UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.D. C. 20549
FORM 10-Q
(Mark One)
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2005Quarterly Period Ended March 31, 2006
OrOR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number: 001-7940
For the transition period fromto
Commission File Number: 1-7940
Goodrich Petroleum CorporationGOODRICH PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
| Delaware | 76-0466193 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer
|
808 Travis, Houston, Texas | 77002 | |
| (Address of principal executive offices) | (Zip Code) |
(713) 780-9494
(Registrant’s telephone number, including area code): (713) 780-9494
Securities Registered Pursuant to Section 12 (b) of the Act:
Title of each class | Name of exchange on which registered | |
| Common Stock, par value $0.20 per share | New York Stock Exchange |
NoneSecurities Registered Pursuant to Section 12 (g) of the Act:
(Former name, former address and former fiscal year, if changed since last report.)
None
Indicate by check mark whether the registrantRegistrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrantRegistrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesxþ No¨
Indicate by checkmarkcheck mark whether the registrantRegistrant is a large accelerated filer, an accelerated filer, (as definedor a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act): YesAct.
Large accelerated filer ¨ NoAccelerated filer xþ Non-accelerated filer
¨
Indicate by checkmarkcheck mark whether the registrantRegistrant is a shell company (as defined in Exchange Act Rule 12b-2 of the Exchange Act.):12b-2). Yes¨ Noxþ
At November 2, 2005, there were 24,788,745The number of shares outstanding of Goodrich Petroleum Corporationthe Registrant’s common stock outstanding.as of May 5, 2006 was 24,932,898.
GOODRICH PETROLEUM CORPORATION
INDEX TO FORM 10-Q
September 30, 2005TABLE OF CONTENTS
| Page | ||||
| PART | ||||
| 3 | |||
| ITEM 1. | FINANCIAL STATEMENTS | |||
| 4 | ||||
| 5 | ||||
| 6 | ||||
| 7 | ||||
| ITEM 2. | ||||
| ITEM 3. | ||||
| ITEM 4. | ||||
| PART II |
| 24 | ||
| ITEM 1A. | ||||
| ITEM 6. | ||||
| ||||
| ||||
2
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Balance SheetsCONSOLIDATED BALANCE SHEETS
(In Thousands, Except Share Amounts)
| September 30, 2005 | December 31, 2004 | |||||||
| (unaudited) | ||||||||
| ASSETS | ||||||||
CURRENT ASSETS | ||||||||
Cash and cash equivalents | $ | 2,056,486 | $ | 3,449,210 | ||||
Accounts receivable | ||||||||
Trade and other, net of allowance | 5,476,555 | 7,183,356 | ||||||
Accrued oil and gas revenue | 5,051,284 | 3,121,932 | ||||||
Prepaid insurance and other | 651,059 | 631,472 | ||||||
Fair value of interest rate derivatives | 166,729 | — | ||||||
Total current assets | 13,402,113 | 14,385,970 | ||||||
PROPERTY AND EQUIPMENT | ||||||||
Oil and gas properties (successful efforts method) | 259,131,761 | 159,903,454 | ||||||
Furniture, fixtures and equipment | 1,006,567 | 821,236 | ||||||
| 260,138,328 | 160,724,690 | |||||||
Less accumulated depletion, depreciation and amortization | (65,998,156 | ) | (51,319,998 | ) | ||||
Net property and equipment | 194,140,172 | 109,404,692 | ||||||
OTHER ASSETS | ||||||||
Restricted cash and investments | 2,039,000 | 2,039,000 | ||||||
Deferred taxes | 17,730,000 | 2,070,000 | ||||||
Other | 351,760 | 77,418 | ||||||
Total other assets | 20,120,760 | 4,186,418 | ||||||
TOTAL ASSETS | $ | 227,663,045 | $ | 127,977,080 | ||||
| March 31, 2006 | December 31, 2005 | |||||||
| (unaudited) | ||||||||
| Assets | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 1,503 | $ | 19,842 | ||||
Accounts receivable, trade and other, net of allowance | 9,998 | 6,397 | ||||||
Accrued oil and gas revenue | 9,937 | 11,863 | ||||||
Fair value of interest rate derivatives | 496 | 107 | ||||||
Prepaid expenses and other | 456 | 463 | ||||||
Total current assets | 22,390 | 38,672 | ||||||
Property and equipment: | ||||||||
Oil and gas properties (successful efforts method) | 379,933 | 316,286 | ||||||
Furniture, fixtures and equipment | 1,207 | 1,075 | ||||||
| 381,140 | 317,361 | |||||||
Less: Accumulated depletion, depreciation and amortization | (85,950 | ) | (74,229 | ) | ||||
Net property and equipment | 295,190 | 243,132 | ||||||
Other assets: | ||||||||
Restricted cash | 2,039 | 2,039 | ||||||
Deferred tax asset | 5,698 | 11,580 | ||||||
Other | 1,062 | 1,103 | ||||||
Total other assets | 8,799 | 14,722 | ||||||
Total assets | $ | 326,379 | $ | 296,526 | ||||
| Liabilities and Stockholders’ Equity | ||||||||
Current liabilities: | ||||||||
Accounts payable | $ | 40,098 | $ | 31,574 | ||||
Accrued liabilities | 21,449 | 15,973 | ||||||
Fair value of oil and gas derivatives | 11,444 | 23,271 | ||||||
Accrued abandonment costs | 92 | 92 | ||||||
Total current liabilities | 73,083 | 70,910 | ||||||
Long-term debt | 30,000 | 30,000 | ||||||
Accrued abandonment costs | 8,321 | 7,868 | ||||||
Fair value of oil and gas derivatives | 3,283 | 6,159 | ||||||
Total liabilities | 114,687 | 114,937 | ||||||
Stockholders’ equity: | ||||||||
Preferred stock: 10,000,000 shares authorized: | ||||||||
Series A convertible preferred stock, $1.00 par value, 791,968 shares issued and outstanding at December 31, 2005 | — | 792 | ||||||
Series B convertible preferred stock, $1.00 par value, 2,250,000 and 1,650,000 shares issued and outstanding | 2,250 | 1,650 | ||||||
Common stock: $0.20 par value, 50,000,000 shares authorized; issued and outstanding 24,922,147 and 24,804,737 shares, respectively | 4,984 | 4,961 | ||||||
Additional paid in capital | 208,265 | 187,967 | ||||||
Accumulated deficit | (74 | ) | (8,649 | ) | ||||
Unamortized restricted stock awards | – | (2,066 | ) | |||||
Accumulated other comprehensive loss | (3,733 | ) | (3,066 | ) | ||||
Total stockholders’ equity | 211,692 | 181,589 | ||||||
Total liabilities and stockholders’ equity | $ | 326,379 | $ | 296,526 | ||||
See notes to consolidated financial statements.
3statements
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Balance Sheets (Continued)CONSOLIDATED STATEMENTS OF OPERATIONS
(In Thousands, Except Per Share Amounts)
(Unaudited)
| September 30, 2005 | December 31, 2004 | |||||||
| (unaudited) | ||||||||
LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||
CURRENT LIABILITIES | ||||||||
Accounts payable | $ | 29,978,287 | $ | 23,352,051 | ||||
Accrued liabilities | 16,009,591 | 3,214,103 | ||||||
Fair value of oil and gas derivatives | 35,568,183 | 1,834,195 | ||||||
Fair value of interest rate derivatives | — | 144,042 | ||||||
Current portion of other non-current liabilities | 91,605 | 91,605 | ||||||
Total current liabilities | 81,647,666 | 28,635,996 | ||||||
LONG TERM DEBT | 36,000,000 | 27,000,000 | ||||||
OTHER NON-CURRENT LIABILITIES | ||||||||
Accrued abandonment costs | 7,654,126 | 6,718,895 | ||||||
Production payment payable and other | 58,469 | 296,960 | ||||||
Fair value of oil and gas derivatives | 11,892,430 | — | ||||||
Fair value of interest rate derivatives | — | 17,925 | ||||||
Total liabilities | 137,252,691 | 62,669,776 | ||||||
STOCKHOLDERS’ EQUITY | ||||||||
Preferred stock; authorized 10,000,000 shares: | ||||||||
Series A convertible preferred stock, par value $1.00 per share; issued and outstanding 791,968 shares (liquidation preference $10 per share, aggregating to $7,919,680) | 791,968 | 791,968 | ||||||
Common stock, par value $0.20 per share; authorized 50,000,000 shares; issued and outstanding, 24,787,412 and 20,587,074 shares | 4,957,481 | 4,117,414 | ||||||
Additional paid-in capital | 109,898,355 | 55,408,587 | ||||||
Retained earnings (deficit) | (16,988,177 | ) | 9,555,977 | |||||
Unamortized restricted stock awards | (2,376,098 | ) | (1,762,001 | ) | ||||
Accumulated other comprehensive income (loss) | (5,873,175 | ) | (2,804,641 | ) | ||||
Total stockholders’ equity | 90,410,354 | 65,307,304 | ||||||
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY | $ | 227,663,045 | $ | 127,977,080 | ||||
| Three Months Ended March 31, | ||||||||
| 2006 | 2005 | |||||||
Revenues: | ||||||||
Oil and gas revenues | $ | 24,905 | $ | 12,431 | ||||
Other | 346 | 129 | ||||||
| 25,251 | 12,560 | |||||||
Operating expenses: | ||||||||
Lease operating expense | 3,584 | 2,244 | ||||||
Production taxes | 1,584 | 786 | ||||||
Depreciation, depletion and amortization | 9,832 | 5,846 | ||||||
Exploration | 1,494 | 1,524 | ||||||
General and administrative | 3,771 | 1,620 | ||||||
Gain on sale of assets | — | (151 | ) | |||||
| 20,265 | 11,869 | |||||||
Operating income | 4,986 | 691 | ||||||
Other income (expense): | ||||||||
Interest expense | (695 | ) | (307 | ) | ||||
Gain (loss) on derivatives not qualifying for hedge accounting | 13,542 | (9,843 | ) | |||||
| 12,847 | (10,150 | ) | ||||||
Income (loss) before income taxes | 17,833 | (9,459 | ) | |||||
Income tax (expense) benefit | (6,241 | ) | 3,308 | |||||
Net income (loss) | 11,592 | (6,151 | ) | |||||
Preferred stock dividends | 1,481 | 158 | ||||||
Preferred stock redemption premium | 1,536 | — | ||||||
Net income (loss) applicable to common stock | $ | 8,575 | $ | (6,309 | ) | |||
Net income (loss) applicable to common stock per common share: | ||||||||
Basic | $ | 0.34 | $ | (0.30 | ) | |||
Diluted | $ | 0.34 | $ | (0.30 | ) | |||
Average common shares outstanding: | ||||||||
Basic | 24,860 | 20,784 | ||||||
Diluted | 25,366 | 20,784 | ||||||
See notes to consolidated financial statements.
4statements
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of OperationsCONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
Three Months Ended September 30, | ||||||||
| 2005 | 2004 | |||||||
REVENUES | ||||||||
Oil and gas revenues | $ | 17,172,993 | $ | 11,983,400 | ||||
Other | 85,086 | 30,387 | ||||||
Total revenues | 17,258,079 | 12,013,787 | ||||||
OPERATING EXPENSES | ||||||||
Lease operating expense | 2,404,320 | 1,850,107 | ||||||
Production taxes | 1,177,576 | 881,209 | ||||||
Depletion, depreciation and amortization | 6,695,967 | 3,173,128 | ||||||
Exploration | 1,396,377 | 1,864,640 | ||||||
General and administrative | 2,577,263 | 1,640,513 | ||||||
Total operating expenses | 14,251,503 | 9,409,597 | ||||||
OPERATING INCOME | 3,006,576 | 2,604,190 | ||||||
OTHER INCOME (EXPENSE) | ||||||||
Interest expense | (344,073 | ) | (317,447 | ) | ||||
Loss on derivatives not qualifying for hedge accounting | (32,624,505 | ) | — | |||||
Gain (loss) on sale of assets and litigation judgment | — | 2,045,748 | ||||||
Total other income (expense) | (32,968,578 | ) | 1,728,301 | |||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (29,962,002 | ) | 4,332,491 | |||||
Income taxes | (10,487,929 | ) | 45,013 | |||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (19,474,073 | ) | 4,287,478 | |||||
DISCONTINUED OPERATIONS INCLUDING GAIN ON SALE, NET OF INCOME TAXES | — | 49,916 | ||||||
NET INCOME (LOSS) | (19,474,073 | ) | 4,337,394 | |||||
Preferred stock dividends | 158,200 | 158,201 | ||||||
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK | $ | (19,632,273 | ) | $ | 4,179,193 | |||
NET INCOME (LOSS) PER COMMON SHARE - BASIC | ||||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | $ | (0.79 | ) | $ | 0.21 | |||
DISCONTINUED OPERATIONS | — | — | ||||||
NET INCOME (LOSS) | $ | (0.79 | ) | $ | 0.21 | |||
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK | $ | (0.79 | ) | $ | 0.21 | |||
NET INCOME (LOSS) PER COMMON SHARE - DILUTED | ||||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | $ | (0.79 | ) | $ | 0.20 | |||
DISCONTINUED OPERATIONS | — | 0.01 | ||||||
NET INCOME (LOSS) | $ | (0.79 | ) | $ | 0.21 | |||
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK | $ | (0.79 | ) | $ | 0.20 | |||
AVERAGE COMMON SHARES OUTSTANDING - BASIC | 24,784,484 | 20,221,358 | ||||||
AVERAGE COMMON SHARES OUTSTANDING - DILUTED | 24,784,484 | 21,091,390 | ||||||
| Three Months Ended March 31, | ||||||||
| 2006 | 2005 | |||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | 11,592 | $ | (6,151 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities - | ||||||||
Depletion, depreciation and amortization | 9,832 | 5,846 | ||||||
Unrealized (gain) loss on derivatives not qualifying for hedge accounting | (16,121 | ) | 10,423 | |||||
Deferred income taxes | 6,241 | (3,308 | ) | |||||
Dry hole costs | — | 641 | ||||||
Amortization of leasehold costs | 1,158 | 542 | ||||||
Stock based compensation | 932 | 240 | ||||||
Gain on sale of assets | — | (151 | ) | |||||
Other non cash items | 60 | 63 | ||||||
Changes in assets and liabilities - | ||||||||
Accounts receivable and other assets | (1,668 | ) | 322 | |||||
Accounts payable and accrued liabilities | 13,747 | 1,713 | ||||||
Net cash provided by operating activities | 25,773 | 10,180 | ||||||
Cash flows from investing activities: | ||||||||
Additions to oil and gas properties | (63,372 | ) | (20,860 | ) | ||||
Additions to furniture and fixtures | (132 | ) | (34 | ) | ||||
Proceeds from sale of assets | 909 | 137 | ||||||
Net cash used in investing activities | (62,595 | ) | (20,757 | ) | ||||
Cash flows from financing activities: | ||||||||
Net proceeds from Series B Preferred Stock offering | 29,037 | — | ||||||
Redemption of Series A Preferred Stock | (9,310 | ) | — | |||||
Principal payments of bank borrowings | — | (5,500 | ) | |||||
Proceeds from bank borrowings | — | 14,000 | ||||||
Deferred financing costs | — | (133 | ) | |||||
Exercise of stock options and warrants | — | 458 | ||||||
Preferred stock dividends | (1,229 | ) | (158 | ) | ||||
Production payments | — | (124 | ) | |||||
Other | (15 | ) | (33 | ) | ||||
Net cash provided by financing activities | 18,483 | 8,510 | ||||||
Decrease in cash and cash equivalents | (18,339 | ) | (2,067 | ) | ||||
Cash and cash equivalents, beginning of period | 19,842 | 3,449 | ||||||
Cash and cash equivalents, end of period | $ | 1,503 | $ | 1,382 | ||||
Supplemental disclosures of cash flow information: | ||||||||
Cash paid during the period for interest | $ | 674 | $ | 159 | ||||
Cash paid during the period for income taxes | $ | — | $ | 15 | ||||
See notes to consolidated financial statements.
