183 | ||||||||
| Gas supply adjustment |
18,110 | — | — | — | ||||||||
| Risk management activities |
29,491 | — | 6,291 | — | ||||||||
| Other |
342 | 190 | 342 | 446 | ||||||||
| Total regulatory assets |
$ | 47,943 | $ | 11,110 | $ | 6,633 | $ | 33,436 | ||||
| Regulatory liabilities: |
||||||||||||
| Enhanced stability reserve |
$ | 3,948 | $ | — | $ | 3,690 | $ | — | ||||
| Gas supply adjustment |
— | — | 22,326 | — | ||||||||
| RSE adjustment |
1,584 | — | 2,943 | — | ||||||||
| Unbilled service margin |
4,559 | — | 24,537 | — | ||||||||
| Asset removal costs, net |
— | 111,738 | — | 105,404 | ||||||||
| Asset retirement obligation |
— | 14,031 | — | 13,451 | ||||||||
| Other |
— | 908 | — | 953 | ||||||||
| Total regulatory liabilities |
$ | 10,091 | $ | 126,677 | $ | 53,496 | $ | 119,808 | ||||
23
12. ACQUISITION AND DISPOSITIONS OF OIL AND GAS PROPERTIES
On December 15, 2005, Energen Resources completed a purchase of Permian Basin oil properties from a private company. The contract purchase price was approximately $168 million with an effective date of November 1, 2005. Approximately 80 percent of the 21.9 million barrels of proved oil reserves are undeveloped. More than 90 percent of the estimated proved reserves are oil. Energen used its available cash and existing lines of credit to finance the acquisition.
In September 2006, Energen Resources signed a purchase and sale agreement expanding it operations in the San Juan Basin with the acquisition of approximately 30 Bcfe of proved and probable reserves from Dominion Resources Inc. effective December 1, 2006 for approximately $30 million.
In October 2006, Energen Resources sold a 50 percent interest in its lease position in various shale plays in Alabama to Chesapeake Energy Corporation (Chesapeake) for cash and a carried drilling interest. In addition, the two companies have signed an agreement to form an area of mutual interest (AMI) to focus on the further exploration and development of these shale plays throughout Alabama and a part of Georgia. Energen Resources received $75 million in cash from Chesapeake for a 50 percent interest in Energen Resources’ existing shale lease position of approximately 200,000 net acres in Alabama. Chesapeake also will pay for Energen Resources’ first $15 million of future drilling costs.
13. RECENT PRONOUNCEMENTS OF THE FINANCIAL ACCOUNTING STANDARDS BOARD (FASB)
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109 (FIN 48).” This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition, measurement and disclosure of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying this Interpretation will be recorded as an adjustment to retained earnings as of the beginning of the period of adoption. The impact of this Interpretation on the Company is currently being evaluated.
The FASB ratified the consensus reached by the Emerging Issues Task Force (EITF) in Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation),” during June 2006. The scope of EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing activity between a seller and a customer, and may include, but is not limited to, sales, use, value added, and some excise taxes. EITF 06-3 concluded that the presentation of taxes within its scope on either a gross (included in revenue and cost) or net (excluded from revenue) basis is an accounting policy decision and requires only appropriate disclosure retrospectively to interim and annual financial statements for all periods presented if the amounts are significant. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006. The Company is currently evaluating any disclosure requirements of this interpretation.
During September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or a liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS No. 157, fair value measurements would be separately disclosed by level within the fair value hierarchy effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of this Statement and does not expect it to be material.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R) (SFAS No. 158).” This Standard requires an employer to recognize the net funded status of a defined benefit pension and other postretirement benefit plans (benefit plans) as an asset or liability in its statement of financial position and to recognize changes in the funded status through comprehensive income in the year in which the changes occur. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. The Company is required to recognize the funded status of benefit plans and to provide the required disclosures prospectively as of the end of the fiscal year ending after December 15, 2006. Alagasco anticipates it will establish a regulatory asset for the portion of the total benefit obligation to be recovered through rates in future periods in accordance with SFAS No. 71. Upon adoption of this Statement, the Company expects to increase its net obligation for underfunded benefit plans by approximately $35 million, increase its regulatory asset by approximately $37 million and reduce shareholders’ equity by approximately $18 million after-tax. In addition, the Company anticipates recording an asset for overfunded plans of approximately $4 million. SFAS No. 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position effective for fiscal years ending after December 15, 2008. The Company currently uses a September 30 valuation date.
24
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Energen’s net income totaled $41.4 million ($0.56 per diluted share) for the three months ended September 30, 2006 and compared favorably with net income of $19.1 million ($0.26 per diluted share) for the same period in the prior year. Energen Resources Corporation, Energen’s oil and gas subsidiary, had net income for the three months ended September 30, 2006, of $49.9 million compared with $28.1 million in the same quarter in the previous year. Energen Resources reported income from continuing operations of $49.8 million in the current quarter as compared with $28.1 million in the same quarter last year. Significantly higher commodity prices (approximately $26 million after-tax) and increased production volumes (approximately $3 million after-tax) were partially offset by increased lease operating expenses (approximately $5 million after-tax). Energen’s natural gas utility, Alagasco, reported a net loss of $7.7 million in the third quarter of 2006 compared to a net loss of $8.8 million in the same period last year primarily due to the utility’s ability to earn on a higher level of equity.
