Edgar Filing: GOODRICH PETROLEUM CORP

Form 10-K Amendment No. 1

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K/A

(Amendment No. 1)

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

For the Fiscal Year Ended December 31, 2005

Commission file number: 001-7940

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

Identification No.)

808 Travis, Suite 1320

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(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

Securities Registered Pursuant to Section 12 (g) of the Act:


Series A Preferred Stock, $1.00 par value		NASDAQ Small Cap

Indicate by check mark if the Registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act). Yes ¨ No x

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨

Indicate by check mark whether the Registrant is a shell company (as defined in Exchange Act Rule 12b-2). Yes ¨ No x

The aggregate market value of the voting and non-voting common stock held by non-affiliates of the Registrant as of June 30, 2005 (the last business day of the Registrant’s most recently completed second fiscal quarter) was approximately $258,852,976. The number of shares of the Registrant’s common stock outstanding as of March 10, 2006 was 24,904,941.

DOCUMENTS INCORPORATED BY REFERENCE: Portions of Goodrich Petroleum Corporation’s definitive Proxy Statement are incorporated by reference in Part III of this Form 10-K.

Cautionary Statement Regarding Forward-Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements other than statements of historical facts included in this Annual Report on Form 10-K regarding reserve estimates, planned capital expenditures, future oil and gas production and prices, future drilling activity, our financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to be correct. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimates and such revisions could change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and natural gas that are ultimately recovered. Additional important factors that could cause actual results to differ materially from our expectations include changes in oil and gas prices, changes in regulatory or environmental policies, production difficulties, transportation difficulties and future drilling results. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by such factors.

EXPLANATORY NOTE

We are filing this Amendment No. 1 to our Annual Report on Form 10-K for the year ended December 31, 2005, as originally filed with the SEC on March 14, 2006, to correct a typographical error.

Under Part IV, Item 15. Exhibits and Financial Statement Schedules, page 68 of the previously filed Form 10-K, beginning of period proved developed reserves for natural gas in 2004 were incorrectly stated as 123,429 million cubic feet (“MMcf”), rather than 23,429 MMcf. This Amendment No. 1 corrects that error. Other than the correction of this typographical error, this Amendment No. 1 does not include any restatements or corrections of any previously reported financial statements or change any other disclosures.

In accordance with Rule 12b-15 of the Exchange Act, we are required to include in this Amendment No. 1 the entire Item 15. in which the typographical error occurred. Refer to page 33 of this Amendment No. 1 in the discussion regarding “Oil and Natural Gas Reserves” for the corrected amount.

This Amendment No. 1 continues to speak as of the date of the original Form 10-K for the year ended December 31, 2005 and we have not updated or amended the disclosures contained herein to reflect events that have occurred since the filing of the original Form 10-K, or modified or updated those disclosures in any way other than as described in the preceding paragraphs. Accordingly, this Amendment No. 1 should be read in conjunction with our filings made with the SEC subsequent to the filing of the original Form 10-K on March 14, 2006.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a) (1) and (2) Financial Statements and Financial Statement Schedules

See “Index to Consolidated Financial Statements” on page 7.

(a) (3) Exhibits


1.1		Purchase Agreement by among Goodrich Petroleum Corporation, Bear, Sterns & Co. Inc. and BNP Paribas Securities Corp. dated December 16, 2005 (Incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed on December 16, 2005).

3.1		Amended and Restated Certificate of Incorporation of Goodrich Petroleum Corporation dated March 12, 1998 (Incorporated by reference to Exhibit 3.1 of the Company’s First Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed November 22, 2000).

3.2		Bylaws of the Company, as amended and restated (Incorporated by reference to Exhibit 3.3 of the Company’s First Amended Registration Statement on Form S-1 (Registration No. 333-47078) filed November 22, 2000).

3.3		Certificate of Designation of 5.375% Series B Cumulative Convertible Preferred Stock (Incorporated by reference to Exhibit 1.1 of the Company’s Form 8-K filed on December 22, 2005).

4.1		Specimen Common Stock Certificate (Incorporated by reference to Exhibit 4.6 of the Company’s Registration Statement filed February 20, 1996 on Form S-8 (File No. 33-01077)).

4.2		Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated November 9, 2001 (Incorporated by reference to Exhibit 4.2 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001).

4.3		Registration Rights Agreement dated December 21, 2005 among the Company, Bear, Sterns & Co. Inc. and BNP Paribas Securities Corp. (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on December 22, 2005).

10.1		Goodrich Petroleum Corporation 1995 Stock Option Plan (Incorporated by reference to Exhibit 10.21 to the Company’s Registration Statement filed June 13, 1995 on Form S-4 (File No. 33-58631)).

10.2		Consulting Services Agreement between Patrick E. Malloy and Goodrich Petroleum Corporation dated June 1, 2001 (Incorporated by reference to Exhibit 10.3 of the Company’s Annual Report filed on Form 10-K for the year ended December 31, 2001).

10.3		Goodrich Petroleum Corporation 1997 Nonemployee Director Compensation Plan (Incorporated by reference to the Company’s Proxy Statement filed April 27, 1998).

10.4		Form of Subscription Agreement dated September 27, 1999 (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated October 15, 1999).

10.5		Purchase and Sale Agreement between Goodrich Petroleum Company, LLC and Malloy Energy Company, LLC, dated March 4, 2002 (Incorporated by reference to Exhibit 10.7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002).

10.6		Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated February 25, 2005 (Incorporated by reference to Exhibit 10.1 of the Company’s Form 8-K filed on April 21, 2005).

10.7		Severance Agreement between the Company and Walter G. Goodrich, dated April 25, 2003 (Incorporated by reference to Exhibit 10.2 of the Company’s Form 8-K filed on April 21, 2005)


10.8		Severance Agreement between the Company and Robert C. Turnham, Jr., dated April 25, 2003 (Incorporated by reference to Exhibit 10.3 of the Company’s Form 8-K filed on April 21, 2005)

10.9		First Amendment to the Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated April 29, 2005 (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report Form 10-Q for the quarterly period ended March 31, 2005).

10.10		Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated November 17, 2005 (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on November 23, 2005).

10.11		Second Lien Term Loan Agreement among Goodrich Petroleum Company L.L.C., BNP Paribas and Certain Lenders, dated as of November 17, 2005 (Incorporated by reference to Exhibit 4.3 of the Company’s Form 8-K filed on November 23, 2005).

10.12		First Amendment to Amended and Restated Credit Agreement between Goodrich Petroleum Company, L.L.C. and BNP Paribas dated as of December 14, 2005 (Incorporated by reference to Exhibit 4.1 of the Company’s Form 8-K filed on December 20, 2005).

10.13		First Amendment to Second Lien Term Loan Agreement among Goodrich Petroleum Company, L.L.C., BNP Paribas and Certain Lenders, dated as of December 14, 2005 (Incorporated by reference to Exhibit 4.2 of the Company’s Form 8-K filed on December 20, 2005).

**12.1		Ratio of Earnings to Fixed Charges

**12.2		Ratio of Earnings to Fixed Charges and Preference Securities Dividends

21		Subsidiaries of the Registrant

		Goodrich Petroleum Company LLC— organized in state of Louisiana

		Goodrich Petroleum Company—Lafitte, LLC—organized in state of Louisiana

		Drilling & Workover Company, Inc.—incorporated in state of Louisiana

		LECE, Inc.—incorporated in the state of Texas

*23.1		Consent of KPMG LLP

**23.2		Consent of Netherland, Sewell & Associates, Inc.

*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.

*	Filed herewith.

**	Previously filed as an exhibit to our originally filed 2005 Form 10-K.

***	Furnished herewith.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report on Form 10-K/A to be signed on its behalf by the undersigned, thereunto duly authorized on this 10^th day of April, 2006.