5statements
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of OperationsCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In Thousands)
(Unaudited)
Nine Months Ended September 30, | ||||||||
| 2005 | 2004 | |||||||
REVENUES | ||||||||
Oil and gas revenues | $ | 42,884,127 | $ | 31,824,408 | ||||
Other | 247,476 | 144,705 | ||||||
Total revenues | 43,131,603 | 31,969,113 | ||||||
OPERATING EXPENSES | ||||||||
Lease operating expense | 6,935,991 | 4,978,173 | ||||||
Production taxes | 2,934,470 | 2,153,849 | ||||||
Depletion, depreciation and amortization | 18,287,062 | 8,314,089 | ||||||
Exploration | 5,338,746 | 3,881,443 | ||||||
General and administrative | 6,033,713 | 4,473,296 | ||||||
Total operating expenses | 39,529,982 | 23,800,850 | ||||||
OPERATING INCOME | 3,601,621 | 8,168,263 | ||||||
OTHER INCOME (EXPENSE) | ||||||||
Interest expense | (1,139,285 | ) | (788,589 | ) | ||||
Loss on derivatives not qualifying for hedge accounting | (42,736,334 | ) | — | |||||
Gain (loss) on sale of assets and litigation judgment | 169,196 | 1,986,903 | ||||||
Total other income (expense) | (43,706,423 | ) | 1,198,314 | |||||
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (40,104,802 | ) | 9,366,577 | |||||
Income taxes | (14,035,250 | ) | 170,878 | |||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (26,069,552 | ) | 9,195,699 | |||||
DISCONTINUED OPERATIONS INCLUDING GAIN ON SALE, NET OF INCOME TAXES | — | 156,183 | ||||||
NET INCOME (LOSS) | (26,069,552 | ) | 9,351,882 | |||||
Preferred stock dividends | 474,602 | 474,770 | ||||||
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK | $ | (26,544,154 | ) | $ | 8,877,112 | |||
NET INCOME (LOSS) PER COMMON SHARE - BASIC | ||||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | $ | (1.13 | ) | $ | 0.48 | |||
DISCONTINUED OPERATIONS | — | 0.01 | ||||||
NET INCOME (LOSS) | $ | (1.13 | ) | $ | 0.49 | |||
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK | $ | (1.15 | ) | $ | 0.46 | |||
NET INCOME (LOSS) PER COMMON SHARE - DILUTED | ||||||||
NET INCOME (LOSS) FROM CONTINUING OPERATIONS | $ | (1.13 | ) | $ | 0.46 | |||
DISCONTINUED OPERATIONS | — | 0.01 | ||||||
NET INCOME (LOSS) | $ | (1.13 | ) | $ | 0.47 | |||
NET INCOME (LOSS) APPLICABLE TO COMMON STOCK | $ | (1.15 | ) | $ | 0.44 | |||
AVERAGE COMMON SHARES OUTSTANDING - BASIC | 23,023,855 | 19,228,728 | ||||||
AVERAGE COMMON SHARES OUTSTANDING - DILUTED | 23,023,855 | 20,044,793 | ||||||
| Three Months Ended March 31, | ||||||||
| 2006 | 2005 | |||||||
Net income (loss) | $ | 11,592 | $ | (6,151 | ) | |||
Other comprehensive loss: | ||||||||
Change in fair value of derivatives (1) | (1,079 | ) | (3,166 | ) | ||||
Reclassification adjustment (2) | 412 | 1,421 | ||||||
Other comprehensive loss | (667 | ) | (1,745 | ) | ||||
Comprehensive income (loss) | $ | 10,925 | $ | (7,896 | ) | |||
(1) Net of income tax benefit of: | $ | 581 | $ | 1,074 | ||
(2) Net of income tax expense of: | $ | 222 | $ | 764 |
See notes to consolidated financial statements.
6statements
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended September 30, | ||||||||
| 2005 | 2004 | |||||||
OPERATING ACTIVITES | ||||||||
Net income (loss) | $ | (26,069,552 | ) | $ | 9,351,882 | |||
Adjustments to reconcile net income (loss) to cash provided by operating activities | ||||||||
Depletion, depreciation and amortization | 18,287,062 | 8,314,089 | ||||||
Deferred income taxes | (14,035,250 | ) | 170,878 | |||||
Unrealized loss on derivatives not qualifying for hedge accounting | 40,611,765 | — | ||||||
Amortization of leasehold costs | 2,200,586 | 1,013,482 | ||||||
Dry hole expense | 2,011,805 | — | ||||||
(Gain) loss on sale of assets | (169,196 | ) | 63,097 | |||||
Non-cash effect of discontinued operations | — | 223,955 | ||||||
Other non-cash items | 876,892 | (129,864 | ) | |||||
Net change in: | ||||||||
Accounts receivable | (222,551 | ) | (5,572,331 | ) | ||||
Prepaid insurance and other | (19,587 | ) | (463,619 | ) | ||||
Accounts payable | 6,626,236 | 8,571,149 | ||||||
Accrued liabilities | 12,795,488 | 2,565,056 | ||||||
Net cash provided by operating activities | 42,893,698 | 24,107,774 | ||||||
INVESTING ACTIVITIES | ||||||||
Capital expenditures | (106,227,401 | ) | (28,808,528 | ) | ||||
Proceeds from sale of assets | 148,086 | 8,895 | ||||||
Net cash used in investing activities | (106,079,315 | ) | (28,799,633 | ) | ||||
FINANCING ACTIVITIES | ||||||||
Principal payments of bank borrowings | (45,000,000 | ) | (1,000,000 | ) | ||||
Net proceeds from bank borrowings | 53,853,921 | 6,500,000 | ||||||
Net proceeds of public equity offering | 53,175,000 | — | ||||||
Exercise of stock warrants and options | 477,065 | 169,251 | ||||||
Production payments | (238,491 | ) | (230,897 | ) | ||||
Preferred stock dividends | (474,602 | ) | (474,770 | ) | ||||
Net cash provided by financing activities | 61,792,893 | 4,963,584 | ||||||
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (1,392,724 | ) | 271,725 | |||||
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD | 3,449,210 | 1,488,852 | ||||||
CASH AND CASH EQUIVALENTS AT END OF PERIOD | $ | 2,056,486 | $ | 1,760,577 | ||||
See notes to consolidated financial statements.
7
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statements of Stockholders’ Equity and Comprehensive Income
Nine Months Ended September 30, 2005 and 2004
(Unaudited)
Series A Preferred Stock | Common Stock | Additional Paid - In Capital | Retained (Deficit) | Unamortized Awards | Accumulated Income (Loss) | Total Equity | ||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | |||||||||||||||||||||||||||
Balance at December 31, 2003 | 791,968 | $ | 791,968 | 18,130,011 | $ | 3,626,002 | $ | 53,359,023 | $ | (8,338,403 | ) | $ | (381,598 | ) | $ | (997,998 | ) | $ | 48,058,994 | |||||||||||
Net Income | — | — | — | — | — | 9,351,882 | — | — | 9,351,882 | |||||||||||||||||||||
Other Comprehensive Income (Loss); Net of Tax | ||||||||||||||||||||||||||||||
Net Derivative (Loss), net of tax of $3,404,407 | — | — | — | — | — | — | — | (6,322,471 | ) | (6,322,471 | ) | |||||||||||||||||||
Reclassification Adjustment, net of tax of $1,194,973 | — | — | — | — | — | — | — | 2,219,235 | 2,219,235 | |||||||||||||||||||||
Total Comprehensive Income | 5,248,646 | |||||||||||||||||||||||||||||
Issuance and Amortization of Restricted Stock | — | — | 4,331 | 866 | 1,184,790 | — | (778,585 | ) | — | 407,071 | ||||||||||||||||||||
Exercise of Stock Warrants | — | — | 2,298,803 | 459,761 | (290,510 | ) | — | — | — | 169,251 | ||||||||||||||||||||
Preferred Stock Dividends | — | — | — | — | — | (474,770 | ) | — | — | (474,770 | ) | |||||||||||||||||||
Balance at September 30, 2004 | 791,968 | $ | 791,968 | 20,433,145 | $ | 4,086,629 | $ | 54,253,303 | $ | 538,709 | $ | (1,160,183 | ) | $ | (5,101,234 | ) | $ | 53,409,192 | ||||||||||||
Balance at December 31, 2004 | 791,968 | $ | 791,968 | 20,587,074 | $ | 4,117,414 | $ | 55,408,587 | $ | 9,555,977 | $ | (1,762,001 | ) | $ | (2,804,641 | ) | $ | 65,307,304 | ||||||||||||
Net Loss | — | — | — | — | — | (26,069,552 | ) | — | — | (26,069,552 | ) | |||||||||||||||||||
Other Comprehensive Income (Loss); Net of Tax | ||||||||||||||||||||||||||||||
Net Derivative (Loss), net of tax of $3,835,997 | — | — | — | — | — | — | — | (7,123,995 | ) | (7,123,995 | ) | |||||||||||||||||||
Reclassification Adjustment, net of tax of $2,183,710 | — | — | — | — | — | — | — | 4,055,461 | 4,055,461 | |||||||||||||||||||||
Total Comprehensive Loss | (29,138,086 | ) | ||||||||||||||||||||||||||||
Public Equity Offering | — | — | 3,710,000 | 742,000 | 52,433,000 | — | — | 53,175,000 | ||||||||||||||||||||||
Issuance and Amortization of Restricted Stock | — | — | 105,106 | 21,021 | 1,416,749 | (614,097 | ) | — | 823,673 | |||||||||||||||||||||
Exercise of Stock Warrants and Options | — | — | 371,000 | 74,200 | 402,865 | — | — | — | 477,065 | |||||||||||||||||||||
Director Stock Grants | — | — | 14,232 | 2,846 | 237,154 | — | — | — | 240,000 | |||||||||||||||||||||
Preferred Stock Dividends | — | — | — | — | — | (474,602 | ) | — | — | (474,602 | ) | |||||||||||||||||||
Balance at September 30, 2005 | 791,968 | $ | 791,968 | 24,787,412 | $ | 4,957,481 | $ | 109,898,355 | $ | (16,988,177 | ) | $ | (2,376,098 | ) | $ | (5,873,175 | ) | $ | 90,410,354 | |||||||||||
See notes to consolidated financial statements.
8
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
Notes to Consolidated Financial Statements
September 30, 2005 and 2004
(Unaudited)
NOTE A - A—Basis of Presentation
The consolidated financial statements of Goodrich Petroleum Corporation (“Goodrich” or “the Company” or “we”) included in this Form 10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”) and, accordingly, certain information normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States has been condensed or omitted. The consolidated financial statements reflect all normal recurring adjustments that, in the opinion of management, are necessary for a fair presentation.
Significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to the prior year statements to conform to the current year presentation.
The accompanying consolidated financial statements of the Company should be read in conjunction with the consolidated financial statements and notes included in the Company’s Annual Report on Form 10-K, as amended, for the year ended December 31, 2004. Since the issuance of its Form 10-K for the year ended December 31, 2004, the Company has changed the presentation of its Statement of Operations by creating a new subtotal called Operating Income, defined as Revenues minus Operating Expenses, and adding a new section following Operating Income called Other Income (Expense). Included in Other Income (Expense) are interest expense, gain (loss) on derivatives not qualifying for hedge accounting, and gain (loss) on asset sales and litigation judgment. Where appropriate, reclassifications have been made to the 2004 amounts to conform to the 2005 presentation.
2005. The results of operations for the nine-month periodthree months ended September 30, 2005March 31, 2006 are not necessarily indicative of the results to be expected for the full year.
NOTE B—Recent Accounting Pronouncements
In March 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No.156, “Accounting for Servicing of Financial Assets” (“SFAS 156”), which requires all separately recognized servicing assets and servicing liabilities be initially measured at fair value. SFAS 156 permits, but does not require, the subsequent measurement of servicing assets and servicing liabilities at fair value. Adoption is required as of the beginning of the first fiscal year that begins after September 15, 2006. Early adoption is permitted. The adoption of SFAS 156 is not expected to have a material effect on our consolidated financial position, results of operations or cash flows.