For the 2006 year-to-date, Energen’s net income totaled $178.4 million ($2.42 per diluted share) and compared favorably to net income of $115.7 million ($1.57 per diluted share) for the same period in the prior year. Energen Resources had net income for the nine months ended September 30, 2006, of $150.1 million as compared with $84 million in the previous period. Energen Resources generated income from continuing operations of $150 million in the current year-to-date as compared with $83.9 million in the same period last year primarily as a result of higher commodity prices (approximately $81 million after-tax) and increased production volumes (approximately $11 million after-tax) partially offset by the impact of increased lease operating expenses (approximately $16 million after-tax), higher production taxes (approximately $2 million after-tax), increased depreciation, depletion and amortization (DD&A) expense (approximately $3 million after-tax) and increased administrative expenses (approximately $3 million after-tax). Alagasco’s net income of $29.2 million in the current year-to-date compared to net income of $31.3 million in the same period in the previous year primarily reflecting a decrease in customer usage partially offset by the utility’s ability to earn on a higher level of equity.
Oil and Gas Operations
Revenues from oil and gas operations rose 35.8 percent to $171.5 million for the three months ended September 30, 2006 and 40.3 percent to $510.2 million in the year-to-date largely as a result of increased commodity prices as well as the impact of higher production volumes. During the current quarter, revenue per unit of production for natural gas rose 28.1 percent to $6.80 per thousand cubic feet (Mcf), while oil revenue per unit of production increased 44.8 percent to $51.43 per barrel. Natural gas liquids revenue per unit of production increased 22 percent to an average price of $0.72 per gallon. In the year-to-date, revenue per unit of production for natural gas increased 30.6 percent to $7.04 per Mcf, oil revenue per unit of production increased 47.4 percent to $49.75 per barrel and natural gas liquids revenue per unit of production rose 24.1 percent to $0.67 per gallon.
Production increased primarily due to additional development activities in the San Juan Basin, accelerated workovers due to milder winter weather and increased volumes related to the prior year purchase of Permian Basin oil properties. Energen Resources acquired an estimated 21.9 million barrels of proved oil reserves in the Permian Basin in the fourth quarter of 2005. Negatively affecting production were normal production declines. Natural gas production from continuing operations in the third quarter remained relatively stable at 16 billion cubic feet (Bcf), while oil volumes increased 11.3 percent to 905 thousand barrels (MBbl) and natural gas liquids production increased 12.7 percent to 20.4 million gallons (MMgal). For the year-to-date, natural gas production from continuing operations increased 2.6 percent to 47.1 Bcf, oil volumes rose 10.3 percent to 2,736 MBbl and natural gas liquids production increased 8.8 percent to 57.1 MMgal. Natural gas comprised approximately 65 percent of Energen Resources’ production for the current quarter and the year-to-date.
Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. Energen Resources applies SFAS No. 133 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 effectiveness of the hedge, or the degree that the gain (loss) for the hedging instrument offsets the loss (gain) on the hedged item is measured 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 operating revenues 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 operating revenues in the period of change. For the three months and nine months ended September 30, 2006, the Company recorded a $0.4 million after-tax gain and a $0.9 million after-tax loss, respectively, on open and closed contracts for the ineffective portion of the change in fair value of derivatives accounted for as cash flow hedges.
25
Operations and maintenance (O&M) expense increased $11.3 million for the quarter and $32.1 million in the year-to-date. Lease operating expense (excluding production taxes) increased by $7.9 million for the quarter and $25.3 million year-to-date primarily due to maintenance expense in the San Juan Basin designed to increase production and accelerated as a result of milder weather, higher transportation costs, overall price increases related to higher commodity prices and the December 2005 acquisition of Permian Basin oil properties. Administrative expense increased $1.5 million for the three months ended September 30, 2006 and $3.9 million year-to-date largely due to labor-related costs. Exploration expense rose $1.9 million in the third quarter and $2.9 million in the year-to-date primarily due to increased exploratory efforts.
Energen Resources’ DD&A expense for the quarter increased $0.9 million and rose $4.6 million year-to-date. The average depletion rate for the current quarter and the same period a year ago was $0.98 per Mcfe. For the nine months ended September 30, 2006, the average depletion rate was $0.98 per Mcfe as compared to $0.96 per Mcfe in the previous period. The increase in the year-to-date rate was largely due to a higher depletion rate on oil properties purchased in the Permian Basin in December 2005 partially offset by increased production in lower rate areas.
Energen Resources’ expense for taxes other than income taxes primarily reflected production-related taxes that were $0.9 million lower this quarter primarily due to decreased commodity market prices, which exclude the effects of derivative instruments, largely offset by increased production. In the year-to-date, production taxes were $2.9 million higher year-to-date largely due to increased commodity market prices and production.
Energen Resources may, in the ordinary course of business, be involved in the sale of developed or undeveloped properties. With respect to developed properties, sales may occur as a result of, but not limited to, disposing of non-strategic or marginal assets and accepting offers where the buyer gives greater value to a property than does Energen Resources. The Company is required to reflect gains and losses on the dispositions of these assets, the impairments on certain properties held-for-sale, and income or loss from the operations of the associated held-for-sale properties as discontinued operations under the provisions of SFAS No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets.” Energen Resources had no property sales during the three months ended September 30, 2006 and 2005 or the year-to-date ended September 30, 2006. In the nine months ended September 30, 2005, Energen Resources recorded a pre-tax gain of $194,000 primarily from a property sale located in the Permian Basin.