Goodrich Petroleum Corporation

By:		/s/ Walter G. Goodrich
		Walter G. Goodrich
		Chief Executive Officer

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
Management’s Annual Report on Internal Controls over Financial Reporting		8

Report of Independent Registered Public Accounting Firm - Consolidated Financial Statements		9

Report of Independent Registered Public Accounting Firm - Internal Controls over Financial Reporting		10

Consolidated Balance Sheets as of December 31, 2005 and 2004		12

Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003		13

Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003		14

Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2005, 2004 and 2003		15

Consolidated Statements of Comprehensive Income (Loss) for the years ended December 31, 2005, 2004 and 2003		16

Notes to Consolidated Financial Statements		17

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROLS

OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining effective internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934. Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Our internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and board of directors of the Company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

We assessed the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation under the framework in Internal Control – Integrated Framework, we have concluded that our internal control over financial reporting was effective as of December 31, 2005. Our assessment of the effectiveness of our internal control over financial reporting as of December 31, 2005 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which is included on pages 10 and 11.

Management of Goodrich Petroleum Corporation

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Goodrich Petroleum Corporation:

We have audited the accompanying consolidated balance sheets of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, cash flows and stockholders’ equity and other comprehensive income for each of the years in the three-year period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Goodrich Petroleum Corporation and Subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.

As discussed in Note B to the consolidated financial statements, effective January 1, 2003, the Company changed its method of accounting for asset retirement obligations.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Goodrich Petroleum Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 14, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

Shreveport, Louisiana

March 14, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Goodrich Petroleum Corporation:

We have audited management’s assessment, included in the accompanying report, “Management’s Annual Report on Internal Controls over Financial Reporting”, that Goodrich Petroleum Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Goodrich Petroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Goodrich Petroleum Corporation and subsidiaries maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Goodrich Petroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Goodrich Petroleum Corporation and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, changes in stockholders’ equity and comprehensive income or loss, and cash flows for each of the years in the three-year period ended December 31, 2005, and our report dated March 14, 2006 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

Shreveport, Louisiana

March 14, 2006

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In Thousands, Except Share Amounts)


	December 31,
	2005			2004
Assets
Current assets:
Cash and cash equivalents	$	19,842		$	3,449
Accounts receivable, trade and other, net of allowance		6,397			7,183
Accrued oil and gas revenue		11,863			3,122
Fair value of interest rate derivatives		107			—
Prepaid expenses and other		463			632

Total current assets		38,672			14,386

Property and equipment:
Oil and gas properties (successful efforts method)		316,286			159,904
Furniture, fixtures and equipment		1,075			821

		317,361			160,725
Less: Accumulated depletion, depreciation and amortization		(74,229	)		(51,320	)

Net property and equipment		243,132			109,405

Other assets:
Restricted cash and investments		2,039			2,039
Deferred tax asset		11,580			2,070
Other		1,103			77

Total other assets		14,722			4,186

Total assets	$	296,526		$	127,977

Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	31,574		$	23,352
Accrued liabilities		15,973			3,214
Fair value of oil and gas derivatives		23,271			1,834
Fair value of interest rate derivatives		—			144
Accrued abandonment costs		92			92

Total current liabilities		70,910			28,636
Long-term debt		30,000			27,000
Accrued abandonment costs		7,868			6,719
Production payment payable		—			297
Fair value of oil and gas derivatives		6,159			—
Fair value of interest rate derivatives		—			18

Total liabilities		114,937			62,670

Stockholders’ equity:
Preferred stock: 10,000,000 shares authorized:
Series A convertible preferred stock, $1.00 par value, 791,968 shares issued and outstanding		792			792
Series B convertible preferred stock, $1.00 par value, 1,650,000 shares issued and outstanding		1,650			—
Common stock: $0.20 par value, 50,000,000 shares authorized; issued and outstanding 24,804,737 and 20,587,074 shares, respectively		4,961			4,117
Additional paid in capital		187,967			55,409
Retained earnings (deficit)		(8,649	)		9,556
Unamortized restricted stock awards		(2,066	)		(1,762	)
Accumulated other comprehensive loss		(3,066	)		(2,805	)

Total stockholders’ equity		181,589			65,307

Total liabilities and stockholders’ equity	$	296,526		$	127,977

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(In Thousands, Except Per Share Amounts)


	Year Ended December 31,
	2005			2004			2003
Revenues:
Oil and gas revenues	$	68,008		$	44,861		$	31,663
Other		325			151			477

		68,333			45,012			32,140

Operating expenses:
Lease operating expense		9,931			7,402			6,099
Production taxes		4,053			3,105			2,288
Depreciation, depletion and amortization		25,563			11,562			8,996
Exploration		6,867			4,426			2,249
Impairment of oil and gas properties		340			—			335
General and administrative		8,702			5,821			5,314
(Gain) loss on sale of assets		(235	)		(50	)		66

		55,221			32,266			25,347

Operating income		13,112			12,746			6,793

Other income (expense):
Interest expense		(2,279	)		(1,110	)		(1,051	)
Gain (loss) on derivatives not qualifying for hedge accounting		(37,680	)		2,317			—
Gain on litigation judgment		—			2,118			—

		(39,959	)		3,325			(1,051	)

Income (loss) from continuing operations before income taxes		(26,847	)		16,071			5,742
Income tax (expense) benefit		9,397			1,707			(2,016	)

Income (loss) from continuing operations		(17,450	)		17,778			3,726
Discontinued operations including gain on sale of assets, net of tax		—			749			196

Income (loss) before cumulative effect of accounting change		(17,450	)		18,527			3,922
Cumulative effect of accounting change, net of tax		—			—			(205	)

Net income (loss)		(17,450	)		18,527			3,717
Preferred stock dividends		755			633			633

Net income (loss) applicable to common stock	$	(18,205	)	$	17,894		$	3,084

Net income (loss) per common share - basic
Income (loss) from continuing operations	$	(0.75	)	$	0.91		$	0.21
Discontinued operations		—			0.04			0.01

Before cumulative effect of accounting change		(0.75	)		0.95			0.22
Cumulative effect of accounting change		—			—			(0.01	)

Net income (loss)	$	(0.75	)	$	0.95		$	0.21

Net income (loss) applicable to common stock	$	(0.78	)	$	0.92		$	0.17

Net income (loss) per common share - diluted
Income (loss) from continuing operations	$	(0.75	)	$	0.87		$	0.18
Discontinued operations		—			0.04			0.01

Before cumulative effect of accounting change		(0.75	)		0.91			0.19
Cumulative effect of accounting change		—			—			(0.01	)

Net income (loss)	$	(0.75	)	$	0.91		$	0.18

Net income (loss) applicable to common stock	$	(0.78	)	$	0.88		$	0.15

Weighted average common shares outstanding - basic		23,333			19,552			18,064
Weighted average common shares outstanding - diluted		23,333			20,347			20,482

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)


	Year Ended December 31,
	2005			2004			2003
Cash flows from operating activities:
Net income (loss)	$	(17,450	)	$	18,527		$	3,717
Adjustments to reconcile net income (loss) to net cash provided by operating activities –
Depletion, depreciation, and amortization		25,563			11,562			8,996
Unrealized (gain) loss on derivatives not qualifying for hedge accounting		26,960			(2,317	)		—
Deferred income taxes		(9,396	)		(1,303	)		1,905
Dry hole costs		2,014			—			816
Amortization of leasehold costs		3,344			1,035			474
Impairment of oil and gas properties		340			—			335
Stock based compensation (non-cash)		1,144			580			155
Stock issued for cancelled options (non-cash)		—			—			403
Cumulative effect of change in accounting principle		—			—			316
(Gain) loss on sale of assets		(235	)		(814	)		66
Non-cash effect of discontinued operations, net		—			155			185
Other non-cash items		(36	)		(516	)		339
Changes in assets and liabilities –
Accounts receivable and other assets		(7,546	)		(4,256	)		(218	)
Accounts payable and accrued liabilities		20,860			18,375			(301	)