In February 2006, the FASB issued SFAS No. 155, “Accounting for Certain Hybrid Financial Instruments, an amendment of FASB Statements No. 133 and 140” (“SFAS 155”). SFAS 155 clarifies certain issues relating to embedded derivatives and beneficial interests in securitized financial assets. The provisions of SFAS 155 are effective for all financial instruments acquired or issued after fiscal years beginning after September 15, 2006. We are currently assessing the impact that the adoption of SFAS 155 will have on our consolidated financial position, results of operations or cash flows.
In December 2004, the FASB issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123R”), replacing SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), and superceding Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”). SFAS 123R requires recognition of share-based compensation in the financial statements. SFAS 123R is effective as of the first annual reporting period that begins after June 15, 2005 and was adopted on January 1, 2006. See Note C for further details.
NOTE C—Stock-Based Compensation
Abandonment ObligationsShare-Based Employee Compensation Plans
On February 1, 2006, our Board of Directors approved our 2006 Long-Term Incentive Plan (the “2006 Plan”), subject to stockholder approval at our annual meeting of stockholders in May 2006. The 2006 Plan is similar to and will, upon shareholder approval, replace our previously adopted 1995 Incentive Plan (the “1995 Plan”) and 1997 Non-Employee Directors’ Stock Option Plan (the “Directors’ Plan”). No further awards will be granted under the previously adopted plans, however, those plans shall continue to apply to and govern awards made thereunder. Under the 2006 Plan, a maximum of 2.0 million new shares are reserved for issuance as
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
awards of share options to officers, employees and non-employee directors. Share options granted to officers and employees will generally become exercisable in 33% increments over a three year period and to the extent not exercised, expire on the tenth anniversary of the date of grant. Share options granted to non-employee directors will usually be immediately exercisable and to the extent not exercised, expire on the tenth anniversary of the date of grant. The exercise price of share options granted under the 2006 Plan will equal the market value of the underlying stock on the date of grant. The 1995 Plan expired according to its original terms on August 16, 2005. However, on February 1, 2006, our Board of Directors approved the extension of the 1995 Plan through December 31, 2005 and the granting of a total of 101,129 shares of restricted stock and 525,000 stock options to certain of our employees and directors as of December 6, 2005, subject to approval at our 2006 annual meeting of stockholders in May 2006. For accounting purposes, such restricted shares and options have been valued as of February 9, 2006, the date on which our directors and executive officers reached a level of more than 50% ownership of our common stock, so that shareholder approval of those actions was no longer uncertain.
Share options previously granted under the 1995 Plan become exercisable in 33% increments over a three year period and to the extent not exercised, expire on the tenth anniversary of the date of grant. Share options previously granted under the Directors’ Plan generally become exercisable immediately and expire, if not exercised, ten years thereafter. The exercise price of share options granted under the 1995 Plan and the Directors’ Plan equals the market value of the underlying stock on the date of grant. At March 31, 2006, options to purchase 1,044,500 shares of our common stock were outstanding under the 1995 Plan and the Directors’ Plan.
Adoption of New Accounting Pronouncement
Stock based compensation for the three months ended March 31, 2006 of $0.9 million has been recognized as a component of general and administrative expenses in the accompanying Consolidated Financial Statements.
Effective January 1, 2003, the Company2006 we adopted SFAS 123R, which requires us to measure the cost of employee services received in exchange for all equity awards granted, including stock options and restricted stock, based on the fair market value of the award as of the grant date, net of estimated forfeitures. SFAS 123R supersedes SFAS 123 and APB 25. We have adopted SFAS 123R using the modified prospective application method of adoption, which requires us to record compensation cost related to unvested stock awards as of December 31, 2005 by recognizing the unamortized grant date fair value of these awards over the remaining service periods of those awards with no change in historical reported earnings. Awards granted after December 31, 2005 are valued at fair value in accordance with provisions of SFAS 123R and recognized on a straight line basis over the service periods of each award. We estimated forfeiture rates for the first quarter of 2006 based on our historical experience.
Prior to 2006, we accounted for stock-based compensation in accordance with APB 25 using the intrinsic value method, which did not require that compensation cost be recognized for our stock options provided the option exercise price was established at 100% of the common stock fair market value on the date of grant. Under APB 25, we were required to record expense over the vesting period for the value of restricted stock granted. Prior to 2006, we provided pro forma disclosure amounts in accordance with SFAS No. 143,148, “Accounting for Asset Retirement Obligations.Stock-Based Compensation – Transition and Disclosure” (SFAS 148), as if the fair value method defined by SFAS No. 143 requires123 had been applied to our stock-based compensation. Our net loss and net loss per share for the Companythree months ended March 31, 2005 would have been greater if compensation cost related to record a liability equal tostock options had been recorded in the financial statements based on fair value at the grant dates.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The estimated fair value of the estimatedoptions granted during 2006 and prior years was calculated using a Black Scholes Merton option pricing model (Black Scholes). The following summarizes the assumptions used in the 2006 Black Scholes model:
Risk free interest rate | 4.50 | % | |
Weighted average volatility | 54-57 | % | |
Dividend yield | 0 | % | |
Expected years until exercise | 5-6 |
The Black Scholes model incorporates assumptions to value stock-based awards. The risk-free rate of interest for periods within the expected term of the option is based on a zero-coupon U.S. government instrument over the expected term of the equity instrument. Expected volatility is based on the historical volatility of our common stock. We generally use the midpoint of the vesting period and the life of the grant to estimate employee option exercise timing (expected term) within the valuation model. This methodology is not materially different from our historical data on exercise timing. In the case of director options, we used historical exercise behavior. Employees and directors that have different historical exercise behavior with regard to option exercise timing and forfeiture rates are considered separately for valuation and attribution purposes.
Pro forma net loss as if the fair value based method had been applied to all awards is as follows (in thousands, except per share amounts):
| Three Months Ended March 31, 2005 | ||||
Net loss as reported | $ | (6,151 | ) | |
Add: Stock based compensation programs recorded as expense, net of tax | 158 | |||
Deduct: Total stock based compensation expense, net of tax | (265 | ) | ||
Pro forma net loss | $ | (6,258 | ) | |
Net loss applicable to common stock as reported | $ | (6,309 | ) | |
Add: Stock based compensation programs recorded as expense, net of tax | 158 | |||
Deduct: Total stock based compensation expense, net of tax | (265 | ) | ||
Pro forma net loss | $ | (6,416 | ) | |
Net loss applicable to common stock per share: | ||||
Basic and diluted – as reported | $ | (0.30 | ) | |
Basic and diluted – pro forma | $ | (0.30 | ) | |
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the components of our stock-based compensation programs recorded as expense (in thousands):
| Three Months Ended, March 31, | ||||||||
| 2006 | 2005 | |||||||
Restricted stock: | ||||||||
Pretax compensation expense | $ | 426 | $ | 240 | ||||
Tax benefit | (149 | ) | (82 | ) | ||||
Restricted stock expense, net of tax | $ | 277 | $ | 158 | ||||
Stock options: | ||||||||
Pretax compensation expense | $ | 506 | $ | — | ||||
Tax benefit | (177 | ) | — | |||||
Stock option expense, net of tax | $ | 329 | $ | — | ||||
Total share based compensation: | ||||||||
Pretax compensation expense | $ | 932 | $ | 240 | ||||
Tax benefit | (326 | ) | (82 | ) | ||||
Total share based compensation expense, net of tax | $ | 606 | $ | 158 | ||||
As of March 31, 2006, $4.1 million and $8.1 million of total unrecognized compensation cost related to retirerestricted stock and stock options, respectively, is expected to be recognized over a weighted average period of approximately 2.0 years for restricted stock and 2.4 years for stock options.
Option activity under our stock option plans as of March 31, 2006 and changes during the three months ended March 31, 2006 were as follows:
| Shares | Weighted Average Exercise Price | Weighted Average Remaining Contractual Term In Years | Aggregate Intrinsic Value | |||||||
Outstanding at January 1, 2006 | 519,500 | $ | 13.70 | |||||||
Granted | 525,000 | 23.39 | ||||||||
Outstanding at March 31, 2006 | 1,044,500 | $ | 18.57 | 8.7 | $ | 8,805,368 | ||||
Exercisable at March 31, 2006 | 372,833 | $ | 12.61 | 7.4 | $ | 5,364,251 | ||||
The aggregate intrinsic value in the table above represents the total pre-tax intrinsic value (the difference between our closing stock price on the last trading day of the first quarter of 2006 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on March 31, 2006. The amount of aggregate intrinsic value will change based on the fair market value of our stock.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes information on unvested restricted stock outstanding as of March 31, 2006:
| Number of Shares | Weighted Average Grant-Date Fair Value | |||||
Unvested at start of quarter | 263,890 | $ | 11.13 | |||
Vested | (110,935 | ) | 7.60 | |||
Granted | 101,629 | 23.42 | ||||
Unvested at end of quarter | 254,584 | $ | 17.57 | |||
NOTE D—Asset Retirement Obligations
SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets and requires that an asset. The asset retirement liability mustcost should be recorded incapitalized as part of the periods in whichcost of the obligation meets the definition ofrelated long- lived asset and subsequently allocated to expense using a liability, which is generally when the asset is placed in service. Prior to the adoption ofsystematic and rational method. We adopted SFAS No. 143 the Company recorded liabilities for the abandonment of oil and gas properties only in its two largest fields, with such liabilities amounting to $4,881,000 as of December 31, 2002. In accordance with the transition provisions of SFAS No. 143, the Company recorded an adjustment to recognize additional estimated liabilities for the abandonment of oil and gas properties, as ofon January 1, 2003 in the amountand recorded an incremental liability for asset retirement obligations of $1,408,000, and$1.4 million, additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1,092,000. Any subsequent difference between costs incurred upon settlement$1.1 million and a net of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings. To recognize thetax cumulative effect of this change in accounting principle the Company recorded a charge to earnings as of January 1, 2003 in the amount of $205,000, reflecting the $316,000 difference between the adjustments to the liability and asset accounts, net$0.2 million. The reconciliation of the related income tax effect. Forbeginning and ending asset retirement obligation for the nine months ended September 30, 2005 and 2004, the Company recordedperiod ending March 31, 2006 is as follows (in thousands):
Beginning balance | $ | 7,960 | ||
Liabilities incurred | 359 | |||
Liabilities settled | — | |||
Accretion expense (reflected in depletion, depreciation and amortization expense) | 94 | |||
Ending balance | 8,413 | |||
Less current portion | (92 | ) | ||
| $ | 8,321 | |||
NOTE E—Long-Term Debt
Long-term debt consisted of the following activity in the abandonment liability:balances (in thousands):
| March 31, 2006 | December 31, 2005 | |||||
Second lien term loan | $ | 30,000 | $ | 30,000 | ||
Less current maturities | — | — | ||||
Total long-term debt | $ | 30,000 | $ | 30,000 | ||
9
Nine Months Ended September 30, | ||||||||
| 2005 | 2004 | |||||||
Beginning Balance | $ | 6,810,500 | $ | 6,601,186 | ||||
Accretion of liability | 250,934 | 238,711 | ||||||
Liability of newly added wells | 684,297 | 314,334 | ||||||
Abandonment costs incurred | — | (140,793 | ) | |||||
Ending balance | 7,745,731 | 7,013,438 | ||||||
Less current portion | (91,605 | ) | (91,605 | ) | ||||
| $ | 7,654,126 | $ | 6,921,833 | |||||
Discontinued Operations
In October 2004,On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (the “Amended and Restated Credit Agreement”) and a funded $30.0 million second lien term loan (the “Second Lien Term Loan Agreement”) that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Company sold its operated interests in the MarhollAmended and Sean Andrew fields, along with its non-operated interests in the Ackerly field, all of whichRestated Credit Agreement were located in West Texas, for gross proceeds of approximately $2,100,000. The Company realized a pre-tax gain of $877,000 on the sale of these non-core properties. Prior period results of operations of these sold properties have been presented as discontinued operations in the accompanying consolidated statement of operations. Results for these properties reported as discontinued operations for the three months and nine months ended September 30, 2004 were as follows:
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||
| 2004 | 2004 | |||||||
Oil and gas sales | $ | 168,685 | $ | 505,081 | ||||
Operating expenses | (91,891 | ) | (264,800 | ) | ||||
Gain on sale | — | — | ||||||
Income before taxes | 76,794 | 240,281 | ||||||
Income tax expense | 26,878 | 84,098 | ||||||
Income from discontinued operations | $ | 49,916 | $ | 156,183 | ||||
NOTE B – New Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123R,Share-Based Payment, a revision of SFAS No. 123,Accounting for Stock-Based Compensation. The revised statement requires the expensing of new, modified or repurchased stock-based compensation awards issued after June 15, 2005. Previously issued stock-based compensation awards, which are unvested as of that date, must also be accounted for in accordance with the revised statement. The revised statement provides for the use of either a closed-form model or open-form lattice model for the valuation of stock option awards. The Company plansincreased from $50.0 million to follow the “modified prospective transition approach” to the adoption of the revised statement and is currently evaluating the potential impact that the adoption of the revised statement will have on its financial statements. In April 2005, the SEC adopted a rule permitting registrants to delay the expensing of options, pursuant to SFAS No. 123R, to the first annual period beginning after June 15, 2005. Accordingly, the Company will implement the provisions of SFAS No. 123R in its financial statements, effective January 1, 2006.
In March 2005, the FASB issued FASB Interpretation (FIN) 47, an interpretation of SFAS No. 143,Accounting for Asset Retirement Obligations.FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 143, which the Company adopted on January 1, 2003 (see Note A). The Company applied the guidance in this FIN beginning in the third quarter of 2005 resulting in no impact on its financial statements.
10
In April 2005, the FASB issued FASB Staff Position (FSP) 19-1 to provide guidance on the accounting for exploratory well costs and to amend SFAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-1 applies to companies that use the successful efforts method of accounting as described in SFAS No. 19. This FSP clarifies that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well$200.0 million and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company adopted the guidance in this FSP prospectively in April 2005 and the adoption had no impact on its financial statements. The Company had no capitalized exploratory costs pending determination of reserves as of September 30, 2005.
NOTE C – Public Equity Offering
In May 2005, the Company completed a public offering of 3,710,000 shares of its common stock at an offering price of $15.40 per share resulting in net proceeds of $53,175,000, after underwriting discount and offering costs. The Company used the proceeds to repay all outstanding indebtedness to BNP Paribas under its senior credit facility in the amount of $39,500,000 (see Note D) with the balance being added to working capital to be used primarily to fund an accelerated drilling program in the Cotton Valley Trend of East Texas and Northwest Louisiana.