Natural Gas Distribution
Natural gas distribution revenues increased $6.8 million for the quarter largely due to an increase in commodity gas costs partially offset by a decrease in customer usage. In addition, Alagasco had a $1.8 million benefit to revenue in period comparisons related to various components of the utility’s rate setting methodology at the end of the fiscal year for rate-setting purposes. Alagasco’s O&M expense per customer exceeded its inflation-based cost control measure at the end of the 2006 rate year. The resulting $1.5 million revenue reduction at September 30, 2006, was less than a $3.3 million revenue reduction to bring the utility’s return on average equity to midpoint at September 30, 2005. For the quarter, weather was comparable with the same period last year. Residential sales volumes declined 11.5 percent and commercial and industrial customer sales volumes decreased 14.3 percent largely due to a decrease in the number of customers and a decline in per customer usage. Transportation volumes rose 8.8 percent in period comparisons. Revenues for the year-to-date rose $73.3 million primarily due to a significant increase in the commodity cost of gas partially offset by a decrease in usage. Weather that was 4.9 percent warmer than in the previous period along with customer conservation related to higher gas costs contributed to a 12.7 percent decrease in residential sales volumes. Commercial and industrial customer sales volumes decreased 9.9 percent while transportation volumes increased 1 percent in period comparisons. An increase in gas costs partially offset by a decline in gas purchase volumes resulted in a 15.2 percent increase in cost of gas for the quarter and a 31.4 percent increase in the year-to-date. Utility gas costs include commodity cost, risk management gains and losses and the provisions of the GSA rider. The GSA rider in Alagasco’s rate schedule provides for a pass-through of gas price fluctuations to customers without markup. Alagasco’s tariff provides a temperature adjustment to certain customers’ bills designed to substantially remove the effect of departures from normal temperatures. The temperature adjustment applies primarily to residential, small commercial and small industrial customers.
26
As discussed more fully in Note 3 to the Unaudited Condensed Financial Statements, Alagasco is subject to regulation by the Alabama Public Service Commission (APSC). On June 10, 2002, the APSC issued an order to extend Alagasco’s rate-setting mechanism. Under the terms of that extension, RSE will continue after January 1, 2008, unless, after notice to Alagasco and a hearing, the Commission votes to either modify or discontinue its operation.
O&M expense decreased 1.8 percent in the current quarter primarily due to decreased bad debt expense and labor-related expenses partially offset by higher insurance costs. In the nine months ended September 30, 2006, O&M rose 4 percent largely due to increased insurance costs, bad debt expense and distribution maintenance expenses partially offset by decreased labor-related expenses. A 5 percent increase in depreciation expense in the current quarter and a 3.6 percent increase in the year-to-date was primarily due to normal replacement of the utility’s distribution and support systems. Taxes other than income taxes primarily reflected various state and local business taxes as well as payroll-related taxes. State and local business taxes generally are based on gross receipts and fluctuate accordingly.
Non-Operating Items
Interest expense for the Company increased $0.7 million in the third quarter and $3 million year-to-date primarily due to an increase in short-term borrowings related to the December 2005 purchase of Permian Basin oil properties at Energen Resources. Also influencing interest expense was an increase in interest rates associated with Energen’s $100 million Floating Rate Senior Notes issued in November 2004. An increase in interest expense related to Alagasco’s issuance of $80 million of long-term debt in November 2005 was partially offset by the redemption of $56.7 million of long-term debt by Alagasco in December 2005. Income tax expense for the Company increased $11.2 million in the current quarter and $33.6 million in the year-to-date largely due to higher pre-tax income.
Stock-Based Compensation
In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123 (revised 2004), “Share-Based Payment” (SFAS No. 123R), which requires a fair value based method of accounting using pricing models that reflect the specific economics of a company’s transactions. This statement was effective for the first annual reporting period beginning after June 15, 2005. The Company prospectively adopted the fair value recognition provisions of SFAS No. 123 as amended, which provided methods of transition for a voluntary change to the fair value base method of accounting for stock-based employee compensation effective January 1, 2003. The Company adopted SFAS No. 123R using the modified prospective application method for new awards effective January 1, 2006. The adoption of SFAS No. 123R did not have a significant impact on the financial condition or results of operations of the Company (See Note 2, Stock-Based Compensation, in the Notes to Unaudited Condensed Financial Statements).
FINANCIAL POSITION AND LIQUIDITY
Cash flows from operations for the year-to-date were $399.9 million as compared to $312.7 million in the prior period. Operating cash flow benefited from higher realized commodity prices and production volumes at Energen Resources. The Company’s working capital needs were also highly influenced by throughput, changes in weather, and timing of payments. Working capital needs at Alagasco were primarily affected by increased gas costs and the timing of recovery of gas costs from customers compared to the prior period.
The Company had a net outflow of cash from investing activities of $213.1 million for the nine months ended September 30, 2006 primarily due to additions of property, plant and equipment. Energen Resources invested $156.6 million in capital expenditures primarily related to the development of oil and gas properties. Utility capital expenditures totaled $58.1 million in the year-to-date and primarily represented expansion and replacement of its distribution system and support facilities.