Net cash provided by operating activities		45,562			41,028			17,188

Cash flows from investing activities:
Capital expenditures		(164,551	)		(47,501	)		(19,898	)
Proceeds from sale of assets		980			2,087			398

Net cash used in investing activities		(163,571	)		(45,414	)		(19,500	)

Cash flows from financing activities:
Principal payments of bank borrowings		(118,500	)		(1,000	)		(1,600	)
Proceeds from bank borrowings		121,500			8,000			3,100
Net proceeds from common stock offering		53,112			—			—
Net proceeds from preferred stock offering		79,775			—			—
Exercise of stock options and warrants		477			340			129
Production payments		(297	)		(361	)		(406	)
Deferred financing costs		(971	)		—			(140	)
Preferred stock dividends		(634	)		(633	)		(633	)
Other		(60	)		—			—

Net cash provided by financing activities		134,402			6,346			450

Increase (decrease) in cash and cash equivalents		16,393			1,960			(1,862	)
Cash and cash equivalents, beginning of period		3,449			1,489			3,351

Cash and cash equivalents, end of period	$	19,842		$	3,449		$	1,489

Supplemental disclosures of cash flow information:
Cash paid during the year for interest	$	1,862		$	865		$	902

Cash paid during the year for income taxes	$	110		$	30		$	—

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Thousands)


	2005				2004				2003
	Shares	Amount			Shares	Amount			Shares	Amount
Series A Preferred Stock
Balance, beginning and end of year	792	$	792		792	$	792		792	$	792

Series B Preferred Stock
Balance, beginning of year	—	$	—		—	$	—		—	$	—
Offering of preferred stock	1,650		1,650		—		—		—		—

Balance, end of year	1,650	$	1,650		—	$	—		—	$	—

Common Stock
Balance, beginning of year	20,587	$	4,117		18,130	$	3,626		17,914	$	3,583
Offering of common stock	3,710		742		—		—		—		—
Issuance of common stock for cancelled stock options	—		—		—		—		125		25
Issuance and amortization of restricted stock	123		25		52		10		—		—
Exercise of stock options and warrants	371		74		2,376		475		91		18
Director stock grants	14		3		29		6		—		—

Balance, end of year	24,805	$	4,961		20,587	$	4,117		18,130	$	3,626

Paid-in Capital
Balance, beginning of year		$	55,409			$	53,359			$	52,333
Offering of common stock			52,370				—				—
Offering of preferred stock			78,125				—				—
Issuance of common stock for cancelled stock options			—				—				378
Issuance and amortization of restricted stock			1,423				1,951				537
Exercise of stock options and warrants			403				(135	)			111
Director stock grants			237				234				—

Balance, end of year		$	187,967			$	55,409			$	53,359

Retained Earnings (Deficit)
Balance, beginning of year		$	9,556			$	(8,338	)		$	(11,422	)
Net income (loss)			(17,450	)			18,527				3,717
Preferred stock dividends			(755	)			(633	)			(633	)

Balance, end of year		$	(8,649	)		$	9,556			$	(8,338	)

Unamortized Restricted Stock Awards
Balance, beginning of year		$	(1,762	)		$	(382	)		$	—
Issuance and amortization of restricted stock			(304	)			(1,380	)			(382	)

Balance, end of year		$	(2,066	)		$	(1,762	)		$	(382	)

Accumulated Other Comprehensive Loss
Balance, beginning of year		$	(2,805	)		$	(998	)		$	(679	)
Other comprehensive loss			(261	)			(1,807	)			(319	)

Balance, end of year		$	(3,066	)		$	(2,805	)		$	(998	)

Total Stockholders’ Equity		$	181,589			$	65,307			$	48,059

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(In Thousands)


	Year Ended December 31,
	2005			2004			2003
Net income (loss)	$	(17,450	)	$	18,527		$	3,717

Other comprehensive loss:
Change in fair value of derivatives (1)		(6,233	)		(5,909	)		(2,237	)
Reclassification adjustment (2)		5,972			4,102			1,918

Other comprehensive loss		(261	)		(1,807	)		(319	)

Comprehensive income (loss)	$	(17,711	)	$	16,720		$	3,398


(1) Net of income tax benefit of:	$	3,356	$	3,180	$	1,204
(2) Net of income tax expense of:	$	3,216	$	2,209	$	1,033

See notes to consolidated financial statements

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE A—Description of Business

We are in the primary business of exploration and production of crude oil and natural gas. Our subsidiaries have interests in such operations in three states, primarily in Louisiana and Texas.

NOTE B—Summary of Significant Accounting Policies

Principles of Consolidation—The consolidated financial statements include the financial statements of Goodrich Petroleum Corporation and its wholly-owned subsidiaries. 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.

Since the issuance of our Form 10-K for the year ended December 31, 2004, we have changed the presentation of our 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 on litigation judgment.

Use of Estimates—Our Management has made a number of estimates and assumptions relating to the reporting of assets, liabilities, revenues and expenses and the disclosure of contingent assets and liabilities to prepare these consolidated financial statements in conformity with accounting principles generally accepted in the United States of America. Actual results could differ from those estimates.

Cash and Cash Equivalents—Cash and cash equivalents include cash on hand, demand deposit accounts and temporary cash investments with maturities of ninety days or less at date of purchase. Restricted cash represents amounts held in escrow for plugging and abandonment obligations which were incurred with the acquisition of our Burrwood and West Delta 83 fields in 2000.

Revenue Recognition—Revenues from the production of crude oil and natural gas properties in which we have an interest with other producers are recognized on the entitlements method. We record an asset or liability for natural gas balancing when we have purchased or sold more than our working interest share of natural gas production, respectively. At December 31, 2005 and 2004, the net assets for gas balancing were $0.7 million and $0.1 million, respectively. Differences between actual production and net working interest volumes are routinely adjusted. These differences are not significant.

Property and Equipment—We use the successful efforts method of accounting for exploration and development expenditures. Leasehold acquisition costs are capitalized. When proved reserves are found on an undeveloped property, leasehold cost is reclassified to proved properties. Significant undeveloped leases are reviewed periodically, and a valuation allowance is provided for any estimated decline in value. Cost of all other undeveloped leases is amortized over the estimated average holding period of the leases.

Costs of exploratory drilling are initially capitalized, but if proved reserves are not found, generally within one year after completion of drilling, the costs are subsequently expensed. All other exploratory costs are charged to expense as incurred. Development costs are capitalized, including the cost of unsuccessful development wells.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We recognize an impairment when the net of future cash inflows expected to be generated by an identifiable long-lived asset and cash outflows expected to be required to obtain those cash inflows is less than the carrying value of the asset. We perform this comparison for our oil and gas properties on a field-by-field basis using our estimates of future commodity prices and proved and probable reserves. The amount of such loss is measured based on the difference between the discounted value of such net future cash flows and the carrying value of the asset. For the years ended December 31, 2005 and 2003, we recorded impairments of $0.3 million as a result of certain non-core fields depleting earlier than anticipated. There were no impairments in 2004.

Depreciation and depletion of producing oil and gas properties are provided under the unit-of-production method. Proved developed reserves are used to compute unit rates for unamortized tangible and intangible development costs, and proved reserves are used for unamortized leasehold costs. As described in Note C, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations (“SFAS 143”) on January 1, 2003. Under SFAS 143, estimated asset retirement costs are generally recognized when the asset is placed in service, and are amortized over proved reserves using the units of production method. Prior to the adoption of SFAS 143, estimated dismantlement, abandonment and site restoration costs, net of salvage value, were generally recognized using the units of production method and were included in depreciation expense. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates.

Gains and losses on disposals or retirements that are significant or include an entire depreciable or depletable property unit are included in income. All other dispositions, retirements, or abandonments are reflected in accumulated depreciation, depletion, and amortization.