NOTE D – Senior Credit Facility
The Company has a $65,000,000 senior credit facility with BNP Paribas maturing onmaturity was extended from February 25, 2008. It presently provides for2008 to February 25, 2010. Revolving borrowings of up to $50,000,000 on Tranche Aunder the Amended and $15,000,000 on Tranche B, however, it is anticipated to be expanded and extended in the fourth quarter of 2005.
Tranche A borrowingsRestated Credit Agreement are subject to periodic redeterminations of the borrowing base which wasis currently established at $44,000,000 in February 2005$75.0 million, and is anticipatedcurrently scheduled to be increasedredetermined in May 2006, based upon our 2005 year-end reserve report. With a portion of the net proceeds of the offering of our 5.375% Series B Cumulative Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) in December 2005, we fully repaid all outstanding indebtedness on our revolver in the fourth quarteramount of 2005.$47.5 million leaving a zero balance outstanding as of December 31, 2005 (see Note F). Interest on Tranche Arevolving borrowings under the Amended and Restated Credit Agreement accrues at a rate calculated, at the
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
our option, of the Company, at either the BNP Paribasbank base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—2.50%1.25% to 2.00%, depending on borrowing base utilization. Prior to maturity, no principal payments are required so long as the maximum borrowing base amount exceeds outstanding Tranche A borrowings. Tranche B borrowings can be made with the approval of BNP Paribas to finance development(“BNP”) is the lead lender and administrative agent under the amended credit facility with Comerica Bank and Harris Nesbit Financing, Inc. as co-lenders.
The terms of the Company’s acreageAmended and Restated Credit Agreement require us to maintain certain covenants. Capitalized terms are defined in the Cotton Valley Trend of East Texas and Northwest Louisiana. Interest on Tranche B borrowings accrues at a quarterly rate of LIBOR plus 5.0% and principal will be due on February 25, 2008.credit agreement. The covenants include:
The credit facility precludes the payment
As of September 30, 2005, the Company was notMarch 31, 2006, we were in compliance with all of the working capital ratio covenantfinancial covenants of the Amended and Restated Credit Agreement.
The Second Lien Term Loan Agreement provides for a 5-year, non-revolving loan of $30.0 million which was funded on November 17, 2005 and is due in a single maturity on November 17, 2010. Optional prepayments of term loan principal can be made in amounts of not less than $5.0 million during the first year at a 1% premium and without premium after the first year. Interest on term loan borrowings accrues at a rate calculated, at our option, at either base rate plus 3.50%, or LIBOR plus 4.50%, and is payable quarterly. BNP is the lead lender and administrative agent under the Second Lien Term Loan Agreement.
The terms of the Second Lien Term Loan Agreement require us to maintain certain covenants. Capitalized terms are defined in the loan agreement. The covenants include:
As of March 31, 2006, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.
NOTE F—Preferred Stock
In December 2005, 1,650,000 shares of our Series B Convertible Preferred Stock were issued in a private placement for net proceeds of $79.8 million (after offering costs of $2.7 million). On January 23, 2006, the initial purchasers exercised their option to purchase an additional 600,000 shares of Series B Convertible Preferred Stock at the same price per share, resulting in net proceeds of $29.0 million.
As part of this transaction we filed a registration statement with the SEC on April 20, 2006 for the purpose of registering the resale of the shares of common stock issuable pursuant to the purchase agreement. As of the date we filed this Form 10-Q, the registration statement had not been declared effective by the SEC.
During the first quarter of 2006 we completed the redemption of our Series A Convertible Preferred Stock. Of the previously outstanding shares of Series A Convertible Preferred Stock, holders of 15,539 shares elected to convert such shares into a net total of 6,466 shares of our common stock and the tangible net worth covenant, however, the Company receivedremaining shares were redeemed in cash for $12 per share, plus accrued dividends. The total redemption cost to us was approximately $9.3 million and was funded from available cash resources. This amount includes a waiver from BNP Paribas with respect to those covenants. Substantially all the Company’s assets are pledged to secure the senior credit facility.
In April 2005, the credit agreement was amended to allow the Company to redraw the $7,500,000 initially advanced under Tranche B$1.5 million redemption premium which is treated in the event that it was repaid within 30 dayssame manner as preferred stock dividends on the Consolidated Statement of a public equity offering. In May 2005, the Company completed a public equity offering (see Note C) and used the proceeds to repay all outstanding indebtedness under the senior credit facility in the amount of $39,500,000, including $7,500,000 initially advanced under Tranche B.
11Operations.
In July 2005, the Company commenced new Tranche A borrowings to continue funding of its Cotton Valley Trend drilling program. Outstanding Tranche A borrowings as of September 30, 2005 and November 2, 2005 were $36,000,000 and $44,000,000, respectively. Subsequent to September 30, 2005, the Company made new Tranche B borrowings of $7,500,000 resulting in total borrowings outstanding as of November 2, 2005 in the amount of $51,500,000. In October 2005, the Company received a non-binding commitment from BNP Paribas and two co-lenders to expand the senior credit facility to a total of $105 million, consisting of a $75 million Tranche A and a new $30 million second lien facility (in lieu of Tranche B), and to extend the term of the credit facility for an additional two years. Documentation of the expanded and extended credit facility is presently underway and closing of the new credit agreement and initial funding of the $30 million second lien facility is anticipated to take place in mid November 2005.GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period, as further described below, and in February 2004, entered into another interest rate swap with BNP Paribas for an additional one year period (see Note E).NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE E – G—Net Income (Loss) Per Share
Net income (loss) applicable to common stock was used as the numerator in computing basic and diluted income (loss) per common share for the three months ended March 31, 2006 and 2005. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):
| For the Three Months Ended March 31, | ||||
| 2006 | 2005 | |||
Basic Method | 24,860 | 20,784 | ||
Dilutive Stock Warrants | 194 | — | ||
Dilutive Stock Options and Restricted Stock | 312 | — | ||
Dilutive Method | 25,366 | 20,784 | ||
NOTE H—Hedging Activities
Commodity Hedging Activity
The Company entersWe enter into swap contracts, costless collars or other hedging agreements from time to time to manage the commodity price risk for a portion of itsour production. The Company considersWe consider these to be hedging activities and, as such, monthly settlements on these contracts are reflected in itsour crude oil and natural gas sales, provided the contracts are deemed to be “effective” hedges under FAS 133. The Company’sOur strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of itsour production. As of September 30, 2005,March 31, 2006, the commodity hedges we utilized by the Company were in the form of: (a) Swaps,swaps, where the Company receiveswe receive a fixed price and payspay a floating price, based on NYMEX quoted prices; and (b) Collars,collars, where the Company receiveswe receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and payspay the excess, if any, of the reference price over the ceiling price. Hedge ineffectiveness results from difference changes in the NYMEX contract terms and the physical location, grade and quality of the Company’sour oil and gas production.
As of September 30, 2005, the Company’sMarch 31, 2006, our open forward position on itsour outstanding commodity hedging contracts all of which were with BNP Paribas, was as follows:
Swaps | Volume | Average Price | |||
Natural gas (MMBtu/day) | |||||
2Q 2006 | 15,000 | $ | 6.95 | ||
3Q 2006 | 15,000 | 6.95 | |||
4Q 2006 | 15,000 | 6.95 | |||
1Q 2007 | 10,000 | 7.77 | |||
Oil (Bbl/day) | |||||
2Q 2006 | 800 | $ | 50.80 | ||
3Q 2006 | 800 | 50.80 | |||
4Q 2006 | 800 | 50.80 | |||
2007 | 400 | 53.35 | |||
12Table continued on following page
| Natural Gas | Crude Oil | |||||||||
Quantity (MMBtu/d) | Average Price | Quantity (Barrels/d) | Average Price | |||||||
Swaps | ||||||||||
Fourth Quarter 2005 | 15,000 | $ | 6.61 | 1,000 | $ | 36.85 | ||||
First Quarter 2006 | 14,000 | $ | 7.05 | 700 | $ | 49.75 | ||||
Second Quarter 2006 | 15,000 | $ | 6.95 | 800 | $ | 50.80 | ||||
Third Quarter 2006 | 15,000 | $ | 6.95 | 800 | $ | 50.80 | ||||
Fourth Quarter 2006 | 15,000 | $ | 6.95 | 800 | $ | 50.80 | ||||
First Quarter 2007 | 10,000 | $ | 7.77 | 400 | $ | 53.35 | ||||
Second Quarter 2007 | — | — | 400 | $ | 53.35 | |||||
Third Quarter 2007 | — | — | 400 | $ | 53.35 | |||||
Fourth Quarter 2007 | — | — | 400 | $ | 53.35 | |||||
Collars | ||||||||||
First Quarter 2007 | 10,000 | $ | 7.00 -$16.90 | — | — | |||||
Second Quarter 2007 | 15,000 | $ | 7.00 -$15.90 | — | — | |||||
Third Quarter 2007 | 15,000 | $ | 7.00 -$15.90 | — | — | |||||
Fourth Quarter 2007 | 15,000 | $ | 7.00 -$15.90 | — | — | |||||
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Collars | Volume | Average Floor/Cap | |||
Natural gas (MMBtu/day) | |||||
1Q 2007 | 25,000 | $ | 7.00 – $14.92 | ||
2Q 2007 | 30,000 | 7.00 – 14.75 | |||
3Q 2007 | 30,000 | 7.00 – 14.75 | |||
4Q 2007 | 30,000 | 7.00 – 14.75 | |||
Oil (Bbl/day) | |||||
2007 | 400 | $ | 60.00 – $76.50 | ||
The hedging contracts summarized above are based on floating NYMEX contract prices and fall within the Company’s targeted range of estimated net oil and gas production volumes for the remainder of 2005. The fair value of the oil and gas hedging contracts in place at September 30, 2005March 31, 2006 resulted in a net liability of $47,461,000.$14.7 million. As of September 30, 2005, $4,156,000March 31, 2006, $2.8 million (net of $2,238,000$1.5 million in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive incomeloss are expected to be reclassified into earnings during the next twelve months. InFor the ninethree months ended September 30, 2005, $4,022,000 of previously deferred losses (net of $2,166,000 in income taxes) was reclassified from accumulated other comprehensive income to oil and gas sales as the cash flow of the hedged items was recognized. In the nine months ended September 30, 2005, the CompanyMarch 31, 2006, we recognized in earnings a lossgain on derivatives not qualifying for hedge accounting in the amount of $42,736,000.$13.5 million (also included in this amount are settlement payments on ineffective gas hedges). This lossgain was recognized because our gas swaps have been deemed ineffective since the Company’s gas hedges were deemed to be ineffective for the first three quartersfourth quarter of 2005,2004, and accordingly, the changes in fair value of such hedges could no longer be reflected in other comprehensive income (also includedloss. In addition, three collars did not qualify for hedge accounting treatment and those changes in this loss amount are settlement payments on ineffective gas hedges).fair value have been recognized in earnings. For the ninethree months ended September 30, 2004, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness arising from the oil and gas hedging contracts.
Interest Rate Swaps
The Company has a variable-rate debt obligation that exposes the Company to the effects of changes in interest rates. To partially reduce its exposure to interest rate risk, the Company entered into three separate interest rate swaps with BNP Paribas in February 2003 which are designated as cash flow hedges (two of the interest rate swaps have now expired). The unexpired interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26,March 31, 2006, is for $18,000,000 with a LIBOR swap rate of 3.46%. In February 2004, the Company entered into another interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at September 30, 2005, resulted in an asset of $167,000. As of September 30, 2005, $109,000 (net of $58,000 in income taxes) of deferred gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve
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months. In the nine months ended September 30, 2005, $33,000$0.5 million of previously deferred losses (net of $18,000$0.2 million in income taxes) was reclassified from accumulated other comprehensive incomeloss to interest expenseoil and gas sales as the cash flow of the hedged items was recognized. For the nine months ended September 30, 2005 and 2004, the Company’s earnings were not significantly affected by cash flow hedging ineffectiveness of interest rates.
NOTE F – Net Income Per Share
Net income (loss) was used as the numerator in computing basic and diluted income per common share for the three months and nine months ended September 30, 2005 and 2004. The following table reconciles the weighted-average shares outstanding used for these computations.
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||
| 2005 | 2004 | 2005 | 2004 | |||||
Basic Method | 24,784,484 | 20,221,358 | 23,023,855 | 19,228,728 | ||||
Dilutive Stock Warrants | — | 522,008 | — | 509,743 | ||||
Dilutive Stock Options and Restricted Stock | — | 348,024 | — | 306,322 | ||||
Diluted Method | 24,784,484 | 21,091,390 | 23,023,855 | 20,044,793 | ||||
The computation of earnings per share for the three months and nine months ended September 30, 2005 and 2004 considered exercisable stock warrants and stock options to the extent that the exercise of such securities would have been dilutive under the treasury stock method. The computation of earnings per share for the three months and nine months ended September 30, 2005 and 2004 did not consider preferred stock which is convertible into shares of common stock because the effect of such conversion would have been antidilutive.
In February 2003, the Company issued 125,157 shares of its common stock to the holders of 1,016,500 outstanding stock options in exchange for the cancellation of such options (at the time of cancellation, the options were antidilutive). Based on the value of the Company’s common stock at the time of the exchange, the Company recorded a non-cash charge to earnings in February 2003 in the amount of $403,000 related to the issuance of shares in lieu of cancelled options. At the same time, the Company commenced granting a series of restricted share awards, with three year vesting periods, to certain employees under a stockholder approved equity compensation plan. Based on the value of the Company’s common stock at the time of the grants, those awards resulted in charges to a contra equity account and credits to additional paid-in capital in the following amounts:
The charges to the contra equity account are being amortized to earnings as non-cash charges to general and administrative expenses over the three year vesting period of each restricted share award and
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resulted in non-cash charges to earnings of $824,000 and $407,000 in the nine months ended September 30, 2005 and 2004, respectively. In the year ended December 31, 2004, the Company recorded a credit to the contra equity account and a charge to additional paid-in capital in the amount of $157,000 for the value of 28,918 non-vested restricted share awards that were forfeited by terminated employees. The amortization to earnings of restricted share awards has been adjusted to reflect such forfeitures. Assuming no additional restricted share awards or forfeitures, the Company will be required to record recurring non-cash charges to earnings of approximately $325,000 per quarter, related to the periodic vesting of the restricted share awards that have been issued to date.