The Company used $189.9 million for financing activities in the year-to-date primarily due to the repayment of short-term borrowings, dividends paid to common shareholders and the buy-back of Energen common stock under its stock repurchase plan.
27
FUTURE CAPITAL RESOURCES AND LIQUIDITY
For 2006, the Company expects its oil and gas capital spending to total approximately $225 million, including $168 million for the development of existing properties and approximately $30 million for the planned acquisition in December 2006 of an estimated 30 Bcfe of proved and unproved reserves in the San Juan Basin.
As Energen continues to implement its diversified growth strategy, the Company plans to invest significant capital in Energen Resources’s oil and gas production operations. In the three-year period ending December 31, 2009, the Company expects to invest approximately $620 million to develop proved and unproved reserves in its four major areas of operation. The Company also may allocate additional capital during this three-year period for other oil and gas activities such as property acquisitions and the exploration and development of potential shale plays primarily in Alabama.
To finance capital spending at Energen Resources, the Company primarily expects to use internally generated cash flow supplemented by its short-term credit facilities. The Company also may issue long-term debt and equity periodically to replace short-term obligations, enhance liquidity and provide for permanent financing. Energen currently has available short-term credit facilities aggregating $410 million to help finance its growth plans and operating needs.
In October 2006, Energen Resources sold to Chesapeake Energy Corporation (Chesapeake) a 50 percent interest in its lease position of approximately 200,000 acres in various shale plays in Alabama for $75 million and a $15 million carried drilling interest. In addition, the two companies signed an agreement to form an area of mutual interest (AMI) through which they will partner on a 50-50 basis, for at least the next 10 years, to secure new leases and pursue exploration, development and operations. The Company has not included in its capital spending estimates any amounts associated with potential development and/or exploratory drilling in the AMI. Energen Resources anticipates a gain of approximately $50 to $60 million pre-tax in the fourth quarter of 2006 resulting from this sale of its lease position.
Energen plans to consider stock repurchases as a capital investment option over the next 24-30 months. In May 2006, Energen began the buy-back of its common stock under an existing stock repurchase plan. In June 2006, the Company’s Board of Directors authorized an additional 9 million shares of common stock for repurchase. Energen may buy shares from time to time on the open market or in negotiated purchases. The timing and amounts of any repurchases are subject to changes in market conditions. Through November 6, 2006, the Company purchased 1.6 million shares at an average price of $37.46 per share. The Company plans to continue utilizing internally generated cash flow to fund its stock repurchases.
Energen Resources has experienced various market driven conditions generally caused by the increased commodity price environment including, but not limited to, higher workover and maintenance expenses, increased taxes and other field-service-related expenses. The Company anticipates influences such as weather, natural disasters, changes in global economics and political unrest will continue to contribute to increased price volatility in the near term.
Energen Resources hedges its exposure to estimated commodity 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 may 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 collateral must be posted for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. In cases where this arrangement exists, generally the credit ratings must be maintained at investment grade status to have any available counterparty credit. Adverse changes to the Company’s credit rating will result in decreasing amounts of credit available under these contracts. The counterparties for these contracts do not extend credit to the Company in the event credit ratings are below investment grade. At September 30, 2006, Energen Resources was in a net gain position with all but one of its counterparties and was not required to post collateral. Energen Resources used various counterparties for its over-the-counter derivatives as of September 30, 2006. The Company believes the creditworthiness of these counterparties is satisfactory. These hedge transactions are pursuant to standing authorizations by the Board of Directors, which do not permit speculative positions.
28
Energen Resources entered into the following transactions for the remainder of 2006 and subsequent years:
| Production Period |
Total Hedged Volumes |
Average Contract Price |
Description | |||||
| Natural Gas | ||||||||
| 2006 |
3.9 Bcf | $8.03 Mcf | NYMEX Swaps | |||||
| 5.4 Bcf | $6.45 Mcf | Basin Specific Swaps | ||||||
| 2007 |
11.4 Bcf | $9.43 Mcf | NYMEX Swaps | |||||
| 22.7 Bcf | $8.14 Mcf | Basin Specific Swaps | ||||||
| Oil |
||||||||
| 2006 |
691 MBbl | $52.58 Bbl | NYMEX Swaps | |||||
| 2007 |
2,716 MBbl | $70.01 Bbl | NYMEX Swaps | |||||
| 2008 |
1,920 MBbl | $66.89 Bbl | NYMEX Swaps | |||||
| 2009 |
900 MBbl | $56.25 Bbl | NYMEX Swaps | |||||
| Oil Basis Differential |
||||||||
| 2006 |
469 MBbl | ** | Basis Swaps | |||||
| 2007 |
1,768 MBbl | ** | Basis Swaps | |||||
| 2007 |
*600 MBbl | ** | Basis Swaps | |||||
| 2008 |
1,020 MBbl | ** | Basis Swaps | |||||
| Natural Gas Liquids |
||||||||
| 2006 |
7.6 MMGal | $0.56 Gal | Liquids Swaps | |||||
| 2007 |
41.8 MMGal | $0.93 Gal | Liquids Swaps | |||||
| * |
Contracts entered into subsequent to September 30, 2006. |
| ** |
Average contract prices are not meaningful due to the varying nature of each contract. |
Realized prices are anticipated to be lower than NYMEX prices due to basis differences and other factors.