Furniture, fixtures and equipment consists of office furniture, computer hardware and software and leasehold improvements. Depreciation of these assets is computed using the straight-line method over their estimated useful lives, which vary from one to five years.

Income Taxes—We follow the provisions of SFAS No. 109, “Accounting for Income Taxes”, (“SFAS 109”) which requires income taxes be accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Earnings Per Share—Basic income per common share is computed by dividing net income available for common stockholders, for each reporting period by the weighted average number of common shares outstanding during the period. Diluted income per common share is computed by dividing net income available for common stockholders for each reporting period by the weighted average number of common shares outstanding during the period, plus the effects of potentially dilutive common shares.

Derivative Instruments and Hedging Activities—We utilize derivative instruments such as futures, forwards, options, collars and swaps for purposes of hedging our exposure to fluctuations in the price of crude oil and natural gas and to hedge our exposure to changing interest rates. SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (“SFAS 133”), as amended, requires that all derivative instruments subject to the requirements of the statement be measured at fair value and recognized as assets or liabilities in the balance sheet. Upon entering into a derivative contract, we may designate the derivative as either a fair value hedge or a cash flow hedge, or decide that the contract is not a hedge, and thenceforth, mark

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

the contract to market through earnings. We document the relationship between the derivative instrument designated as a hedge and the hedged items, as well as our objective for risk management and strategy for use of the hedging instrument to manage the risk. Derivative instruments designated as fair value or cash flow hedges are linked to specific assets and liabilities or to specific firm commitments or forecasted transactions. We assess at inception, and on an ongoing basis, whether a derivative instrument used as a hedge is highly effective in offsetting changes in the fair value or cash flows of the hedged item. A derivative that is not a highly effective hedge does not qualify for hedge accounting. Changes in the fair value of a qualifying fair value hedge are recorded in earnings along with the gain or loss on the hedged item. Changes in the fair value of a qualifying cash flow hedge are recorded in other comprehensive income, until earnings are affected by the cash flows of the hedged item. When the cash flow of the hedged item is recognized in the Statement of Operations, the fair value of the associated cash flow hedge is reclassified from other comprehensive income into earnings.

Ineffective portions of a cash flow hedging derivative’s change in fair value are recognized currently in earnings as other income (expense). If a derivative instrument no longer qualifies as a cash flow hedge, hedge accounting is discontinued and the gain or loss that was recorded in other comprehensive income is recognized over the period anticipated in the original hedge transaction.

Asset Retirement Obligations—Effective January 1, 2003, we adopted SFAS 143 (see Note C). SFAS 143 applies to obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. SFAS 143 requires that we record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset.

Commitments and Contingencies—Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. Recoveries from third parties, which are probable of realization, are separately recorded, and are not offset against the related environmental liability.

Concentration of Credit Risk—Due to the nature of the industry, we sell our oil and natural gas production to a limited number of purchasers and, accordingly, amounts receivable from such purchasers could be significant. For the year ended December 31, 2005, revenues from three purchasers accounted for 34%, 18% and 13% of oil and gas revenues. For the year ended December 31, 2004, revenues from two purchasers accounted for 45% and 15%, of oil and gas revenues. For the year ended December 31, 2003, revenues from two purchasers accounted for 47% and 25% of oil and gas revenues.

Stock Based Compensation—While SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS 123”), permits entities to recognize as expense, over the vesting period, the fair value of all stock-based awards on the date of grant, it also allows entities to continue to apply the provisions of APB Opinion No. 25, “Accounting for Stock Issued to Employees” (“APB 25”), and provide pro forma net income and pro forma earnings per share and other disclosures for employee stock option grants made in 1995 and future years as if the fair-value-based method defined in SFAS 123 had been applied. We have elected to continue to apply the provisions of APB 25 and provide the disclosure provisions of SFAS 123. For stock based compensation that vests on a prorata basis where the award is fixed at the grant date, we have elected to amortize those costs using straight line method over the life of the award.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We apply APB 25 in accounting for our plans and, accordingly, no compensation cost has been recognized for our stock options in the financial statements. Had we determined compensation cost based on the fair value at the grant date for our stock options under SFAS 123, our net income (loss) would have been reduced to the pro forma amounts indicated below (in thousands, except per share data):


	Year Ended December 31,
	2005			2004			2003
Net income (loss) as reported	$	(17,450	)	$	18,527		$	3,717
Add: Restricted stock compensation expense included in net income, net of tax		743			579			155
Deduct: Stock based compensation expense at fair value, net of tax		(1,236	)		(609	)		(196	)

Pro forma	$	(17,943	)	$	18,497		$	3,676

Net income (loss) applicable to common stock as reported	$	(18,205	)	$	17,894		$	3,084
Add: Restricted stock compensation expense included in net income, net of tax		743			579			155
Deduct: Stock based compensation expense at fair value, net of tax		(1,236	)		(609	)		(196	)

Pro forma	$	(18,698	)	$	17,864		$	3,043

Net income (loss) applicable to common stock per share:
Basic – as reported	$	(0.78	)	$	0.92		$	0.17
Basic – pro forma	$	(0.80	)	$	0.91		$	0.17
Diluted – as reported	$	(0.78	)	$	0.88		$	0.15
Diluted – pro forma	$	(0.80	)	$	0.88		$	0.15

See “New Accounting Pronouncements” below regarding the impact of the adoption of SFAS No. 123R (Revised 2004) “Share-Based Payment” (“SFAS 123R”).

New Accounting Pronouncements—In December 2004, the FASB issued SFAS 123R which is effective for interim or annual reporting periods that begin after December 15, 2005, and requires the expensing of new, modified or repurchased stock-based compensation awards issued after that date. Previously issued stock-based compensation awards, which are unvested as of December 15, 2005, 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. We plan to follow the “modified prospective application” to the adoption of the revised statement. The specific magnitude of the impact of adoption of SFAS 123R cannot be predicted at this time because it will depend on levels of share-based incentive awards granted in the future. However, had we adopted SFAS 123R in prior periods, the impact of that standard would have approximated the impact of SFAS 123 as described in the disclosure of pro forma net income and earnings per share in “Stock Based Compensation” above.

In March 2005, the FASB issued FASB Interpretation (“FIN”) 47, an interpretation of SFAS 143. FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS. 143, which we adopted on January 1, 2003. We applied the guidance in this FIN beginning in the third quarter of 2005 resulting in no impact on our financial statements.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED 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 (“SFAS 19”). The guidance in FSP 19-1 applies to companies that use the successful efforts method of accounting as described in SFAS 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 we are making sufficient progress assessing the reserves and the economic and operating viability of the project. We adopted the guidance in this FSP prospectively in April 2005 and the adoption had no impact on our financial statements. We had no capitalized exploratory costs pending determination of reserves as of December 31, 2005.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections,” (“SFAS 154”) which replaces APB Opinion No. 20, “Accounting Changes,” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements — An Amendment of APB Opinion No. 28.” SFAS 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes retrospective application, or the latest practicable date, as the required method for reporting a change in accounting principle and the reporting of a correction of an error. SFAS 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005, and is therefore required to be adopted by us in the first quarter of fiscal 2006. We are currently evaluating the effect that the adoption of SFAS 154 will have on our consolidated results of operations and financial condition, but do not expect it will have a material impact.

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 results of operations and financial position.

NOTE C—Asset Retirement Obligations

SFAS 143 provides accounting requirements for retirement obligations associated with tangible long-lived assets and requires that an asset retirement cost should be capitalized as part of the cost of the related long- lived asset and subsequently allocated to expense using a systematic and rational method. We adopted SFAS 143 on January 1, 2003 and recorded an incremental liability for asset retirement obligations of $1.4 million, additional oil and gas properties, net of accumulated depletion, depreciation and amortization, in the amount of $1.1 million and a net of tax cumulative effect of change in accounting principle of $0.2 million.