The Company applies APB Opinion No. 25 in accounting for its stock compensation plans and, accordingly, no compensation cost has been recognized for its stock options in the financial statements. Had the Company determined compensation cost based on the fair value at the grant date for its stock options under SFAS No. 123, net income for the three months and nine months ended September 30, 2005 and 2004 would have been reduced to the pro forma amounts indicated below.
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
| 2005 | 2004 | 2005 | 2004 | |||||||||||||
Net income (loss) | ||||||||||||||||
As reported | $ | (19,474,073 | ) | $ | 4,337,394 | $ | (26,069,552 | ) | $ | 9,351,882 | ||||||
Restricted stock compensation expense included in net income, net of tax | 206,473 | 139,311 | 535,387 | 407,071 | ||||||||||||
Stock based compensation expense at fair value, net of tax | (313,283 | ) | (140,976 | ) | (855,815 | ) | (412,065 | ) | ||||||||
Pro forma | $ | (19,580,883 | ) | $ | 4,335,729 | $ | (26,389,980 | ) | $ | 9,346,888 | ||||||
Net income (loss) applicable to common stock | ||||||||||||||||
As reported | $ | (19,632,273 | ) | $ | 4,179,193 | $ | (26,544,154 | ) | $ | 8,877,112 | ||||||
Restricted stock compensation expense included in net income, net of tax | 206,473 | 139,311 | 535,387 | 407,071 | ||||||||||||
Stock based compensation expense at fair value, net of tax | (313,283 | ) | (140,976 | ) | (855,815 | ) | (412,065 | ) | ||||||||
Pro forma | $ | (19,739,083 | ) | $ | 4,177,528 | $ | (26,864,582 | ) | $ | 8,872,118 | ||||||
Net income (loss) per share | ||||||||||||||||
As reported, basic | $ | (0.79 | ) | $ | 0.21 | $ | (1.13 | ) | $ | 0.46 | ||||||
Pro forma, basic | (0.79 | ) | 0.21 | (1.15 | ) | 0.46 | ||||||||||
As reported, diluted | (0.79 | ) | 0.20 | (1.15 | ) | 0.44 | ||||||||||
Pro forma, diluted | (0.80 | ) | 0.20 | (1.17 | ) | 0.44 | ||||||||||
NOTE G - Commitments and Contingencies
In July 2005, the Company received a Notice of Proposed Tax Due from the State of Louisiana asserting that the Company underpaid its Louisiana franchise taxes for the years 1998 through 2004 in the amount of $501,000. The Notice of Proposed Tax Due includes additional assessments of penalties and interest in the amount of $352,000 for a total asserted liability of $853,000. The Company believes that it has fully paid its Louisiana franchise taxes for the years in question, therefore, it intends to vigorously contest the Notice of Proposed Tax Due. The Company has commenced its analysis of this contingency and has not recorded any provision for possible payment of additional Louisiana franchise taxes nor any related penalties and interest.
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In the third quarter of 2004, the Company recognized a non-recurring gain in the amount of $2,050,000, reflecting the proceeds of a successful litigation judgment. The litigation was commenced by the Company as plaintiff in February 2000 against the operator of a South Louisiana property which was jointly acquired by the Company and the defendant in September 1999. The judgment provided for recovery of the Company’s damages and a portion of its attorneys’ fees as well as interest calculated on the Company’s damages.
In connection with the acquisition of its Burrwood and West Delta fields in March 2000, the Company assumed obligations associated with the plugging and abandonment of the wells, salvage and removal of platforms and related equipment, and the site restoration of the fields. The Company secured a performance bond and established an escrow account to be used for the payment of these obligations. The current balance in the escrow account is $2,039,000 and is reflected on the accompanying Balance Sheet as restricted cash.
The Company is party to various lawsuits arising in the normal course of business. The Company intends to defend these actions vigorously and believes, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to its financial position or results of operations.
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Management’s Discussion and Analysis of Financial
Condition and Results of Operations
The following discussion is intended to assist in understanding the Company’s financial position, results of operations and cash flows for each of the periods presented. The Company’s Annual Report on Form 10-K for the year ended December 31, 2004 includes a description of the Company’s critical accounting policies and certain other detailed information that should be referred to in conjunction with the following discussion.
Changes in Results of Operations
Three months ended September 30, 2005 versus three months ended September 30, 2004 —Total revenues from continuing operations for the three months ended September 30, 2005 amounted to $17,258,000 compared to $12,014,000 for the three months ended September 30, 2004. Oil and gas sales for the three months ended September 30, 2005 were $17,173,000 compared to $11,983,000 for the three months ended September 30, 2004. This increase resulted from a 5% increase in oil and gas production volumes, due to an increase in Cotton Valley Trend production partially offset by a decline in South Louisiana production arising largely from hurricane shutins, as well as higher average prices for oil and gas. The following table presents the production volumes and pricing information for the comparative periods, including amounts attributable to discontinued operations, with the average oil and gas prices including realized gains and losses on the effective portion of the Company’s commodity hedging program as further described under “Quantitative and Qualitative Disclosures about Market Risk – Commodity Hedging Activity.”
| Three months ended September 30, 2005 | Three months ended September 30, 2004 | |||||||||
| Production | Average Price | Production | Average Price | |||||||
Gas (Mcf) | 1,573,187 | $ | 8.65 | 1,344,736 | $ | 5.80 | ||||
Oil (Bbls) | 98,241 | 36.31 | 120,904 | 35.99 | ||||||
Other revenues for the three months ended September 30, 2005 were $85,000 compared to $30,000 for the three months ended September 30, 2004.
Lease operating expense from continuing operations was $2,404,000 for the three months ended September 30, 2005 versus $1,850,000 for the three months ended September 30, 2004, with the increase due to an increase in production volumes as well as an increase in operating expenses in South Louisiana. Production taxes from continuing operations were $1,178,000 in the three months ended September 30, 2005 compared to $881,000 in the third quarter of 2004, with the increase due to higher production volumes and product prices. Depletion, depreciation and amortization expense from continuing operations was $6,696,000 for the three months ended September 30, 2005 versus $3,173,000 for the three months ended September 30, 2004, with the increase due to higher equivalent units of production and higher depletion rates primarily resulting from an increase in net capitalized development costs. Exploration expense in the three months ended September 30, 2005 was $1,396,000 compared to $1,865,000 in the three months ended September 30, 2004, with the decrease mainly due to seismic costs in the St. Gabriel field in 2004, partially offset by higher non-producing leasehold amortization expense.
General and administrative expenses amounted to $2,577,000 in the three months ended September 30, 2005 versus $1,641,000 in the third quarter of 2004. The most significant factor in this variance resulted from an increase in the Company’s payroll and employee benefits expense to
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$1,794,000 in the three months ended September 30, 2005 from $1,080,000 in the three months ended September 30, 2004, primarily due to an increase in the number of employees from 45 as of September 30, 2004 to 63 as of September 30, 2005. Audit and compliance costs accounted for most of the increase in other general and administrative expenses.
Interest expense was $344,000 in the three months ended September 30, 2005 compared to $317,000 in the three months ended September 30, 2004, with the increase mainly attributable to an increase in interest rates.
Loss on derivatives not qualifying for hedge accounting amounted to $32,625,000 in the three months ended September 30, 2005, compared to zero in the three months ended September 30, 2004. The 2005 amount arose because the Company’s natural gas hedges have been deemed to be ineffective since the fourth quarter of 2004, which has resulted in the changes in fair value of such hedges since that time being reflected in earnings rather than in other comprehensive income, a component of stockholders’ equity (also included in this loss amount are settlement payments on ineffective gas hedges). As applied to the Company’s hedging program, there must be a high degree of correlation between the actual prices received and the hedge prices in order to justify treatment as cash flow hedges pursuant to SFAS 133. The Company performs historical correlation analyses of the actual and hedged prices over an extended period of time. In the fourth quarter of 2004, the Company initially determined that its gas hedges fell short of the effectiveness guidelines to be accounted for as cash flow hedges and, likewise, made the same determination in each of the first three quarters of 2005. To the extent that the Company’s hedges are not deemed to be effective in the future, the Company will likewise be exposed to volatility in earnings resulting from changes in the fair value of its hedges.
Gains and losses on asset sales and litigation judgment were a net gain of zero in the three months ended September 30, 2005 compared to $2,046,000 in the three months ended September 30, 2004, with the decrease due to a non-recurring gain for the proceeds of a successful litigation judgment.
Income taxes were a benefit of $10,488,000 in the three months ended September 30, 2005 representing 35% of the pre-tax loss. Income taxes from continuing operations were an expense of $45,000 in the three months ended September 30, 2004 reflecting a revision in the deferred tax valuation allowance of $1,471,000, based on the anticipated reversal of temporary differences. The net deferred tax asset as of September 30, 2005 is expected to be realized based upon expected utilization of tax net operating loss carryforwards and the projected reversal of temporary differences.
Nine months ended September 30, 2005 versus nine months ended September 30, 2004 —Total revenues from continuing operations for the nine months ended September 30, 2005 amounted to $43,132,000 compared to $31,969,000 for the nine months ended September 30, 2004. Oil and gas sales for the nine months ended September 30, 2005 were $42,884,000 compared to $31,824,000 for the nine months ended September 30, 2004. This increase resulted from a 9% increase in oil and gas production volumes, due to an increase in Cotton Valley Trend production partially offset by a decline in South Louisiana production, as well as higher average prices for oil and gas. The following table presents the production volumes and pricing information for the comparative periods, including amounts attributable to discontinued operations, with the average oil and gas prices including realized gains and losses on the effective portion of the Company’s commodity hedging program as further described under “Quantitative and Qualitative Disclosures about Market Risk – Commodity Hedging Activity.”
| Nine months ended September 30, 2005 | Nine months ended September 30, 2004 | |||||||||
| Production | Average Price | Production | Average Price | |||||||
Gas (Mcf) | 4,093,794 | $ | 7.51 | 3,362,924 | $ | 6.08 | ||||
Oil (Bbls) | 324,298 | 37.49 | 366,295 | 32.35 | ||||||
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Other revenues for the nine months ended September 30, 2005 were $247,000 compared to $145,000 for the nine months ended September 30, 2004.
Lease operating expense from continuing operations was $6,936,000 for the nine months ended September 30, 2005 versus $4,978,000 for the nine months ended September 30, 2004, with the increase due to an increase in production volumes as well as an increase in operating expenses in South Louisiana. Production taxes from continuing operations were $2,934,000 in the nine months ended September 30, 2005 compared to $2,154,000 in the nine months ended September 30, 2004, with the increase due to higher production volumes and product prices. Depletion, depreciation and amortization expense from continuing operations was $18,287,000 for the nine months ended September 30, 2005 versus $8,314,000 for the nine months ended September 30, 2004, with the increase due to higher equivalent units of production and higher depletion rates primarily resulting from an increase in net capitalized development costs. Exploration expense in the nine months ended September 30, 2005 was $5,339,000 compared to $3,881,000 in the nine months ended September 30, 2004, with the increase due to dry hole costs in the amount of $2,012,000 applicable to an exploratory well drilled in East Baton Rouge Parish, Louisiana, and an increase in non-producing leasehold amortization expense, partially offset by a decrease in seismic costs in the St. Gabriel field incurred in 2004.
General and administrative expenses amounted to $6,034,000 in the nine months ended September 30, 2005 versus $4,473,000 in the nine months ended September 30, 2004. The most significant factor in this variance resulted from an increase in the Company’s payroll and employee benefits expense to $4,421,000 in the nine months ended September 30, 2005 from $2,789,000 in the nine months ended September 30, 2004, primarily due to an increase in the number of employees. Partially offsetting this increase was a net decrease in other administrative expenses, primarily legal fees.
Interest expense was $1,139,000 in the nine months ended September 30, 2005 compared to $789,000 in the nine months ended September 30, 2004, with the increase attributable to an increase in interest rates as well as an increase in the level of average borrowings outstanding during the period.
Loss on derivatives not qualifying for hedge accounting amounted to $42,736,000 in the nine months ended September 30, 2005, compared to zero in the nine months ended September 30, 2004. The 2005 amount arose because the Company’s natural gas hedges have been deemed to be ineffective since the fourth quarter of 2004, which has resulted in the changes in fair value of such hedges since that time being reflected in earnings rather than in other comprehensive income, a component of stockholders’ equity (also included in this loss amount are settlement payments on ineffective gas hedges). As applied to the Company’s hedging program, there must be a high degree of correlation between the actual prices received and the hedge prices in order to justify treatment as cash flow hedges pursuant to SFAS 133. The Company performs historical correlation analyses of the actual and hedged prices over an extended period of time. In the fourth quarter of 2004, the Company initially determined that its gas hedges fell short of the effectiveness guidelines to be accounted for as cash flow hedges and, likewise, made the same determination in each of the first three quarters of 2005. To the extent that the Company’s hedges are not deemed to be effective in the future, the Company will likewise be exposed to volatility in earnings resulting from changes in the fair value of its hedges.
Gains and losses on asset sales and litigation judgment were a net gain of $169,000 in the nine months ended September 30, 2005 compared to $1,987,000 in the nine months ended September 30, 2004, with the decrease due to a non-recurring gain for the proceeds of a successful litigation judgment.
Income taxes were a benefit of $14,035,000 in the nine months ended September 30, 2005 representing 35% of the pre-tax loss. Income taxes from continuing operations were an expense of $171,000 in the nine months ended September 30, 2004 reflecting a revision in the deferred tax valuation allowance of $3,106,000, based on the anticipated reversal of temporary differences. The net deferred tax asset as of September 30, 2005 is expected to be realized based upon expected utilization of tax net operating loss carryforwards and the projected reversal of temporary differences.