The Company’s efforts to minimize commodity price volatility through hedging is reflected in Alagasco’s current rates. Alagasco’s rate schedules for natural gas distribution charges contain a Gas Supply Adjustment (GSA) rider which permits the pass-through to customers for changes in the cost of gas supply. The GSA rider is designed to capture the Company’s cost of natural gas and provides for a pass-through of gas cost fluctuations to customers without markup; the cost of gas includes the commodity cost, pipeline capacity, transportation and fuel costs, and risk management gains and losses. Sustained high prices may decrease Alagasco’s customer base and could result in a decline of per customer use and number of customers. The utility will continue to monitor its bad debt reserve and will make adjustments as required based on the evaluation of its receivables which are impacted by natural gas prices.
Alagasco maintains an investment in storage gas that is expected to average approximately $69 million in 2006 but will vary depending upon the price of natural gas. During 2006, Alagasco plans to invest an estimated $72 million in utility capital expenditures for normal distribution and support systems. Over the three-year period ending December 31, 2009, Alagasco anticipates capital investments of approximately $190 million. The utility anticipates funding these capital requirements through internally generated capital and the utilization of short-term credit facilities. Subject to market conditions, Alagasco may issue $45 million in long-term debt in the fourth quarter of 2006 and recall approximately $45 million in the same quarter in order to capitalize on lower interest rates. In January 2005, Alagasco issued $80 million in long-term debt to repay amounts drawn on short-term credit facilities for capital expenditures and to refinance $30 million of Medium-Term Notes recalled by Alagasco in April 2004. In November 2005, Alagasco issued an additional $80 million of long-term debt. This debt largely refinanced $18 million of Medium-Term Notes maturing June 27, 2007 to July 5, 2022 and $56.7 million of long-term debt maturing June 15, 2015 to June 27, 2025 recalled by Alagasco in August 2005 and December 2005, respectively.
Access to capital is an integral part of the Company’s business plan. The Company regularly provides information to corporate rating agencies related to current business activities and future performance expectations. While the Company expects to have ongoing access to its short-term credit facilities and the broader long-term markets, continued access could be adversely affected by future economic and business conditions and credit rating downgrades.
29
Dividends
Energen expects to pay annual cash dividends of $0.44 per share on the Company’s common stock in 2006. The amount and timing of all dividend payments is subject to the discretion of the Board of Directors and is based upon business conditions, results of operations, financial conditions and other factors.
On April 27, 2005, Energen’s shareholders approved a 2-for-1 split of the Company’s common stock. The split was effected in the form of a 100 percent stock dividend and was effective on June 1, 2005, to shareholders of record on May 13, 2005. All share and per share amounts of capital stock outstanding have been adjusted to reflect the stock split.
Contractual Cash Obligations and Other Commitments
In the course of ordinary business activities, Energen enters into a variety of contractual cash obligations and other commitments. The following table summarizes the Company’s significant contractual cash obligations, other than hedging contracts, as of September 30, 2006.
| Payments Due before December 31, | |||||||||||||||
| (in thousands) |
Total | 2006 | 2007 & 2008 |
2009 & 2010 |
2011 & Thereafter | ||||||||||
| Short-term debt |
$ | 42,000 | $ | 42,000 | $ | — | $ | — | $ | — | |||||
| Long-term debt (1) |
684,254 | — | 110,000 | 150,000 | 424,254 | ||||||||||
| Interest payments on debt (2) |
545,185 | 44,613 | 82,241 | 76,131 | 342,200 | ||||||||||
| Purchase obligations (3) |
208,395 | 13,351 | 95,621 | 70,218 | 29,205 | ||||||||||
| Capital lease obligations |
— | — | — | — | — | ||||||||||
| Operating leases |
47,160 | 999 | 7,095 | 6,356 | 32,710 | ||||||||||
| Total contractual cash obligations |
$ | 1,526,994 | $ | 100,963 | $ | 294,957 | $ | 302,705 | $ | 828,369 | |||||
| (1) |
Long-term cash obligations include $1.3 million of unamortized debt discounts as of September 30, 2006. |
| (2) |
Includes interest on fixed rate debt and an estimate of adjustable rate debt. The adjustable rate interest is calculated based on the indexed rate in effect at September 30, 2006. |
| (3) |
Certain of the Company’s long-term gas procurement contracts for the supply, storage and delivery of natural gas include fixed charges of approximately $208.4 million through October 2015. The Company also is committed to purchase minimum quantities of gas at market-related prices or to pay certain costs in the event the minimum quantities are not taken. These purchase commitments are 149.9 Bcf through April 2015. |
Energen Resources operates in certain instances through joint ventures under joint operating agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a working interest basis as defined in the joint operating contractual agreement.
The Company has two defined non-contributory pension plans and provides certain post-retirement healthcare and life insurance benefits. In September 2006 and October 2006, the Company made discretionary pension contributions of $10 million and $7 million, respectively, to Plan A. The Company is not required to make pension contributions and does not currently plan to make any additional discretionary contributions during 2006. The Company expects to make discretionary payments of approximately $0.5 million to post-retirement benefit program assets during the remainder of 2006.