The reconciliation of the beginning and ending asset retirement obligation for the periods ending December 31, 2005 and 2004 is as follows (in thousands):


	December 31,
	2005			2004
Beginning balance	$	6,811		$	6,601
Liabilities incurred		1,004			389
Liabilities settled		(39	)		(506	)
Accretion expense (reflected in depletion, depreciation and amortization expense)		363			327
Other		(179	)		—

Ending balance		7,960			6,811
Less: current portion		(92	)		(92	)

	$	7,868		$	6,719

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE D—Long-Term Debt

Long-term debt consisted of the following balances (in thousands):


	December 31,
	2005		2004
Borrowings under senior credit facility, bearing interest at a weighted average interest rate 4.1% at December 31, 2004	$	—	$	27,000
Second lien term loan, bearing interest at a weighted average interest rate of 8.9% at December 31, 2005		30,000		—

Total debt		30,000		27,000
Less current maturities		—		—

Total long-term debt	$	30,000	$	27,000

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 March 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 in the amount of $47.5 million leaving a zero balance outstanding as of December 31, 2005 (see Note H). 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:

•

Current Ratio of 1.0/1.0;

•

Interest Coverage Ratio which is not less than 3.0/1.0 for the trailing four quarters, and

•

Tangible Net Worth of not less than $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 December 31, 2005, we were in compliance with all of the financial 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. At December 31, 2005, borrowings outstanding under the term loan were $30.0 million.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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:

•

Total Debt to EBITDAX Ratio which is not greater than 4.0/1.0 for the most recent period of four fiscal quarters for which financial statements are available and

•

Asset Coverage Ratio to be not less than 1.5/1.0.

As of December 31, 2005, we were in compliance with all of the financial covenants of the Second Lien Term Loan Agreement.

NOTE E—Net Income (Loss) Per Share

Net income (loss) was used as the numerator in computing basic and diluted income (loss) per common share for the years ended December 31, 2005, 2004 and 2003. The following table reconciles the weighted average shares outstanding used for these computations (in thousands):


	Year Ended December 31,
	2005	2004	2003
Basic method	23,333	19,552	18,064
Stock warrants	—	478	2,364
Stock options and restricted stock	—	317	54

Dilutive method	23,333	20,347	20,482

NOTE F—Income Taxes

Income tax (expense) benefit consisted of the following (in thousands):


	Year Ended December 31,
	2005		2004		2003
Current:
Federal	$	—	$	—	$	—
State		—		—		—

		—		—		—

Deferred:
Federal		9,397		1,303		(2,121	)
State		—		—		—

		9,397		1,303		(2,121	)

Total	$	9,397	$	1,303	$	(2,121	)

The following is a reconciliation of the U.S. statutory income tax rate at 35% to our income (loss) before income taxes (in thousands):


	Year Ended December 31,
	2005			2004			2003
Income (loss) from continuing operations
Tax at U.S. statutory income tax	$	9,397		$	(5,625	)	$	(2,010	)
Nondeductible expenses		(5	)		(6	)		(6	)
Valuation allowance and other		5			7,338			—

		9,397			1,707			(2,016	)

Income (loss) from discontinued operations
Tax at U.S. statutory income tax		—			(404	)		(105	)

		—			(404	)		(105	)

Total tax (expense) benefit	$	9,397		$	1,303		$	(2,121	)

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2005 and 2004 are presented below (in thousands).


	2005			2004
Deferred tax assets:
Differences between book and tax basis of:
Operating loss carryforwards	$	16,064		$	14,189
Statutory depletion carryforward		7,034			7,034
AMT tax credit carryforward		1,480			1,400
Derivative financial instruments		10,263			699
Contingent liabilities		45			45
Other		421			348

Total gross deferred tax assets		35,307			23,715
Less valuation allowance		(13,263	)		(12,648	)

Net deferred tax asset		22,044			11,067

Deferred tax liabilities:
Differences between book and tax basis of:
Property and equipment		(10,464	)		(8,997	)

Total gross deferred tax liabilities		(10,464	)		(8,997	)

Net deferred tax asset	$	11,580		$	2,070

The valuation allowance for deferred tax assets increased by $0.6 million in 2005. The increase in the allowance was primarily due to the income tax benefits generated from our stock based deferred compensation plans. We recognize the benefits from current and prior years’ stock compensation deductions after the utilization of net operating loss carryforwards generated from operations. These excess tax benefits will be recorded as additional paid in capital when realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based primarily upon the level of projections for future taxable income and the reversal of future taxable temporary differences over the periods which the deferred tax assets are deductible, management believes it is more likely than not we will realize the benefits of these deductible differences, net of the existing valuation allowance at December 31, 2005.

We have net operating loss carryforwards totaling $45.9 million which expire in years 2007 through 2025 as follows (in thousands):


2006	$	—
2007		7,894
2008		4,286
2009		3,247
2010		6,451
2011 through 2025		24,018

Total	$	45,896

An ownership change in accordance with Internal Revenue Code (IRC) (S)382, occurred in August 1995 and again in August 2000. The net operating losses (NOLs) generated prior to August 1995 are subject to an annual IRC (S)382 limitation of $1.7 million. The IRC (S)382 annual limitation for the ownership change in August 2000 is $3.6 million. The latter IRC (S)382 ownership change limitation is a cumulative limitation and does not eliminate or increase the limitation on the pre-August 1995 NOLs. The NOLs generated after August

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1995 and prior to August 2000, are subject to an annual limitation of $3.6 million less the annual amount utilized for pre-August 1995 NOLs. It should be noted that the same IRC (S)382 limitations apply to the alternative minimum tax net operating loss carryforwards, depletion carryforwards, and alternative minimum tax credit carryforwards. The minimum tax credit carryforward (“MTC”) of $1.5 million as of December 31, 2005, will not begin to be utilized until after the available NOLs have been utilized or expired and when regular tax exceeds the current year alternative minimum tax. The unused annual IRC (S)382 limitations can be carried over to subsequent years.

NOTE G—Production Payment Obligation

We entered into a production payment to assist in the financing of the Lafitte field acquisition in September 1999. The original amount of the production payment obligation was $2.9 million, which was recorded as a production payment liability of $2.2 million after a discount to reflect an effective rate of interest of 11.25%. During 2005, the production payment obligation was fully satisfied.

NOTE H—Stockholders’ Equity

Common Stock

At December 31, 2005, a total of 1,381,252 unissued shares of Goodrich common stock were reserved for the following: (a) 531,502 shares for the exercise of stock warrants; (b) 519,500 shares for the exercise of stock options; and (c) 330,250 shares for the conversion of Series A convertible preferred stock. The stock warrants were issued in connection with a September 1999 private placement of convertible notes and subsidiary securities at exercise prices ranging from $0.9375 to $1.50 per share and expire in September 2006. Each warrant is exercisable into one share of common stock upon payment of the exercise price, however, the holders of the stock warrants may, in certain circumstances, elect a cashless exercise whereby additional “in the money” warrants can be tendered to cover the exercise price of the warrants. Pursuant to a May 2003 stock purchase agreement, the holders of 2,369,527 warrants to purchase common stock elected a cashless exercise of such warrants resulting in the issuance of 2,109,169 shares of common stock in three separate installments which closed in January, April, and July 2004. There are no further exercises of warrants to be made pursuant to the stock purchase agreement; however, in February 2005, the holder of 330,000 warrants to purchase common stock elected to exercise such warrants by paying the exercise price in cash.

In May 2005, we completed a public offering of 3,710,000 shares of our common stock at an offering price of $15.40 per share resulting in net proceeds of $53.1 million, after underwriting discount and offering costs. We used the proceeds to repay all outstanding indebtedness to BNP under our previous senior credit facility in the amount of $39.5 million 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.