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Liquidity and Capital Resources
Net cash provided by operating activities was $42,894,000 in the nine months ended September 30, 2005 compared to $24,108,000 in the nine months ended September 30, 2004. The increase in the 2005 period reflects higher oil and gas revenues, partially offset by increases in lease operating, and exploration and administrative expenses. The operating cash flow amounts are net of changes in current assets and current liabilities, which resulted in an increase in operating cash flow of $19,180,000 in the nine months ended September 30, 2005, compared to an increase of $5,100,000 in the nine months ended September 30, 2004.
Net cash used in investing activities was $106,079,000 in the nine months ended September 30, 2005, compared to $28,800,000 in the nine months ended September 30, 2004. In the first three quarters of 2005, capital expenditures totaled $106,227,000, as the Company incurred substantial drilling costs in East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”) as well as in South Louisiana. In the first three quarters of 2004, capital expenditures totaled $28,809,000, as the Company participated in the drilling of two successful exploratory wells in the Burrwood/West Delta 83 field in South Louisiana and commenced its Cotton Valley Drilling Program.
Net cash provided by financing activities was $61,793,000 in the nine months ended September 30, 2005 compared to $4,964,000 in the nine months ended September 30, 2004. In May 2005, the Company completed a public offering of 3,710,000 shares of its common stock resulting in net proceeds of $53,175,000 which was used to repay all then outstanding indebtedness to BNP Paribas under a senior credit facility. The Company made borrowings under its senior credit facility both before and after the May 2005 public equity offering and such borrowings, net of repayments and issuance costs, provided cash in the nine months ended September 30, 2005 in the amount of $8,854,000. Also in the nine months ended September 30, 2005, exercises of stock warrants and options provided cash of $477,000, while preferred stock dividends and production payments used cash of $713,000. In the nine months ended September 30, 2004, net borrowings under the senior credit facility provided cash of $5,500,000 and exercises of stock warrants and options provided cash of $169,000, while preferred stock dividends and production payments used cash of $705,000.
In September 2005, the Company announced that its Board of Directors had authorized an increase in its 2005 capital expenditure budget to approximately $135 million. A substantial portion of the 2005 capital expenditure budget is expected to be focused on a relatively low risk development drilling program in the Cotton Valley Trend of East Texas and Northwest Louisiana (see “Cotton Valley Drilling Program”) and the remainder on the Company’s existing properties and new exploration programs. With the completion of the public equity offering in May 2005, the Company expects to finance its remaining 2005 capital expenditures through a combination of cash flow from operations and borrowings under an anticipated expansion of its senior credit facility (see “Senior Credit Facility”). The Company continuously evaluates its existing and prospective financial resources for the funding of capital expenditures and other long term obligations, including the servicing of its current and possible future working capital deficits.
Cotton Valley Drilling Program
In the first quarter of 2004, the Company commenced what it believes is a relatively low risk drilling program which was initially focused on operated acreage in the Cotton Valley Trend in and around Rusk and Panola Counties, Texas, and DeSoto and Caddo Parishes, Louisiana. In addition, the Company acquired a 40% non-operated working interest in approximately 45,000 gross acres in Angelina
20
and Nacogdoches Counties, Texas, in August 2005. As of September 30, 2005, the Company had acquired or farmed in leases totaling approximately 115,000 gross acres (65,000 net acres) and is attempting to acquire additional acreage in the area. As of September 30, 2005, the Company had successfully drilled and completed 42 operated wells in the Cotton Valley formation. For the wells drilled and completed through September 30, 2005, the Company estimates that the average initial gross production rate per well is approximately 1,500 Mcfe of gas per day. Taking into account the expected decline following the initial production period, the Company’s net production volumes from its Cotton Valley Trend wells aggregated approximately 11,000 Mcfe of gas per day in the third quarter of 2005, or approximately 47% of its total oil and gas production in the period, compared to approximately 4% of its total oil and gas production in the third quarter of 2004.
In East Texas, the Company began leasing acreage in the first quarter of 2004 and commenced a drilling program in April 2004. As of September 30, 2005, the Company had drilled and completed a total of 38 successful wells in East Texas on its operated acreage targeting the Cotton Valley formation. The Company has an average working interest of approximately 95% in the wells drilled and completed on its operated acreage to date. In September 2005, the drilling of an initial exploratory well, in which the Company has a 40% working interest, commenced on the Company’s non-operated acreage in Nacogdoches County.
In Northwest Louisiana, the Company commenced a drilling program targeting the Cotton Valley formation in the first quarter of 2004 and has currently completed four Cotton Valley wells. The Company’s initiative in this area began in the third quarter of 2003, when it obtained, via farmout, exploration rights to approximately 18,000 gross acres in the Bethany-Longstreet field. The Company retains continuous drilling rights to the entire block so long as it drills at least one well within 120 days from previous operations. For each productive well drilled under the agreement, the Company earns an assignment to 160 acres. The Company began exploration and development drilling activities in the field and completed three successful wells in a shallower formation in the fourth quarter of 2003. The Company has a 70% working interest in the Bethany-Longstreet field.
South Louisiana Operations
Burrwood/West Delta 83 Fields— During the first quarter of 2005, the initial well on the Company’s Tunney prospect in the Burrwood/West Delta 83 field went off production from the initial zone due to reservoir depletion. This well, in which the Company owns an approximate 40% working interest, was successfully recompleted in two sands in a dual completion in April 2005. In the second quarter of 2005, the Company commenced drilling of its Leonard and Frazier prospect wells, with the Leonard well being successful and the Frazier well being unsuccessful. On August 24, 2005, the field was shutin due to Hurricane Katrina and, except for the partial restoration of oil production in mid September, remained shutin for the remainder of the third quarter of 2005, pending resumption of operations by third party pipeline and gas plant operators downstream of the field. The Company estimates that the production shutin during the third quarter of 2005 in Burrwood/West Delta 83 and two smaller fields due to Hurricane Katrina, along with the production shutin in another field in late September due to Hurricane Rita, was a net amount of approximately 550,000 Mcf equivalents, or about 25% of its net production in the third quarter of 2005. As of late October, the Company had restored approximately two-thirds of the lost production to the levels experienced prior to the hurricanes and expects to restore the remaining production in November 2005. Damage to the Company’s facilities from both hurricanes was substantially covered by insurance.
St. Gabriel Field— In July 2004, the Company announced that it had acquired a 70% working interest in 3-D seismic permits and oil and gas lease options enabling it to acquire an approximate 30 square mile 3-D seismic survey over the St. Gabriel field in Ascension and Iberville Parishes, Louisiana. The Company commenced shooting the 3-D seismic survey in July 2004 and data acquisition was completed in September 2004. Processing of the data was completed in November 2004 and drilling of a well on the initial seismic prospect is expected to begin in the fourth quarter of 2005.
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Senior Credit Facility
The Company has a $65,000,000 senior credit facility with BNP Paribas maturing on February 25, 2008. It presently provides for borrowings of up to $50,000,000 on Tranche A and $15,000,000 on Tranche B, however, it is anticipated to be expanded and extended in the fourth quarter of 2005.
Tranche A borrowings are subject to periodic redeterminations of the borrowing base which was established at $44,000,000 in February 2005 and is anticipated to be increased in the fourth quarter of 2005. Interest on Tranche A borrowings accrues at a rate calculated, at the option of the Company, at either the BNP Paribas base rate plus 0.00% to 0.50%, or LIBOR plus 1.50%—2.50%, depending on borrowing base utilization. Prior to maturity, no principal payments are required so long as the maximum borrowing base amount exceeds outstanding Tranche A borrowings. Tranche B borrowings can be made with the approval of BNP Paribas to finance development of the Company’s acreage in the Cotton Valley Trend of East Texas and Northwest Louisiana. Interest on Tranche B borrowings accrues at a quarterly rate of LIBOR plus 5.0% and principal will be due on February 25, 2008.
The credit facility precludes the payment of dividends on the Company’s common stock and requires the Company to maintain a working capital ratio (as defined) of not less than 1.0:1.0, an interest coverage ratio for the trailing four quarters of at least 3.0 times, and a tangible net worth of not less than the sum of $53,392,838, plus 50% of cumulative net income after September 30, 2004, plus 100% of the net proceeds of any subsequent equity issuance. As of September 30, 2005, the Company was not in compliance with the working capital ratio covenant and the tangible net worth covenant, however, the Company received a waiver from BNP Paribas with respect to those covenants. Substantially all the Company’s assets are pledged to secure the senior credit facility.
In April 2005, the credit agreement was amended to allow the Company to redraw the $7,500,000 initially advanced under Tranche B in the event that it was repaid within 30 days of a public equity offering. In May 2005, the Company completed a public equity offering (see “Liquidity and Capital Resources”) and used the proceeds to repay all outstanding indebtedness under the senior credit facility in the amount of $39,500,000, including $7,500,000 initially advanced under Tranche B.
In July 2005, the Company commenced new Tranche A borrowings to continue funding of its Cotton Valley Trend drilling program. Outstanding Tranche A borrowings as of September 30, 2005 and November 2, 2005 were $36,000,000 and $44,000,000, respectively. Subsequent to September 30, 2005, the Company made new Tranche B borrowings of $7,500,000 resulting in total borrowings outstanding as of November 2, 2005 in the amount of $51,500,000. In October 2005, the Company received a non-binding commitment from BNP Paribas and two co-lenders to expand the senior credit facility to a total of $105 million, consisting of a $75 million Tranche A and a new $30 million second lien facility (in lieu of Tranche B), and to extend the term of the credit facility for an additional two years. Documentation of the expanded and extended credit facility is presently underway and closing of the new credit agreement and initial funding of the $30 million second lien facility is anticipated to take place in mid November 2005.
In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period, as further described below, and in February 2004, entered into another interest rate swap with BNP Paribas for an additional one year period (see “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Swaps”).
22
New Accounting Pronouncements
In December 2004, the FASB issued SFAS No. 123R,Share-Based Payment, a revision of SFAS No. 123,Accounting for Stock-Based Compensation. The revised statement requires the expensing of new, modified or repurchased stock-based compensation awards issued after June 15, 2005. Previously issued stock-based compensation awards, which are unvested as of that date, must also be accounted for in accordance with the revised statement. The revised statement provides for the use of either a closed-form model or open-form lattice model for the valuation of stock option awards. The Company plans to follow the “modified prospective transition approach” to the adoption of the revised statement and is currently evaluating the potential impact that the adoption of the revised statement will have on its financial statements. In April 2005, the SEC adopted a rule permitting registrants to delay the expensing of options, pursuant to SFAS No. 123R, to the first annual period beginning after June 15, 2005. Accordingly, the Company will implement the provisions of SFAS No. 123R in its financial statements, effective January 1, 2006.
In March 2005, the FASB issued FASB Interpretation (FIN) 47, an interpretation of SFAS No. 143,Accounting for Asset Retirement Obligations.FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 143, which the Company adopted on January 1, 2003. The Company applied the guidance in this FIN beginning in the third quarter of 2005 resulting in no impact on its financial statements.
In April 2005, the FASB issued FASB Staff Position (FSP) 19-1 to provide guidance on the accounting for exploratory well costs and to amend SFAS No. 19,Financial Accounting and Reporting by Oil and Gas Producing Companies. The guidance in FSP 19-1 applies to companies that use the successful efforts method of accounting as described in SFAS No. 19. This FSP clarifies that exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The Company adopted the guidance in this FSP prospectively in April 2005 and the adoption had no impact on its financial statements. The Company had no capitalized exploratory costs pending determination of reserves as of September 30, 2005.
23
Quantitative and Qualitative Disclosures About Market Risk
Commodity Hedging Activity
The Company enters into swap contracts, costless collars or other hedging agreements from time to time to manage the commodity price risk for a portion of its production. The Company considers these to be hedging activities and, as such, monthly settlements on these contracts are reflected in its crude oil and natural gas sales, provided the contracts are deemed to be “effective” hedges under FAS 133. The Company’s strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to hedge between 30% and 70% of its production. As of September 30, 2005, the commodity hedges utilized by the Company were in the form of: (a) Swaps, where the Company receives a fixed price and pays a floating price based on NYMEX quoted prices; and (b) Collars, where the Company receives the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pays the excess, if any, of the reference price over the ceiling price. As of September 30, 2005, the Company’s open forward position on its outstanding commodity hedging contracts, all of which were with BNP Paribas, was as follows:
| Natural Gas | Crude Oil | |||||||||
| Quantity (MMBtu/d) | Average Price | Quantity (Barrels/d) | Average Price | |||||||
Swaps | ||||||||||
Fourth Quarter 2005 | 15,000 | $ | 6.61 | 1,000 | $ | 36.85 | ||||
First Quarter 2006 | 14,000 | $ | 7.05 | 700 | $ | 49.75 | ||||
Second Quarter 2006 | 15,000 | $ | 6.95 | 800 | $ | 50.80 | ||||
Third Quarter 2006 | 15,000 | $ | 6.95 | 800 | $ | 50.80 | ||||
Fourth Quarter 2006 | 15,000 | $ | 6.95 | 800 | $ | 50.80 | ||||
First Quarter 2007 | 10,000 | $ | 7.77 | 400 | $ | 53.35 | ||||
Second Quarter 2007 | — | — | 400 | $ | 53.35 | |||||
Third Quarter 2007 | — | — | 400 | $ | 53.35 | |||||
Fourth Quarter 2007 | — | — | 400 | $ | 53.35 | |||||
Collars | ||||||||||
First Quarter 2007 | 10,000 | $ | 7.00 -$16.90 | — | — | |||||
Second Quarter 2007 | 15,000 | $ | 7.00 -$15.90 | — | — | |||||
Third Quarter 2007 | 15,000 | $ | 7.00 -$15.90 | — | — | |||||
Fourth Quarter 2007 | 15,000 | $ | 7.00 -$15.90 | — | — | |||||
The hedging contracts summarized above fall within the Company’s targeted range of its estimated net oil and gas production volumes for the applicable periods of 2005. The fair value of the crude oil and natural gas hedging contracts in place at September 30, 2005 resulted in a liability of $47,461,000. Based on oil and gas pricing in effect at September 30, 2005, a hypothetical 10% increase in oil and gas prices would have increased the liability to $60,125,000 while a hypothetical 10% decrease in oil and gas prices would have decreased the liability to $34,796,000.