Recent Pronouncements of the Financial Accounting Standards Board (FASB)
In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109 (FIN 48).” This Interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition, measurement and disclosure of a tax position taken or expected to be taken in a tax return. FIN 48 is effective for fiscal years beginning after December 15, 2006. The cumulative effect of applying this Interpretation will be recorded as an adjustment to retained earnings as of the beginning of the period of adoption. The impact of this Interpretation on the Company is currently being evaluated.
30
The FASB ratified the consensus reached by the Emerging Issues Task Force (EITF) in Issue No. 06-3, “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement (That Is, Gross versus Net Presentation),” during June 2006. The scope of EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing activity between a seller and a customer, and may include, but is not limited to, sales, use, value added, and some excise taxes. EITF 06-3 concluded that the presentation of taxes within its scope on either a gross (included in revenue and cost) or net (excluded from revenue) basis is an accounting policy decision and requires only appropriate disclosure retrospectively to interim and annual financial statements for all periods presented if the amounts are significant. EITF 06-3 is effective for interim and annual reporting periods beginning after December 15, 2006. The Company is currently evaluating any disclosure requirements of this interpretation.
During September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which clarifies the principle that fair value should be based on the assumptions market participants would use when pricing an asset or a liability and establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under SFAS No. 157, fair value measurements would be separately disclosed by level within the fair value hierarchy effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the impact of this Statement and does not expect it to be material.
In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132 (R) (SFAS No. 158).” This Standard requires an employer to recognize the net funded status of a defined benefit pension and other postretirement benefit plans (benefit plans) as an asset or liability in its statement of financial position and to recognize changes in the funded status through comprehensive income in the year in which the changes occur. For pension plans, the benefit obligation is the projected benefit obligation; for other postretirement plans, the benefit obligation is the accumulated postretirement benefit obligation. The Company is required to recognize the funded status of benefit plans and to provide the required disclosures prospectively as of the end of the fiscal year ending after December 15, 2006. Alagasco anticipates it will establish a regulatory asset for the portion of the total benefit obligation to be recovered through rates in future periods in accordance with SFAS No. 71. Upon adoption of this Statement, the Company expects to increase its net obligation for underfunded benefit plans by approximately $35 million, increase its regulatory asset by approximately $37 million and reduce shareholders’ equity by approximately $18 million after-tax. In addition, the Company anticipates recording an asset for overfunded plans of approximately $4 million. SFAS No. 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position effective for fiscal years ending after December 15, 2008. The Company currently uses a September 30 valuation date.
FORWARD LOOKING STATEMENTS
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 forward-looking statements do not reflect the impact of possible or pending acquisitions, divestitures or restructurings. The absence of errors in input data, calculations and formulas used in estimates, assumptions and forecasts cannot be guaranteed. Neither the Company nor Alagasco undertakes any 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, our ability to access the capital markets, future business decisions, utility customer growth and retention and usage per customer, litigation results and other uncertainties, all of which are difficult to predict.
31
Third Party Facilities: The forward-looking statements assume generally uninterrupted access to third party oil, gas and natural gas liquid gathering, transportation, processing and storage facilities. Energen Resources relies upon such facilities for access to markets for its production. Alagasco relies upon such facilities for access to natural gas supplies. Such facilities are typically limited in number and geographically concentrated. An extended interruption of access to or service from these facilities, whether caused by weather events, natural disaster, accident, mechanical failure, criminal act or otherwise could result in material adverse financial consequences to Alagasco, Energen Resources and/or the Company.
Energen Resources Production: 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.
Energen Resources Hedging: Although Energen Resources makes use of futures, swaps, options and fixed-price contracts to mitigate price risk, fluctuations in future commodity prices could materially affect the Company’s financial position, results of operations and cash flows; 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. The effectiveness of such risk-mitigation assumes that counterparties maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that actual sales volumes will generally meet or exceed the volumes subject to the futures, swaps, options and fixed-price contracts. A substantial failure to meet sales volume targets, whether caused by miscalculations, weather events, natural disaster, accident, criminal act or otherwise, could leave Energen Resources financially exposed to its counterparties and result in material adverse financial consequences to Energen Resources and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Energen Resources’ position.
Alagasco Hedging: Similarly, although Alagasco makes use of futures, swaps and fixed-price contracts to mitigate gas supply cost risk, fluctuations in future gas supply costs could materially affect its financial position and rates to customers. The effectiveness of Alagasco’s risk mitigation assumes that its counterparties in such activities maintain satisfactory credit quality. The effectiveness of such risk mitigation also assumes that Alagasco’s actual gas supply needs will generally meet or exceed the volumes subject to the futures, swaps and fixed-price contracts. A substantial failure to experience projected gas supply needs, whether caused by miscalculations, weather events, natural disaster, accident, mechanical failure, criminal act or otherwise, could leave Alagasco financially exposed to its counterparties and result in material adverse financial consequences to Alagasco and the Company. The adverse effect could be increased if the adverse event was widespread enough to move market prices against Alagasco’s position.
Operations: Inherent in the gas distribution activities of Alagasco and the oil and gas production activities of Energen Resources are a variety of hazards and operation risks, such as leaks, explosions and mechanical problems. These risks or other risks such as weather events, natural disasters, accidents and criminal acts could result in loss of human life, significant damage to property, environmental pollution, impairment of our operations and substantial financial losses to the Company. In accordance with customary industry practices, the Company maintains insurance against some, but not all, of these risks and losses. The location of pipeline and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. The occurrence of any of these events could adversely affect Alagasco’s, Energen Resources’ and/or the Company’s financial position, results of operations and cash flows.