Preferred Stock

Our Series A Convertible Preferred Stock (the “Series A Convertible Preferred Stock”) has a par value of $1.00 per share with a liquidation preference of $10.00 per share, aggregating to $7.9 million, and is convertible at the option of the holder at any time, unless earlier redeemed, into shares of our common stock at an initial conversion rate of .4167 shares of common stock per share of Series A Convertible Preferred Stock. The Series A Convertible Preferred Stock also will automatically convert to common stock if the closing price for the Series A Convertible Preferred Stock exceeds $15.00 per share for ten consecutive trading days. The Series A Convertible Preferred Stock is redeemable in whole or in part, at $12.00 per share, plus accrued and unpaid dividends. Dividends on the Series A Convertible Preferred Stock accrue at an annual rate of 8% and are cumulative. In February 2006, we fully redeemed all issued and outstanding shares of our Series A Convertible Preferred Stock at a cost of approximately $9.5 million.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Our Series B Convertible Preferred Stock (the “Series B Convertible Preferred Stock”) was initially issued on December 21, 2005 in a private placement of 1,650,000 shares for net proceeds of $79.8 million (after offering costs of $2.7 million). Each share of the Series B Convertible Preferred Stock has a liquidation preference of $50 per share, aggregating to $82.5 million, and bears a dividend of 5.375% per annum. Dividends are payable quarterly in arrears beginning March 15, 2006. If we fail to pay dividends on our Series B Convertible Preferred Stock on any six dividend payment dates, whether or not consecutive, the dividend rate per annum will be increased by 1.0% until we have paid all dividends on our Series B Convertible Preferred Stock for all dividend periods up to and including the dividend payment date on which the accumulated and unpaid dividends are paid in full.

Each share is convertible at the option of the holder into our common stock, par value $0.20 per share (the ”Common Stock”) at any time at an initial conversion rate of 1.5946 shares of Common Stock per share, which is equivalent to an initial conversion price of approximately $31.36 per share of Common Stock. Upon conversion of the Series B Convertible Preferred Stock, we may choose to deliver the conversion value to holders in cash, shares of Common Stock, or a combination of cash and shares of Common Stock.

On or after December 21, 2010, we may, at our option, cause the Series B Convertible Preferred Stock to be automatically converted into that number of shares of Common Stock that are issuable at the then-prevailing conversion rate, pursuant to the Company Conversion Option. We may exercise our conversion right only if, for 20 trading days within any period of 30 consecutive trading days ending on the trading day prior to the announcement of our exercise of the option, the closing price of the Common Stock equals or exceeds 130% of the then-prevailing conversion price of the Series B Convertible Preferred Stock. The Series B Convertible Preferred Stock is non-redeemable by us.

We used the net proceeds of the offering of Series B Convertible Preferred Stock to fully repay all outstanding indebtedness under our senior revolving credit facility in the amount of $47.5 million (see Note D). The remaining net proceeds of the offering were added to our working capital to fund 2006 capital expenditures and for other general corporate purposes.

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 $29.2 million, which will be used to fund our 2006 capital expenditure program.

Stock Option and Incentive Programs

We have historically had two plans, which provide for stock option and other incentive awards for our key employees, consultants and directors: (a) the Goodrich Petroleum Corporation 1995 Stock Option Plan (the “Plan”), which allowed grants of stock options, restricted stock awards, stock appreciation rights, long-term incentive awards and phantom stock awards, or any combination thereof, to key employees and consultants, and (b) the Goodrich Petroleum Corporation 1997 Director Compensation Plan, which allowed grants of stock and options to each director who is not and has never been an employee of the Company. The Goodrich Petroleum Corporation 1995 Stock Option Plan expired according to its original terms in late 2005; however, our Board of Directors approved the extension of the Plan through December 31, 2005 and the granting of a total of 525,000 stock options at an exercise price of $23.39 and 101,129 shares of restricted stock to certain of our employees and officers as of December 6, 2005, subject to approval at our 2006 Annual Meeting of Stockholders. As of February 9, 2006, our directors and executive officers reached a level of more than 50% ownership of our total shares of Common Stock outstanding; therefore, stockholder approval of these actions was no longer contingent. For accounting purposes, we will begin expensing the December 6, 2005 grants based on the grant date value as determined under SFAS 123R, which utilizes the closing price of our Common Stock as of February 9, 2006. At our 2006 Annual Meeting of Stockholders, we expect to put forth to stockholders a proposal to implement a new combined plan to replace both the Goodrich Petroleum Corporation 1995 Stock Option Plan and the Goodrich Petroleum Corporation 1997 Director Compensation Plan.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Prior to the expiration of the Goodrich Petroleum Corporation 1995 Stock Option Plan, the two Goodrich plans had authorized grants of options to purchase up to a combined total of 2,300,000 shares of authorized but unissued common stock. Stock options were granted with an exercise price equal to the stock’s fair market value at the date of grant, and all employee stock options granted under the 1995 Stock Option Plan generally had ten year terms and three year pro rata vesting.

The per share weighted average fair value of stock options granted during the years ended December 31, 2005 and 2004 were $9.69 and $7.96, respectively, on the date of grant using the Black Scholes option-pricing model with the following weighted-average assumptions: (a) expected dividend yield 0%, (b) risk-free interest rate of 6%, (c) volatility of 47% in 2005 and 46% in 2004, and (d) an expected life of 5 years. There were no employee stock options granted in 2003. Stock option transactions during 2005, 2004 and 2003 were as follows:


	Number of Options		Weighted Average Exercise Price		Range of Exercise Price		Weighted Average Remaining Contractual Life
Outstanding, January 1, 2003	1,540,052				$	0.75 to $18.00	7.8 yrs
Granted – 1997 director compensation plan	20,000		$	4.85
Cancelled in exchange for common stock	(1,016,500	)		5.22
Exercised – 1995 stock option plan	(24,000	)		2.63
Expiration of options	(282,739	)		5.38

Outstanding, December 31, 2003	236,813				$	0.75 to $5.85	7.7 yrs
Granted – 1995 stock option plan	220,000			16.46
Exercised – 1995 stock option plan	(2,750	)		2.90
Exercised – 1997 director compensation plan	(43,563	)		3.74

Outstanding, December 31, 2004	410,500				$	0.75 to $16.46	8.5 yrs
Granted – 1997 director compensation plan	150,000			19.78
Exercised – 1995 stock option plan	(25,000	)		2.88
Exercised – 1997 director compensation plan	(16,000	)		4.92

Outstanding, December 31, 2005	519,500				$	0.75 to $19.78	8.4 yrs

Exercisable, December 31, 2003	194,813		$	3.03
Exercisable, December 31, 2004	169,500			3.20
Exercisable, December 31, 2005	372,100			12.60

In February 2003, we issued 125,157 shares of our 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 our common stock at the time of the exchange, we recorded a $0.4 million non-cash charge to earnings in 2003 related to the issuance of shares in lieu of cancelled options.