Interest Rate Swaps
In February 2003, the Company entered into three separate interest rate swaps with BNP Paribas covering a three year period (two of the interest rate swaps have now expired). The unexpired interest rate swap, which has an effective date of November 8, 2004 and a maturity date of February 26, 2006, is
24
for $18,000,000 with a LIBOR swap rate of 3.46%. In February 2004, the Company entered into another interest rate swap contract with BNP Paribas, which has an effective date of February 26, 2006 and a maturity date of February 26, 2007, for $23,000,000 with a LIBOR swap rate of 4.08%. The fair value of the interest rate swap contracts in place at September 30, 2005, resulted in an asset of $167,000. Based on interest rates at September 30, 2005, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the asset.
Price fluctuations and the volatile nature of markets
Despite the measures taken by the Companyus to attempt to control price risk, the Company remainswe remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond the Company’sour control. Domestic crude oil and gas prices could have a material adverse effect on the Company’sour financial position, results of operations and quantities of reserves recoverable on an economic basis.
Interest Rate Swaps
We have a variable-rate debt obligation that exposes us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. At March 31, 2006 we had the following interest rate swaps in place with BNP (in millions):
Effective Date | Maturity Date | LIBOR Swap Rate | Notional Amount | |||||
02/27/06 | 02/26/07 | 4.08 | % | $ | 23.0 | |||
02/27/06 | 02/26/07 | 4.85 | % | 17.0 | ||||
02/26/07 | 02/26/09 | 4.86 | % | 40.0 | ||||
The fair value of the interest rate swap contracts in place at March 31, 2006, resulted in an asset of $0.5 million. As of March 31, 2006, $153,000 (net of $83,000 in income taxes) of deferred net gains on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. During the quarter ended March 31, 2006, $28,000 of previously deferred gains (net of $14,500 in income taxes) were reclassified from accumulated other comprehensive income to interest expense as the cash flow of the hedged items was recognized.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
We entered into two interest rate swaps to protect against movements in interest rates during the fourth quarter of 2005. The documentation was not prepared at the time of inception for these hedges and as a result, we were not entitled to apply hedge accounting to these instruments. The failure to qualify for hedge accounting requires that all changes in the fair value of the interest rate swap be recorded in the consolidated statements of operations. Accordingly, for the three months ended March 31, 2006, we recognized in earnings a gain of approximately $0.2 million, which is included in the aforementioned total gain of $13.5 million.
NOTE I—Commitments and Contingencies
In July 2005, we received a Notice of Proposed Tax Due from the State of Louisiana asserting that we underpaid our Louisiana franchise taxes for the years 1998 through 2004 in the amount of $0.5 million. The Notice of Proposed Tax Due includes additional assessments of penalties and interest in the amount of $0.4 million for a total asserted liability of $0.9 million. We believe that we have fully paid our Louisiana franchise taxes for the years in question; therefore, we intend to vigorously contest the Notice of Proposed Tax Due. We have commenced our analysis of this contingency and have not recorded any provision for possible payment of additional Louisiana franchise taxes nor any related penalties and interest.
We are party to additional lawsuits arising in the normal course of business. We intend to defend these actions vigorously and believe, based on currently available information, that adverse results or judgments from such actions, if any, will not be material to our financial position or results of operations.
GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Disclosure Regarding Forward-LookingForward Looking Statement
Certain statements in this Quarterly Report on Form 10-Q regarding future expectations and plans for future activities may be regarded as “forward looking statements” within the meaning of Private Securities Litigation Reform Act of 1995. They are subject to various risks, such as financial market conditions, operating hazards, drilling risks and the inherent uncertainties in interpreting engineering data relating to underground accumulations of oil and gas, as well as other risks discussed in detail in the Company’sour Annual Report on Form 10-K, and other filings with the Securities and Exchange Commission.such changes to these factors which are discussed in Part II, Item 1A of this Form 10-Q. Although the Company believeswe believe that the expectations reflected in such forward-looking statements are reasonable, itwe can give no assurance that such expectations will prove to be correct.
Executive Overview
25General
We are an independent oil and gas company engaged in the exploration, exploitation, development and production of oil and natural gas properties primarily in the Cotton Valley Trend of East Texas and Northwest Louisiana and in the transition zone of South Louisiana.
Our business strategy is to provide long term growth in net asset value per share, through the growth and expansion of our oil and gas reserves and production. We focus on adding reserve value through the development of our relatively low risk development drilling program in the Cotton Valley Trend, while maintaining our drilling activities in select high impact well locations in South Louisiana. We continue to aggressively pursue the acquisition and evaluation of prospective acreage, oil and gas drilling opportunities and potential property acquisitions.
Source of Revenue
We derive our revenues from the sale of oil and natural gas that is produced from our properties. Revenues are a function of both the volume produced and the prevailing market price at the time of sale. Production volumes, while somewhat predictable after wells have begun producing, can be impacted for various reasons. Hurricanes Katrina and Rita in the third quarter of 2005 are an example of how production volumes can be impacted to defer volumes from the current period to future periods. The price of oil and natural gas is a primary factor affecting our revenues. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a portion of our oil and natural gas production. While the derivative instruments may protect downward price fluctuation, the use of certain types of derivative instruments may prevent us from realizing the full benefit of upward price movements.
First Quarter 2006 Highlights
Our development, financial and operating performance for the first quarter 2006 included the following highlights:
A more complete overview and discussion of our operations can be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2005 Form 10-K, as amended.
Hurricanes Katrina and Rita Update
In August and September 2005, Hurricanes Katrina and Rita caused damage to our assets on the Gulf Coast. The most significant damage was concentrated on one producing well (Norton) and offshore facilities in our Burrwood/West Delta 83 field. As of March 31, 2006, we have incurred costs associated with Hurricane Katrina of approximately $2.3 million in this field, which are net of our share of insurance proceeds received and accrued to date, and our partners’ share of costs incurred to date. We anticipate that we will be fully reimbursed for all of our insured losses, after deductibles are met. We have an approximate 63% working interest in the Burrwood/West Delta field and the remaining 37% working interest owners participate in the costs, insurance deductible and insurance proceeds that are ultimately received. We anticipate that additional costs related to Hurricane Katrina are still to be incurred, although we do not believe the amount to be significant.
Repairs caused by Hurricane Rita related to our Second Bayou field are substantially complete and we incurred net damage costs of approximately $0.2 million. We have recorded a loss of $0.2 million to date representing amounts incurred that will not ultimately be covered by insurance, of which an additional $20,000 was recorded in the first quarter of 2006. We have an approximate 26% working interest in the Second Bayou field and the remaining 74% working interest owners participate in the costs, insurance deductible and insurance proceeds that are ultimately received.
As claims are submitted to the insurance companies, they are reviewed and preliminary payments made until all losses are incurred and documented. A final payment will be made once we and our insurers agree on the total measurement value of the claim, which is expected sometime during the second quarter of 2006.
Three Months Ended March 31, 2006 Compared to Three Months Ended March 31, 2005
For the three months ended March 31, 2006, we reported net income applicable to common stock of $8.6 million, or $0.34 per basic share on total revenue of $25.3 million as compared with a net loss applicable to common stock of $6.3 million, or $0.30 per basic share, on total revenue of $12.6 million for the three months ended March 31, 2005.
Oil and Natural Gas Revenues
Revenues presented in the table and the discussion below represent revenue from sales of our oil and natural gas production volumes and include the realized gains and losses on the effective portion of our derivative instruments as further described under Note H to the Consolidated Financial Statements.
| Three Months Ended March 31, | % Change from 2005 to 2006 | ||||||||||
| 2006 | 2005 | ||||||||||
Production: | |||||||||||
Natural gas (MMcf) | 2,620 | 1,326 | 98 | % | |||||||
Oil and condensate (MBbls) | 111 | 98 | 13 | % | |||||||
Total (MMcfe) | 3,287 | 1,915 | 72 | % | |||||||
Revenues from production (in thousands): | |||||||||||
Natural gas | $ | 18,664 | $ | 8,620 | 117 | % | |||||
Effects of cash flow hedges | — | — | — | ||||||||
Total | $ | 18,664 | $ | 8,620 | 117 | % | |||||
Oil and condensate | $ | 6,992 | $ | 5,019 | 39 | % | |||||
Effects of cash flow hedges | (751 | ) | (1,208 | ) | (38 | %) | |||||
Total | $ | 6,241 | $ | 3,811 | 64 | % | |||||
Natural gas, oil and condensate | $ | 25,656 | $ | 13,639 | 88 | % | |||||
Effects of cash flow hedges | (751 | ) | (1,208 | ) | (38 | %) | |||||
Total revenues from production | $ | 24,905 | $ | 12,431 | 100 | % | |||||
Average sales price per unit: | |||||||||||
Natural gas (per Mcf) | $ | 7.13 | $ | 6.50 | 10 | % | |||||
Effects of cash flow hedges (per Mcf) | — | — | — | ||||||||
Total (per Mcf) | $ | 7.13 | $ | 6.50 | 10 | % | |||||
Oil and condensate (per Bbl) | $ | 62.84 | $ | 51.16 | 23 | % | |||||
Effects of cash flow hedges (per Bbl) | (6.75 | ) | (12.32 | ) | (45 | %) | |||||
Total (per Bbl) | $ | 56.09 | $ | 38.84 | 44 | % | |||||
Natural gas, oil and condensate (per Mcfe) | $ | 7.81 | $ | 7.12 | 10 | % | |||||
Effects of cash flow hedges (per Mcfe) | (0.23 | ) | (0.63 | ) | (64 | %) | |||||
Total (per Mcfe) | $ | 7.58 | $ | 6.49 | 17 | % | |||||
Excluding the effects of settled derivatives, revenues from production increased 88% in the first quarter of 2006 compared to the same period in 2005 due primarily to a substantial increase in Cotton Valley Trend production. Revenues were also impacted favorably by a 10% increase in our sales price per unit.
Lease Operating. Lease operating expense for the first quarter of 2006 increased on an absolute basis ($3.6 million compared to $2.2 million) but decreased on a per unit basis ($1.09 per Mcfe compared to $1.17 per Mcfe) from the first quarter of 2005. This decrease in unit costs was primarily attributable to a greater proportion of our production volumes coming from the lower cost environment in the Cotton Valley Trend. Our South Louisiana lease operating expenses were negatively impacted by an accrual of $350,000 for the estimated costs of cleaning up an oil spill that occurred from a non-producing well in our Plumb Bob field on March 21, 2006. The spill of an estimated 1,000 to 1,500 barrels of oil was quickly contained and the costs of site restoration will be covered by our insurance once a deductible is met. Our cost accrual for site restoration reflects our share of the insurance deductible.
Production Taxes.Production taxes increased to $1.6 million for the first quarter of 2006 compared to $0.8 million for the comparable period in 2005 due to an increase in production volumes and product prices. Our Cotton Valley Trend wells qualify for the “Tight Gas Sands” credit allowed for severance tax in the State of Texas. While we have only partially reflected such credits in the first quarter of 2006, we anticipate that we will incur a gradually lower production tax rate in the future as we add further Cotton Valley wells to our production base and as reduced rates are approved and credits are received.
Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) expense increased to $9.8 million from $5.8 million for the same period in 2005 primarily due to higher levels of production. The average DD&A rate decreased to $2.99 per Mcfe in the first quarter of 2006 compared to $3.05 per Mcfe in the same quarter of 2005 due to a higher percentage of production coming from fields with lower average DD&A rates.
General and Administrative.General and administrative expense increased to $3.8 million for the first quarter of 2006 compared to $1.6 million for the same period of 2005. This increase was primarily due to higher compensation related costs due to an approximate 40% increase in the number of employees at March 31, 2006 versus March 31, 2005. With the implementation of SFAS 123R, non cash stock based compensation expense increased approximately $0.7 million from the first quarter of 2005 due to expensing the fair value of stock options granted. See Note C for more information.
Interest Expense.Interest expense increased to $0.7 million from the first quarter 2005 amount of $0.3 million as a result of a higher average interest rate in the first quarter of 2006.
Gain (Loss) on Derivatives Not Qualifying for Hedge Accounting. Gain on derivatives not qualifying for hedge accounting was $13.5 million for the first quarter of 2006 compared to a loss of $9.8 million for the first quarter of 2005. The gain in 2006 includes an unrealized gain of $15.9 million for the changes in fair value of our ineffective oil and gas hedges, and a realized loss of $2.6 million for the effect of settled derivatives on our ineffective gas hedges. Our natural gas hedges were deemed ineffective, beginning in the fourth quarter of 2004, and we have been required to reflect the changes in the fair value of our natural gas hedges in earnings rather than in accumulated other comprehensive loss, a component of stockholders’ equity. Also included in the 2006 amount is an unrealized gain of $0.2 million related to interest rate swaps that did not qualify for hedge accounting treatment. To the extent that our hedges do not qualify for hedge accounting in the future, we will likewise be exposed to volatility in earnings resulting from changes in the fair value of our hedges.
Income taxes. Income taxes were an expense of $6.2 million for the first quarter of 2006 compared to a benefit of $3.3 million for the first quarter of 2005. The amounts in both periods essentially represented 35% of pre-tax income (loss). We did not however, incur any income taxes on a current basis due to our substantial tax net operating loss carrryforwards.
Liquidity and Capital Resources
Cash Flows
Operating activities. Net cash provided by operating activities increased to $25.8 million, up 153% from $10.2 million in the first quarter of 2005. The increase was a result of an increase in production levels and natural gas and crude oil prices and in the first quarter of 2006 compared to the first quarter of 2005, partially offset by increases in lease operating expenses and general and administrative expenses. Excluding the effect of settled derivatives, sales of oil and gas increased $12.0 million in the first quarter of 2006 compared to the same period in 2005, with realized oil and natural gas prices increasing 10% from the first quarter of 2005. Production volumes increased 72% in the first quarter of 2006 compared to the first quarter of 2005. Operating cash flow amounts are net of changes in our current assets and current liabilities, which resulted in adjustments to our operating cash flow in the amounts of $12.1 million and $2.0 million, respectively, in the three months ended March 31, 2006 and 2005, primarily reflecting increased revenue and expenditure activity associated with our Cotton Valley Trend wells.