Alagasco Service Territory: Alagasco’s utility customers are geographically concentrated in central and north Alabama. Significant economic, weather, natural disaster, criminal act or other events that adversely affect this region could adversely affect Alagasco and the Company.
32
SELECTED BUSINESS SEGMENT DATA
ENERGEN CORPORATION
(Unaudited)
| (in thousands, except sales price data) |
Three months ended September 30, |
Nine months ended September 30, | ||||||||||||
| 2006 | 2005 | 2006 | 2005 | |||||||||||
| Oil and Gas Operations |
||||||||||||||
| Operating revenues from continuing operations |
||||||||||||||
| Natural gas |
$ | 108,795 | $ | 85,087 | $ | 331,073 | $ | 247,088 | ||||||
| Oil |
46,529 | 28,879 | 136,146 | 83,683 | ||||||||||
| Natural gas liquids |
14,668 | 10,721 | 38,152 | 28,519 | ||||||||||
| Other |
1,524 | 1,573 | 4,842 | 4,278 | ||||||||||
| Total |
$ | 171,516 | $ | 126,260 | $ | 510,213 | $ | 363,568 | ||||||
| Production volumes from continuing operations |
||||||||||||||
| Natural gas (MMcf) |
16,004 | 16,013 | 47,056 | 45,871 | ||||||||||
| Oil (MBbl) |
905 | 813 | 2,736 | 2,480 | ||||||||||
| Natural gas liquids (MMgal) |
20.4 | 18.1 | 57.1 | 52.5 | ||||||||||
| Production volumes from continuing operations (MMcfe) |
24,340 | 23,480 | 71,625 | 68,247 | ||||||||||
| Total production volumes (MMcfe) |
24,340 | 23,478 | 71,624 | 68,303 | ||||||||||
| Revenue per unit of production including effects of all derivative instruments |
||||||||||||||
| Natural gas (Mcf) |
$ | 6.80 | $ | 5.31 | $ | 7.04 | $ | 5.39 | ||||||
| Oil (barrel) |
$ | 51.43 | $ | 35.51 | $ | 49.75 | $ | 33.75 | ||||||
| Natural gas liquids (gallon) |
$ | 0.72 | $ | 0.59 | $ | 0.67 | $ | 0.54 | ||||||
| Revenue per unit of production including effects of qualifying cash flow hedges |
||||||||||||||
| Natural gas (Mcf) |
$ | 6.80 | $ | 6.43 | $ | 7.04 | $ | 5.97 | ||||||
| Oil (barrel) |
$ | 51.43 | $ | 35.51 | $ | 49.75 | $ | 33.75 | ||||||
| Natural gas liquids (gallon) |
$ | 0.72 | $ | 0.59 | $ | 0.67 | $ | 0.54 | ||||||
| Revenue per unit of production excluding effects of all derivative instruments |
||||||||||||||
| Natural gas (Mcf) |
$ | 6.10 | $ | 7.78 | $ | 6.70 | $ | 6.72 | ||||||
| Oil (barrel) |
$ | 64.94 | $ | 58.64 | $ | 61.91 | $ | 50.51 | ||||||
| Natural gas liquids (gallon) |
$ | 0.88 | $ | 0.83 | $ | 0.81 | $ | 0.71 | ||||||
| Other data from continuing operations |
||||||||||||||
| Lease operating expense (LOE) |
||||||||||||||
| LOE and other |
$ | 35,305 | $ | 27,396 | $ | 100,789 | $ | 75,511 | ||||||
| Production taxes |
$ | 12,602 | $ | 13,477 | $ | 38,454 | $ | 35,550 | ||||||
| Total |
$ | 47,907 | $ | 40,873 | $ | 139,243 | $ | 111,061 | ||||||
| Depreciation, depletion and amortization |
$ | 24,475 | $ | 23,547 | $ | 71,592 | $ | 67,017 | ||||||
| Capital expenditures |
$ | 61,049 | $ | 44,209 | $ | 156,606 | $ | 132,718 | ||||||
| Exploration expenditures |
$ | 1,986 | $ | 74 | $ | 3,512 | $ | 568 | ||||||
| Operating income
|
$ | 85,239
|
$ | 52,368
|
$ | 260,916
|
$ | 156,714
| ||||||
| Natural Gas Distribution |
||||||||||||||
| Operating revenues |
||||||||||||||
| Residential |
$ | 36,635 | $ | 33,795 | $ | 322,635 | $ | 276,728 | ||||||
| Commercial and industrial |
22,300 | 21,732 | 139,713 | 116,612 | ||||||||||
| Transportation |
10,115 | 9,378 | 33,111 | 32,652 | ||||||||||
| Other |
2,145 | (484 | ) | 7,555 | 3,754 | |||||||||
| Total |
$ | 71,195 | $ | 64,421 | $ | 503,014 | $ | 429,746 | ||||||
| Gas delivery volumes (MMcf) |
||||||||||||||
| Residential |
1,601 | 1,810 | 16,581 | 18,992 | ||||||||||
| Commercial and industrial |
1,534 | 1,791 | 8,559 | 9,497 | ||||||||||
| Transportation |
12,999 | 11,951 | 37,947 | 37,634 | ||||||||||
| Total |
16,134 | 15,552 | 63,087 | 66,123 | ||||||||||
| Other data |
||||||||||||||
| Depreciation and amortization |
$ | 11,201 | $ | 10,668 | $ | 32,880 | $ | 31,724 | ||||||
| Capital expenditures |
$ | 18,512 | $ | 17,863 | $ | 58,947 | $ | 53,562 | ||||||
| Operating income (loss) |
$ | (8,921 | ) | $ | (11,025 | ) | $ | 57,517 | $ | 61,009 | ||||
33
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Energen Resources’ major market risk exposure is in the pricing applicable to its oil and gas production. Historically, prices received for oil and gas production have been volatile because of seasonal weather patterns, world and national supply-and-demand factors and general economic conditions. Crude oil prices also are affected by quality differentials, by worldwide political developments and by actions of the Organization of Petroleum Exporting Countries. Basis differentials, like the underlying commodity prices, can be volatile because of regional supply-and-demand factors, including seasonal factors and the availability and price of transportation to consuming areas.