Also in 2003, we commenced granting a series of restricted share awards, with three year vesting periods, to our employees under a stockholder approved equity compensation plan. The cost of the shares of restricted stock award is recorded at fair market value at the date of grant as unearned compensation, a contra equity account. The unearned deferred compensation balance is shown as a reduction to stockholders’ equity and is being amortized to compensation expense ratably over the vesting period of the participants. During 2005, 2004 and 2003, we contributed $1.5 million, $2.1 million and $0.5 million, respectively, under the plan through the issuance of 75,750, 238,750 and 161,500 shares, respectively, of our common stock. During 2005, 2004 and 2003, $1.1 million, $0.6 million and $0.2 million, respectively, were charged to compensation expense related to the awards. During 2005 and 2004, we recorded credits to the contra equity account of $0.1 million and $0.2 million, respectively, for the value of 12,832 shares and 28,918 shares, respectively, of non-vested restricted share awards that were forfeited by terminated employees.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE I—Hedging Activities

Commodity Hedging Activity

We enter into swap contracts, costless collars or other hedging agreements from time to time to manage the commodity price risk for a portion of our production. We consider these to be hedging activities and, as such, monthly settlements on these contracts are reflected in our crude oil and natural gas sales, provided the contracts are deemed to be “effective” hedges under FAS 133. 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 December 31, 2005, 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. Hedge ineffectiveness results from difference changes in the NYMEX contract terms and the physical location, grade and quality of our oil and gas production. As of December 31, 2005, our open forward position on our outstanding commodity hedging contracts, all of which were with BNP, was as follows:


Swaps	Volume	Average Price
Natural gas (MMBtu/day)
1Q 2006	14,000	$	7.06
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)
1Q 2006	700	$	49.85
2Q 2006	800		50.80
3Q 2006	800		50.80
4Q 2006	800		50.80
2007	400		53.35

Collars	Volume	Floor/Cap
Natural gas (MMBtu/day)
1Q 2007	10,000	$	7.00 – $16.90
2Q 2007	15,000		7.00 – 15.90
3Q 2007	15,000		7.00 – 15.90
4Q 2007	15,000		7.00 – 15.90

The fair value of the oil and gas hedging contracts in place at December 31, 2005 resulted in a net liability of $29.4 million. As of December 31, 2005, $2.2 million (net of $1.2 million in income taxes) of deferred losses on derivative instruments accumulated in other comprehensive loss are expected to be reclassified into earnings during the next twelve months. For the year ended December 31, 2005, we recognized in earnings a loss on derivatives not qualifying for hedge accounting in the amount of $37.8 million (also included in this loss amount are settlement payments on ineffective gas hedges). This loss was recognized because our gas hedges were deemed to be ineffective for 2005, accordingly, the changes in fair value of such hedges could no longer be reflected in other comprehensive loss. For the year ended December 31, 2005, $6.0 million of previously deferred losses (net of $3.2 million in income taxes) was reclassified from accumulated other comprehensive loss to oil and gas sales as the cash flow of the hedged items was recognized.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In February 2006, we entered into a collar with the Bank of Montreal for 15,000 MMBtu per day with a floor of $7.00 and ceiling of $13.60 for calendar year 2007.

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.

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 December 31, 2005 we had the following interest rate swaps in place with BNP (in millions):


Effective Date	Maturity Date	LIBOR Swap Rate	Notional Amount
11/08/04	02/26/06	3.46%	$	18.0
02/27/06	02/26/07	4.08%		23.0
02/27/06	02/26/07	4.85%		17.0
02/27/07	02/26/09	4.86%		40.0

The fair value of the interest rate swap contracts in place at December 31, 2005, resulted in an asset of $0.1 million. As of December 31, 2005, $111,000 (net of $60,000 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 year ended December 31, 2005, $21,000 of previously deferred losses (net of $12,000 in income taxes) were reclassified from accumulated other comprehensive income to interest expense as the cash flow of the hedged items was recognized. For the years ended December 31, 2005 and 2004, our earnings were not significantly affected by cash flow hedging ineffectiveness of interest rates.

NOTE J—Fair Value of Financial Instruments

The following disclosure of the estimated fair value of financial instruments is made in accordance with the requirements of SFAS No. 107, “Disclosures About Fair Value of Financial Instruments” (“SFAS 107”). The estimated fair value amounts have been determined using available market information and valuation methodologies described below. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying amounts and fair values of the other financial instruments and derivatives at December 31, 2005 and 2004 are as follows (in thousands):


	2005						2004
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Long-term debt including current maturities	$	30,000		$	30,000		$	27,000		$	27,000
Production payment liability		—			—			268			268
Derivative assets (liabilities)
Oil		(4,810	)		(4,810	)		(2,657	)		(2,657	)
Gas		(24,620	)		(24,620	)		823			823
Interest rate		107			107			(162	)		(162	)

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE K—Commitments and Contingencies

Operating Leases

We have commitments under an operating lease agreement for office space. Total rent expense for the years ended December 31, 2005, 2004 and 2003 was approximately $0.4 million, $0.3 million and $0.3 million respectively. At December 31, 2005, the future minimum rental payments due under the lease are as follows (in thousands):


2006	$	495
2007		502
2008		508
2009		338

Total	$	1,843

We also have non-cancellable drilling rig commitments of $15.2 million and $2.7 million for 2006 and 2007, respectively.

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.

Litigation

In the third quarter of 2004, we recognized a non-recurring gain in the amount of $2.1 million, reflecting the proceeds of a successful litigation judgment. We commenced the litigation as plaintiff in February 2000 against the operator of a South Louisiana property which was jointly acquired by us and the defendant in September 1999. The judgment provided for recovery of our damages and a portion of our attorneys’ fees as well as interest calculated on our damages.

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.

NOTE L—Related Party Transactions

On March 12, 2002, we completed the sale of a 30% working interest in the existing production and shallow rights, and a 15% working interest in the deep rights below 10,600 feet, in our Burrwood and West Delta 83 fields for $12.0 million to Malloy Energy Company, LLC (“MEC”), led by Patrick E. Malloy, III and participated in by Sheldon Appel, each of whom were members of our Board of Directors at that time, as well as Josiah Austin, who subsequently became a member of our Board of Directors. Mr. Malloy is now Chairman of our Board of Directors and Mr. Appel retired from the Board of Directors in February 2004.

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Subsequent to the acquisition of a 30% working interest in the Burrwood and West Delta 83 fields in March 2002, MEC acquired an approximate 30% working interest in three other fields we operated in 2003 and 2004. In accordance with industry standard joint operating agreements, we bill MEC for its share of the capital and operating costs of the three fields on a monthly basis. As of December 31, 2005 and 2004, the amounts billed and outstanding to MEC for its share of monthly capital and operating costs were $0.5 million and $1.4 million, respectively, and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by MEC to us in the month subsequent to billing and the affiliate is current on payment of its billings.

We also serve as the operator for a number of other oil and gas wells owned by an affiliate of MEC in which we own a 7% after payout working interest. In accordance with industry standard joint operating agreements, we bill the affiliate for its share of the capital and operating costs of these wells on a monthly basis. As of December 31, 2005 and 2004, the amounts billed and outstanding to the affiliate for its share of monthly capital and operating costs were $31,000 and $1.7 million, respectively, and are included in trade and other accounts receivable at each year-end. Such amounts at each year-end were paid by the affiliate to us in the month subsequent to billing and the affiliate is current on payment of its billings.

NOTE M—Discontinued Operations

In October 2004, we sold our operated interests in the Marholl and Sean Andrew fields, along with our non-operated interests in the Ackerly field, all of which were located in West Texas, for gross proceeds of approximately $2.1 million. We realized a gain of $0.9 million on the sale of these non-core properties. The results of operations of these sold properties, including the gain on sale, have been presented as discontinued operations in the accompanying consolidated statement of operations.

Results for these properties reported as discontinued operations were as follows (in thousands):


	Year Ended December 31,
	2004			2003
Oil and gas sales	$	566		$	557
Operating expenses		(290	)		(256	)
Gain on sale		877			—

Income before income taxes		1,153			301
Income tax expense		(404	)		(105	)

Income from discontinued operations	$	749		$	196

NOTE N—Oil and Gas Producing Activities (Unaudited)

Capitalized Costs Related to Oil and Gas Producing Activities

The table below reflects our capitalized costs related to oil and gas producing activities at December 31, 2005, and 2004 (in thousands):


	2005			2004
Proved properties	$	301,842		$	148,497
Unproved properties		14,444			11,407

		316,286			159,904
Less accumulated depreciation, depletion and amortization		(73,291	)		(51,074	)

Net oil and gas properties	$	242,995		$	108,830

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Costs Incurred

Costs incurred in oil and gas property acquisition, exploration and development activities, whether capitalized or expensed, are summarized as follows (in thousands):


	Year Ended December 31,
	2005		2004		2003
Property Acquisition
Unproved	$	9,216	$	5,528	$	601
Exploration		14,021		4,874		2,249
Development (1)		143,574		36,351		18,177

	$	166,811	$	46,753	$	21,027

(1)	Includes asset retirement costs of $1,004 thousand in 2005, $389 thousand in 2004 and $453 thousand in 2003.