Investing activities. Net cash used in investing activities was $62.6 million for the first quarter of 2006 compared to $20.8 million for the first quarter of 2005. For the three months ended March 31, 2006, capital expenditures totaled $63.4 million primarily due to accelerated development of our Cotton Valley Trend, which accounted for 94% of the capital costs incurred in the first quarter of 2006. We conducted drilling operations on approximately 30 gross wells, of which 28 were located in our Cotton Valley Trend, during the first quarter of 2006. We also received proceeds of $0.9 million from the sale of a salt water disposal facility.
Financing activities. Net cash provided by financing activities was $18.5 million for the first quarter of 2006 compared to $8.5 million for the first quarter of 2005. On January 23, 2006, the initial purchasers of the Series B Convertible Preferred Stock exercised their over-allotment option to purchase an additional 600,000 shares at the same price per share, resulting in net proceeds of $29.0 million, which will be used to fund our 2006 capital expenditure program. In February 2006, we fully redeemed all issued and outstanding shares of our Series A Convertible Preferred Stock at a cost of approximately $9.3 million. Dividends paid on both of our series of preferred stock totaled $1.2 million for the quarter.
In December 2005, our Board of Directors approved a preliminary 2006 capital expenditure budget of approximately $195.0 million, of which approximately 85% is expected to be focused on the relatively low risk development drilling program in the Cotton Valley Trend of East Texas and Northwest Louisiana and the remainder on our existing properties and new exploration programs. Our Board may increase our capital expenditure budget for 2006, subject to future economic conditions and financial resources. We expect to finance our 2006 capital expenditures through a combination of cash flow from operations and borrowings under our existing bank credit facility (see “Senior Credit Facility and Term Loan”). In the future, we may issue additional debt or equity securities to provide additional financial resources for our capital expenditures and other general corporate purposes. Our senior credit facility and term loan include certain financial covenants with which we were in compliance as of March 31, 2006. We do not anticipate a lack of borrowing capacity under our senior credit facility or term loan in the foreseeable future due to an inability to meet any such financial covenants nor a reduction in our borrowing base.
Senior Credit Facility and Term Loan
On November 17, 2005, we amended our existing credit agreement and entered into an amended and restated senior credit agreement (the “Amended and Restated Credit Agreement”) and a funded $30.0 million second lien term loan (the “Second Lien Term Loan Agreement”) that expanded our borrowing capabilities and extended our credit facility for an additional two years. Total lender commitments under the Amended and Restated Credit Agreement were increased from $50.0 million to $200.0 million and the maturity was extended from February 25, 2008 to February 25, 2010. Revolving borrowings under the Amended and
Restated Credit Agreement are subject to periodic redeterminations of the borrowing base which is currently established at $75.0 million, and is currently scheduled to be redetermined in May 2006, based upon our 2005 year-end reserve report. With a portion of the net proceeds of the offering of Series B Convertible Preferred Stock in December 2005, we fully repaid all outstanding indebtedness on our revolver in the amount of $47.5 million leaving a zero balance outstanding as of December 31, 2005 (see Note F). Interest on revolving borrowings under the Amended and Restated Credit Agreement accrues at a rate calculated, at our option, at either the bank base rate plus 0.00% to 0.50%, or LIBOR plus 1.25% to 2.00%, depending on borrowing base utilization. BNP Paribas (“BNP”) is the lead lender and administrative agent under the amended credit facility with Comerica Bank and Harris Nesbit Financing, Inc. as co-lenders.
The terms of the Amended and Restated Credit Agreement require us to maintain certain covenants. Capitalized terms are defined in the credit agreement. The covenants include:
As of March 31, 2006, we were in compliance with all of the financial covenants of the Amended and Restated Credit Agreement. In the second quarter of 2006, we resumed borrowings under the revolving credit facility in order to fund our 2006 capital expenditure program. Borrowings to date are $25.5 million.
The Second Lien Term Loan Agreement provides for a 5-year, non-revolving loan of $30.0 million which was funded on November 17, 2005 and is due in a single maturity on November 17, 2010. Optional prepayments of term loan principal can be made in amounts of not less than $5.0 million during the first year at a 1% premium and without premium after the first year. Interest on term loan borrowings accrues at a rate calculated, at our option, at either base rate plus 3.50%, or LIBOR plus 4.50%, and is payable quarterly. BNP is the lead lender and administrative agent under the Second Lien Term Loan Agreement.
The terms of the Second Lien Term Loan Agreement require us to maintain certain covenants. Capitalized terms are defined in the loan agreement. The covenants include:
As of March 31, 2006, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.
Cotton Valley Trend
Our relatively low risk development drilling program in the Cotton Valley Trend is primarily centered in and around Rusk, Panola, Angelina and Nacogdoches Counties, Texas, and DeSoto and Caddo Parishes, Louisiana. In addition, we have recently expanded our acreage position in the Trend to include Harrison, Smith and Upshur Counties of Texas. We have steadily increased our acreage position in these areas over the last two years to approximately 130,000 gross acres as of April 30, 2006. As of April 30, 2006, we have drilled and/or logged a cumulative total of 100 Cotton Valley wells with a 100% success rate, of which drilling operations were conducted on 28 gross wells during the first quarter of 2006. Our net production volumes from our Cotton Valley Trend wells aggregated approximately 22,200 Mcfe of gas per day in the first quarter of 2006, or approximately 61% of our total oil and gas production in the period.
South Louisiana Operations
Burrwood/West Delta 83 Fields— During the first quarter of 2006, we conducted drilling activities on our Norton II development prospect. Subsequent to the end of the quarter, we reached total depth and logged apparent oil and natural gas pay over an approximate 100 feet of gross (60 feet net) interval in the 10,500’ sand. We expect to initiate production from the well during the second quarter of 2006.
In late August 2005, our Burrwood/West Delta 83 field was shut-in due to Hurricane Katrina and, except for the partial restoration of oil production in mid September, remained shut-in for the remainder of the third quarter of 2005. Production was gradually restored in the fourth quarter of 2005 and the first quarter of 2006. As of March 31, 2006, we had restored approximately 90% of our total pre-hurricane volumes in South Louisiana, including the Burrwood/West Delta 83 field and the Second Bayou field, which was impacted to a lesser extent by Hurricane Rita in September 2005. Our remaining pre-hurricane production volumes are temporarily shut-in awaiting completion of facility and well repairs. Damage to our facilities from both hurricanes was substantially covered by insurance.
St. Gabriel Field— In the first quarter of 2006, we commenced an exploratory test well on our Bordeaux Prospect. In March 2006, we announced that an open hole log on the test well, the Gueymard No. 1, had encountered approximately 60 feet of net pay. The well was completed in April 2006 and has preliminarily tested at a gross production rate of approximately 4,000 Mcf of gas per day and 200 barrels of oil per day with 5,000 pounds of flowing tubing pressure. We currently anticipate drilling one additional well in the field later in 2006.
Accounting Pronouncements
See Note B to our Consolidated Financial Statements for a discussion of recently issued accounting pronouncements.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations are based on consolidated financial statements which have been prepared in accordance with generally accepted accounting principles in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts or assets, liabilities, revenues and expenses. We believe that certain accounting policies affect our more significant judgments and estimates used in the preparation of our consolidated financial statements. Our 2005 Annual Report on Form 10-K, as amended, includes a discussion of our critical accounting policies. In addition, following the adoption of SFAS 123R, we consider our policies related to share-based compensation to be a critical accounting policy.
Share-Based Compensation Plans.In January 2006, we adopted SFAS 123R which amends SFAS 123 and supercedes APB 25. SFAS 123R requires new, modified and unvested share-based payment transactions with employees to be measured at fair value and recognized as compensation expense over the vesting period. The fair value of each option award is estimated using a Black-Scholes option valuation model that requires us to develop estimates for assumptions used in the model. The Black-Scholes valuation model uses the following assumptions: expected volatility, expected term of option, risk-free interest rate and dividend yield. Expected volatility estimates are developed by us based on historical volatility of our stock. We use historical data to estimate the expected term of the options. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield in effect at the grant date. Our common stock does not pay dividends; therefore the dividend yield is zero.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Despite the measures taken by us to attempt to control price risk, we remain subject to price fluctuations for natural gas and crude oil sold in the spot market. Prices received for natural gas sold on the spot market are volatile due primarily to seasonality of demand and other factors beyond our control. Domestic crude oil and gas prices could have a material adverse effect on our financial position, results of operations and quantities of reserves recoverable on an economic basis.
We enter into futures contracts or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these agreements to be hedging activities and, as such, monthly settlements on the contracts that qualify for hedge accounting are reflected in our crude oil and natural gas sales. Our strategy, which is administered by the Hedging Committee of the Board of Directors, and reviewed periodically by the entire Board of Directors, has been to generally hedge between 30% and 70% of our production. As of March 31, 2006, the commodity hedges we utilized were in the form of: (a) swaps, where we receive a fixed price and pay a floating price, based on NYMEX quoted prices; and (b) collars, where we receive the excess, if any, of the floor price over the reference price, based on NYMEX quoted prices, and pay the excess, if any, of the reference price over the ceiling price. See Note H to the Consolidated Financial Statements for additional information.
The fair value of the crude oil and natural gas hedging contracts in place at March 31, 2006 resulted in a liability of $14.7 million. Based on oil and gas pricing in effect at March 31, 2006, a hypothetical 10% increase in oil and gas prices would have increased the derivative liability to $21.6 million while a hypothetical 10% decrease in oil and gas prices would have decreased the derivative liability to an asset of $7.9 million.
Interest Rate Risk
We have a variable-rate debt obligation that exposes us to the effects of changes in interest rates. To partially reduce our exposure to interest rate risk, from time to time we enter into interest rate swap agreements. At March 31, 2006 we had the following interest rate swaps in place with BNP (in millions).
Effective Date | Maturity Date | LIBOR Swap Rate | Notional Amount | |||||
02/27/06 | 02/26/07 | 4.08 | % | $ | 23.0 | |||
02/27/06 | 02/26/07 | 4.85 | % | 17.0 | ||||
02/26/07 | 02/26/09 | 4.86 | % | 40.0 | ||||
The fair value of the interest rate swap contracts in place at March 31, 2006 resulted in an asset of $0.5 million. Based on interest rates at March 31, 2006, a hypothetical 10% increase or decrease in interest rates would not have a material effect on the asset.
Item 4. Controls and Procedures
The Company, under the directionOur Chief Executive Officer and Chief Financial Officer performed an evaluation of its chief executive officer and chief financial officer, has established controls and procedures to ensure that material information relating to the Company and its consolidated subsidiaries is made known to the officers who certify the company’s financial reports and to other members of senior management and the Board of Directors.
Based on their evaluation as of September 30, 2005, the chief executive officer and chief financial officer of Goodrich Petroleum Corporation have concluded that the Company’sour disclosure controls and procedures (asprocedures. As defined in Exchange Act Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act, disclosure controls and procedures are controls and other procedures of 1934) were effective as of September 30, 2005the Company that are designed to ensure that the information required to be disclosed by Goodrich Petroleum Corporationthe Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in SECthe SEC’s rules and forms.
There were no changes Based on this evaluation, and following discussions with our independent registered public accounting firm, KPMG LLP, our Chief Executive Officer and Chief Financial Officer concluded that, as of March 31, 2006, due to the material weakness discussed in the Company’ssubsequent paragraph, our disclosure controls and procedures were not effective as further detailed below.
On April 28, 2006, we were advised by our independent registered public accounting firm, KPMG LLP, of the discovery of an error in the failure to record the fair value of commodity price collars in place at March 31, 2006, which did not qualify for hedge accounting. We have corrected this error, which resulted in recording an additional charge to earnings of $1.9 million before taxes in the first quarter of 2006. No results of operations for prior periods were affected by this error.
We believe that our control procedures over recording the fair value of all outstanding derivatives were not operating effectively at March 31, 2006 and that this deficiency in internal control over financial reporting at March 31, 2006 is a material weakness. This control deficiency could result in a misstatement to our annual or interim financial statements that would not be prevented or detected. Our executive management is currently evaluating our accounting resource needs and existing controls over derivative accounting and anticipates taking appropriate remedial action in the near term.
Except as noted above, there has been no change in our internal controls or in other factorsover financial reporting that haveoccurred during the three months ended March 31, 2006 that has materially affected, or areis reasonably likely to materially affect, the Company’sour internal controls over financial reporting. See Item 1A – “Risk Factors” in Part II of this Report.
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Item 1. Legal Proceedings.1A – Risk Factors
For a description of the Company’s legal proceedings, see Note GIn addition to the Consolidated Financial Statements includedother information set forth in this report, you should carefully consider the factors discussed in Part I, Item 1 of this quarterly report1A. “Risk Factors” in our Annual Report on Form 10-Q, and10-K for the year ended December 31, 2005, which could materially affect our business, financial condition or future results. In addition, as disclosed in Part I, Item 34, we believe that our control procedures over recording the fair value of the Company’sall outstanding derivatives were not operating effectively at March 31, 2006 and that this deficiency in internal control over financial reporting at March 31, 2006 is a material weakness. This control deficiency could result in a misstatement to our annual or interim financial statements that would not be prevented or detected. Please read Part I, Item 4 for more information about this control deficiency. The risks described in our Annual Report on Form 10-K filed on March 25, 2005.
and the risk associated with our identified deficiency in internal control over financial reporting, are not the only risks facing our Company. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition and/or operating results.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.6 – Exhibits
None.
Item 3. Defaults Upon Senior Securities.
None.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
Not applicable.
| (b) | Exhibits |
| *31.1 | Certification | |
| *31.2 | Certification | |
| **32.1 | Certification | |
| **32.2 | Certification | |
| * | Filed herewith |
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| ** | Furnished herewith |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned and thereunto duly authorized.
| GOODRICH PETROLEUM CORPORATION | ||||||||
| ||||||||
Date: May 8, 2006 | By: | /s/ Walter G. Goodrich | ||||||
Walter G. Goodrich | ||||||||
Vice Chairman & Chief Executive Officer | ||||||||
Date: May 8, 2006 | By: | /s/ D. Hughes Watler, Jr. | ||||||
D. Hughes Watler, Jr. | ||||||||
Senior Vice President & Chief Financial Officer | ||||||||
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