Energen Resources periodically enters into derivative commodity instruments that qualify as cash flow hedges under Statement of Financial Accounting Standard (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” to hedge its exposure to price fluctuations to its estimated oil, natural gas and natural gas liquids production. In addition, Alagasco periodically enters into cash flow derivative commodity instruments to hedge its gas supply exposure. Such instruments may 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. These counterparties have been deemed creditworthy by the Company and have agreed in certain instances to post collateral with the Company when unrealized gains on hedges exceed certain specified contractual amounts. Notwithstanding these agreements, the Company is at risk for economic loss based upon the creditworthiness of its counterparties. In some contracts, the amount of credit allowed before Energen Resources and Alagasco must post collateral for out-of-the-money hedges varies depending on the credit rating of the Company or Alagasco. 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. The maximum term over which Energen Resources has hedged exposures to the variability of cash flows is through December 31, 2009.
A failure to meet sales volume targets at Energen Resources or gas supply targets at Alagasco due to miscalculations, weather events, natural disasters, accidents, mechanical failure, criminal act or otherwise could leave the Company or Alagasco exposed to its counterparties in commodity hedging contracts and result in material adverse financial losses.
See Note 4, Derivative Commodity Instruments, in the Notes to the Unaudited Condensed Financial Statements for details related to the Company’s hedging activities.
The Company’s interest rate exposure as of September 30, 2006, was minimal since approximately 85 percent of long-term debt obligations were at fixed rates.
34
ITEM 4. CONTROLS AND PROCEDURES
| (a) |
Our chief executive officer and chief financial officer have evaluated the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation they have concluded that our disclosure controls and procedures are effective at a reasonable assurance level. |
| (b) |
Our chief executive officer and chief financial officer have concluded that during the period covered by this report there were no changes in our internal controls that materially affected or are reasonably likely to materially affect our internal control over financial reporting. |
35
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS*
| Period |
Total Number of Shares Purchased |
Average Price Paid per Share |
Total Number of or Programs |
Maximum Number of Shares | |||||
| July 1, 2006 through |
35,000 | $ | 37.75 | 35,000 | 10,146,700 | ||||
| August 1, 2006 through |
154,000 | $ | 42.36 | 154,000 | 9,992,700 | ||||
| September 1, 2006 through |
— | — | — | 9,992,700 | |||||
| Total |
189,000 | $ | 41.51 | 189,000 | 9,992,700 | ||||
| * |
Acquired in connection with tax withholdings and payment of exercise price on stock compensation plans. |
| ** |
By resolution adopted May 24, 1994, and supplemented by resolutions adopted April 26, 2000 and June 24, 2006, the Board of Directors authorized the Company to repurchase up to 12,564,400 shares of the Company’s common stock. The resolutions do not have an expiration date. |
| 31 | (a) | - Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a) | |
| 31 | (b) | - Section 302 Certificate required by Rule 13a-14(a) or Rule 15d-14(a) | |
| 32 | - Section 906 Certificate pursuant to 18 U.S.C. Section 1350 | ||
36
Pursuant to the requirements of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| ENERGEN CORPORATION ALABAMA GAS CORPORATION | ||||||
| November 7, 2006 |
By |
/s/ Wm. Michael Warren, Jr. | ||||
| Wm. Michael Warren, Jr. | ||||||
| Chairman and Chief Executive Officer | ||||||
| of Energen Corporation, Chairman and Chief Executive Officer of Alabama Gas Corporation | ||||||
| November 7, 2006 |
By |
/s/ G. C. Ketcham | ||||
| G. C. Ketcham | ||||||
| Executive Vice President, Chief | ||||||
| Financial Officer and Treasurer of | ||||||
| Energen Corporation and Alabama Gas | ||||||
| Corporation | ||||||
| November 7, 2006 |
By |
/s/ Grace B. Carr | ||||
| Grace B. Carr | ||||||
| Vice President and Controller of Energen | ||||||
| Corporation | ||||||
| November 7, 2006 |
By |
/s/ Paula H. Rushing | ||||
| Paula H. Rushing | ||||||
| Vice President-Finance of Alabama Gas | ||||||
| Corporation | ||||||
37
(This page intentionally left blank.)
38