Oil and Natural Gas Reserves

All of our reserve information related to crude oil, condensate, and natural gas liquids and natural gas was compiled based on evaluations performed by Netherland, Sewell & Associates, Inc. as of December 31, 2005 and 2004. All of the subject reserves are located in the continental United States.

Many assumptions and judgmental decisions are required to estimate reserves. Quantities reported are considered reasonable but are subject to future revisions, some of which may be substantial, as additional information becomes available. Such additional knowledge may be gained as the result of reservoir performance, new geological and geophysical data, additional drilling, technological advancements, price changes, and other factors.

Regulations published by the SEC define proved reserves as those volumes of crude oil, condensate, and natural gas liquids and natural gas that geological and engineering data demonstrate with reasonable certainty are recoverable from known reservoirs under existing economic and operating conditions. Proved developed reserves are those volumes expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes expected to be recovered as a result of making additional investments by drilling new wells on acreage offsetting productive units or recompleting existing wells.

The following table sets forth our net proved oil and gas reserves at December 31, 2002, 2003, 2004 and 2005 and the changes in net proved oil and gas reserves for the years ended December 31, 2003, 2004 and 2005:


	Natural Gas (MMcf)						Oil (MBbls)
	2005		2004		2003		2005		2004		2003
Proved Reserves at beginning of period	67,682		30,903		29,069		5,589		7,805		7,441
Revisions of previous estimates (1)	(10,382	)	(6,666	)	648		(648	)	(3,466	)	54
Extensions, discoveries and other additions (2)	91,900		48,322		6,130		440		1,987		794
Sales of minerals in place	—		(54	)	(1,583	)	—		(249	)	—
Production	(6,237	)	(4,823	)	(3,361	)	(408	)	(488	)	(484	)

Proved Reserves at end of period	142,963		67,682		30,903		4,973		5,589		7,805

Table continued on following page

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


	Natural Gas (MMcf)			Oil (MBbls)
	2005	2004	2003	2005	2004	2003
Proved developed:
Beginning of period	24,362	23,429	15,203	2,228	3,601	2,557
End of period	56,700	24,362	23,429	1,796	2,228	3,601

(1)

Revisions of previous estimates were negative on an overall basis in 2005 and 2004 primarily related to our South Louisiana properties. The main reasons for this decrease were (a) the premature depletion or decline in production from wells which had larger estimates of producible reserves at the previous reporting period and (b) new and/or revised interpretations of technical data from recently drilled wells, updated production performance from existing and offset wells, and/or the results of enhanced 3-D seismic evaluations.

(2)

Extensions, discoveries and other reserve additions were positive on an overall basis in 2005 and 2004 and primarily related to our newly acquired properties in the Cotton Valley Trend of East Texas and North Louisiana. The main reason for this increase was the commencement of our Cotton Valley drilling program in the first quarter of 2004 which resulted in a substantial volume of both proved developed and proved undeveloped reserves being recorded.

The following table summarizes our combined oil and gas reserve information on a MMcfe basis.


	Year Ended December 31,
	2005	2004	2003
Total proved	172,799	101,216	77,736
Proved developed	67,474	37,732	45,035

Standardized Measure

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves as of year-end is shown below (in thousands):


	2005			2004			2003
Future revenues	$	1,798,972		$	654,543		$	446,165
Future lease operating expenses and production taxes		(379,872	)		(151,186	)		(87,929	)
Future development costs (1)		(245,868	)		(86,919	)		(33,180	)
Future income tax expense		(353,472	)		(104,870	)		(77,855	)

Future net cash flows		819,760			311,568			247,201
10% annual discount for estimated timing of cash flows		(409,140	)		(130,890	)		(83,227	)

Standardized measure of discounted future net cash flows	$	410,620		$	180,678		$	163,974

Average price used to calculate reserves (2)
Natural gas (per Mcf)	$	10.54		$	6.14		$	6.42
Oil (per Bbl)	$	58.80		$	42.72		$	31.75

(1)	Includes cumulative asset retirement obligations of $8.0 million, $6.8 million and $6.5 million in 2005, 2004 and 2003, respectively.

(2)	These average prices, used to estimate our reserves at these dates, reflect applicable transportation and quality differentials on a well-by-well basis.

Future revenues are computed by applying year-end prices of oil and gas to the year-end estimated future production of proved oil and gas reserves. The base prices used for the PV-10 calculation were public market prices on December 31 adjusted by differentials to those market prices. These price adjustments were done on a property-by-property basis for the quality of the oil and natural gas and for transportation to the appropriate location. Estimates of future development and production costs are based on year-end costs and assume continuation of existing economic conditions and year-end prices. We will incur significant capital in the development of our Cotton Valley Trend properties. We believe with reasonable certainty that we will be able

GOODRICH PETROLEUM CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

to obtain such capital in the normal course of business. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows. The standardized measure of discounted cash flows is the future net cash flows less the computed discount.

Changes in Standardized Measure

The following are the principal sources of change in the standardized measure of discounted net cash flows for the years shown (in thousands):


	Year Ended December 31,
	2005			2004			2003
Net changes in prices and production costs related to future production	$	185,709		$	84,156		$	47,406
Sales and transfers of oil and gas produced, net of production costs		(54,024	)		(34,636	)		(24,378	)
Net change due to revisions in quantity estimates		(48,540	)		(27,462	)		2,693
Net change due to extensions, discoveries and improved recovery		321,529			60,239			30,081
Net change due to purchases and sales of minerals in place		—			(4,278	)		(4,373	)
Future development costs		(79,618	)		(53,739	)		(4,227	)
Net change in income taxes		(124,526	)		(22,640	)		(23,136	)
Accretion of discount		24,148			21,462			15,136
Change in production rates (timing) and other		5,264			(6,398	)		510

	$	229,942		$	16,704		$	39,712

NOTE O — Summarized Quarterly Financial Data (Unaudited)

(In Thousands, Except Per Share Amounts)


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2005
Revenues	$	12,560		$	13,313		$	17,258		$	25,202		$	68,333
Operating income		691			73			3,006			9,342			13,112
Net income (loss)		(6,151	)		(445	)		(19,474	)		8,620			(17,450	)⁽²⁾
Net income applicable to common stock		(6,309	)		(603	)		(19,632	)		8,339			(18,205	)⁽²⁾
Basic income per average common share (1)		(0.30	)		(0.02	)		(0.79	)		0.35			(0.75	)
Diluted income per average common share (1)		(0.30	)		(0.02	)		(0.79	)		0.34			(0.75	)

2004
Revenues	$	10,764		$	9,191		$	12,014		$	13,043		$	45,012
Operating income		3,413			2,092			2,533			4,708			12,746
Income from continuing operations		2,077			2,831			4,288			8,582	⁽³⁾		17,778	⁽³⁾
Net income applicable to common stock		1,966			2,732			4,179			9,017	⁽³⁾		17,894	⁽³⁾
Basic income per average common share (1)		0.12			0.15			0.21			0.45			0.95
Diluted income per average common share (1)		0.10			0.14			0.21			0.43			0.91

(1)	The sum of the per share amounts per quarter does not equal the year due to the changes in the average number of common shares outstanding.

(2)	Includes a $27.0 million unrealized loss on derivatives not qualifying for hedge accounting.

(3)	Includes a $2.3 million unrealized gain on derivatives not qualifying for hedge accounting.