Goodrich Petroleum 10-Q 2005 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT 1934

For the quarterly period ended September 30, 2005

Or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT 1934

For the transition period from            to            

Commission File Number: 1-7940

Goodrich 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 ID. No.)
808 Travis Street, Suite 1320, Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(713) 780-9494

(Registrant’s telephone number, including area code)

None

(Former name, former address and former fiscal year, if changed since last report.)

Indicate by check mark whether the registrant (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 registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act):    Yes  ¨    No  x

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.):    Yes  ¨    No  x

At November 2, 2005, there were 24,788,745 shares of Goodrich Petroleum Corporation common stock outstanding.

GOODRICH PETROLEUM CORPORATION

INDEX TO FORM 10-Q

September 30, 2005

	Page No.
PART 1 - FINANCIAL INFORMATION
Item 1. Financial Statements.
Consolidated Balance Sheets September 30, 2005 (Unaudited) and December 31, 2004	3-4
Consolidated Statements of Operations (Unaudited)
Three Months Ended September 30, 2005 and 2004	5
Nine Months Ended September 30, 2005 and 2004	6
Consolidated Statements of Cash Flows (Unaudited) Nine Months Ended September 30, 2005 and 2004	7
Consolidated Statements of Stockholders’ Equity and Comprehensive Income (Unaudited) Nine Months Ended September 30, 2005 and 2004	8
Notes to Consolidated Financial Statements (Unaudited)	9-16
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.	17-23
Item 3. Quantitative and Qualitative Disclosures About Market Risk.	24
Item 4. Controls and Procedures.	26
PART II - OTHER INFORMATION	27
Item 1. Legal Proceedings.	27
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.	27
Item 3. Defaults upon Senior Securities.	27
Item 4. Submission of Matters to a Vote of Security Holders.	27
Item 5. Other Information.	27
Item 6. Exhibits.	27

2

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

	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

See notes to consolidated financial statements.

3

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets (Continued)

	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

See notes to consolidated financial statements.

4

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(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

See notes to consolidated financial statements.

5

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(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

See notes to consolidated financial statements.

6

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 SUBSIDIARIES

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 Earnings (Deficit)			Unamortized Restricted Stock Awards			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ 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 - Basis of Presentation

The consolidated financial statements of Goodrich Petroleum Corporation (“Goodrich” or “the Company”) included in this Form 10-Q have been prepared, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission 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.

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 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.

The results of operations for the nine-month period ended September 30, 2005 are not necessarily indicative of the results to be expected for the full year.

Abandonment Obligations

Effective January 1, 2003, the Company adopted SFAS No. 143,Accounting for Asset Retirement Obligations.SFAS No. 143 requires the Company to record a liability equal to the fair value of the estimated cost to retire an asset. The asset retirement liability must be recorded in the periods in which the obligation meets the definition of a liability, which is generally when the asset is placed in service. Prior to the adoption of 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 of January 1, 2003, in the amount of $1,408,000, and 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 of an asset retirement obligation and the recorded liability will be recognized as a gain or loss in the Company’s earnings. To recognize the 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 of the related income tax effect. For the nine months ended September 30, 2005 and 2004, the Company recorded the following activity in the abandonment liability:

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, the Company sold its operated interests in the Marholl and Sean Andrew fields, along with its non-operated interests in the Ackerly field, all of which 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 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 (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 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 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 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.

11

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 Note E).

NOTE E – Hedging Activities

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. Hedge ineffectiveness results from difference changes in the NYMEX contract terms and the physical location, grade and quality of the Company’s oil and gas production. 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:

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	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 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, 2005 resulted in a net liability of $47,461,000. As of September 30, 2005, $4,156,000 (net of $2,238,000 in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive income are expected to be reclassified into earnings during the next twelve months. In the nine 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 Company recognized in earnings a loss on derivatives not qualifying for hedge accounting in the amount of $42,736,000. This loss was recognized because the Company’s gas hedges were deemed to be ineffective for the first three quarters of 2005, accordingly, the changes in fair value of such hedges could no longer be reflected in other comprehensive income (also included in this loss amount are settlement payments on ineffective gas hedges). For the nine 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, 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 of previously deferred losses (net of $18,000 in income taxes) was reclassified from accumulated other comprehensive income to interest expense 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:

• $483,000 for 150,000 restricted share awards granted in February 2003;

• $54,000 for 11,500 restricted share awards granted in July and October 2003;

• $1,147,000 for 166,300 restricted share awards granted in February 2004;

• $209,100 for 19,500 restricted share awards granted in July through September 2004;

• $762,500 for 52,950 restricted share awards granted in December 2004;

• $1,086,500 for 54,500 restricted share awards granted in March 2005;

• $130,000 for 7,250 restricted share awards granted in April and May 2005; and

• $222,300 for 10,000 restricted share awards granted in August and September 2005

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”).

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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.

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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

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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 Company to attempt to control price risk, the Company remains subject to price fluctuations for natural gas and 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’s control. Domestic oil and gas prices could have a material adverse effect on the Company’s financial position, results of operations and quantities of reserves recoverable on an economic basis.

Disclosure Regarding Forward-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’s Annual Report on Form 10-K and other filings with the Securities and Exchange Commission. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to be correct.

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Controls and Procedures

The Company, under the direction 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’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) were effective as of September 30, 2005 to ensure that the information required to be disclosed by Goodrich Petroleum Corporation in 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 SEC rules and forms.

There were no changes in the Company’s internal controls or in other factors that have materially affected, or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

For a description of the Company’s legal proceedings, see Note G to the Consolidated Financial Statements included in Part I, Item 1 of this quarterly report on Form 10-Q, and Part I, Item 3 of the Company’s Form 10-K filed on March 25, 2005.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

12.1	Ratio of Earnings to Fixed Charges for the nine months ended September 30, 2005 and 2004.
12.2	Ratio of Earnings to Fixed Charges and Preference Securities Dividends for the nine months ended September 30, 2005 and 2004.
31.1	Certification by Chief Executive Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Chief Financial Officer Pursuant to 15 U.S.C. Section 7241, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification by Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification by Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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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 thereunto duly authorized.

	GOODRICH PETROLEUM CORPORATION
	(Registrant)
November 2, 2005	/s/ Walter G. Goodrich
Date	Walter G. Goodrich,
	Vice Chairman & Chief Executive Officer
November 2, 2005	/s/ D. Hughes Watler, Jr.
Date	D. Hughes Watler, Jr.,
	Senior Vice President & Chief Financial Officer

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