UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the quarterly period ended June 30, ~~2004.~~2005

¨	Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to . to

Commission file number 001-16009

SPINNAKER EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)

Delaware		76-0560101
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1200 Smith Street, Suite 800 Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)


1200 Smith Street, Suite 800
Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 759-1770

(Registrant’s telephone number, including area code)

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

The number of shares outstanding of the registrant’s common stock, par value $0.01 per share, on August 58, ~~2004~~2005 was 33 34,~~898~~136,~~340~~776.

SPINNAKER EXPLORATION COMPANY

Form 10-Q

For the Three and Six Months Ended June 30, ~~2004~~2005

		Page
Cautionary Statement About Forward-Looking Statements		3
PART I - FINANCIAL INFORMATION
Item 1.	Financial Statements
Consolidated Balance Sheets June 30, 2004 (unaudited) and December 31, 2003		4
Consolidated Balance SheetsAs of June 30, 2005 (unaudited) and December 31, 2004		3
Consolidated Statements of Operations Three and Six Months Ended June 30, 2004 and 2003 (unaudited)		5
Consolidated Statements of OperationsFor the Three and Six Months Ended June 30, 2005 and 2004 (unaudited)		4
Consolidated Statements of Cash Flows Six Months Ended June 30, 2004 and 2003 (unaudited)		6
Consolidated Statements of Cash FlowsFor the Six Months Ended June 30, 2005 and 2004 (unaudited)		5
Notes to Interim Consolidated Financial Statements (unaudited)		76
Cautionary Statement About Forward-Looking Statements		11
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	12
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2326
Item 4.	Controls and Procedures	2528
PART II - OTHER INFORMATION
Item 4.	Submission of Matters to a Vote of Security Holders	2629
Item 6.	Exhibits ~~and Reports on Form 8-K~~	2629
SIGNATURES		2730

Cautionary Statement About Forward-Looking Statements

Some of the information in this quarterly report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the “Exchange Act”). The forward-looking statements speak only as of the date made, and the Company undertakes no obligation to update such forward-looking statements. These forward-looking statements may be identified by the use of the words “believe,” “expect,” “anticipate,” “will,” “contemplate,” “would” and similar expressions that contemplate future events. These future events include the following matters:

• financial position;

• business strategy;

• budgets;

• amount, nature and timing of capital expenditures, including future development costs;

• drilling of wells;

• oil and gas reserves;

• timing and amount of future production of oil and gas;

• operating costs and other expenses;

• cash flow and anticipated liquidity;

• prospect development and property acquisitions; and

• marketing of oil and gas.

Numerous important factors, risks and uncertainties may affect the Company’s operating results, including:

• the risks associated with exploration;

• delays in anticipated start-up dates;

• shut-ins of production for platform, pipeline and facility maintenance, additions and removals;

• the ability to find, acquire, market, develop and produce new properties;

• oil and gas price volatility;

• uncertainties in the estimation of proved reserves and in the projection of future rates of production and timing of development expenditures;

• downward revisions of proved reserves and the related negative impact on the depreciation, depletion and amortization rate;

• production and reserves concentrated in a small number of properties;

• operating hazards attendant to the oil and gas business;

• drilling and completion risks, which costs are generally not recoverable from third parties or insurance;

• potential mechanical failure or under-performance of significant wells;

• impact of weather conditions on timing and costs of operations;

• availability and cost of material and equipment;

• actions or inactions of third-party operators of the Company’s properties;

• the ability to find and retain skilled personnel;

• availability of capital;

• the strength and financial resources of competitors;

• regulatory developments;

• environmental risks; and

• general economic conditions.

Any of the factors listed above and other factors contained in this quarterly report could cause the Company’s actual results to differ materially from the results implied by these or any other forward-looking statements made by the Company or on its behalf. The Company cannot provide assurance that future results will meet its expectations. You should pay particular attention to the risk factors and cautionary statements described in the Company’s annual report on Form 10-K for the year ended December 31, 2003.

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)

	As of June 30, 2004			As ofDecember 31, 2003
	As of June 30, 2005			As of December 31,2004
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	167,~~027~~798		$	1521,~~315~~830
Accounts receivable, net of allowance for doubtful accounts of $3,232 as of June 30, 2004 and December 31, 2003, respectively		53,796			30,067
Accounts receivable, net of allowance for doubtful accounts of $3,232 as of June 30, 2005 and December 31, 2004, respectively		62,289			48,785
Hedging assets		—			~~203~~2,829
Other		4,941			4,193
Deferred tax assets		41,953			—
Total current assets		74,764			49,778
Other		7,752			3,467
Total current assets		119,792			76,911
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		1,~~317~~593,~~903~~007			1,~~175~~447,~~443~~824
Unproved properties and properties under development, not being amortized		~~150~~178,~~650~~141			~~151~~148,~~214~~277
Other		187,~~365~~129			176,~~309~~651
		1,486,918			1,343,966
		1,778,277			1,602,752
Less – Accumulated depreciation, depletion and amortization		(~~475~~634,~~590~~308	)		(~~404~~541,~~298~~615	)
Total property and equipment		1,~~011~~143,~~328~~969			~~939~~1,~~668~~061,137
OTHER ASSETS		~~854~~1,148			112,~~136~~883
Total assets	$	1,~~086~~264,~~946~~909		$	~~990~~1,~~582~~150,931
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	2630,~~869~~479		$	1834,~~723~~692
Accrued liabilities and other		4562,~~904~~206			6047,~~874~~264
Hedging liabilities		611,~~319~~848			21,~~903~~628
Asset retirement obligations, current portion		110,~~139~~471			~~446~~6,841
Total current liabilities		80115,~~231~~004			8290,~~946~~425
LONG-TERM DEBT		93105,000			50105,000
ASSET RETIREMENT OBLIGATIONS		3537,~~123~~460			3233,~~548~~644
DEFERRED INCOME TAXES		95163,~~834~~402			81107,~~027~~776
COMMITMENTS AND CONTINGENCIES EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; no shares issued and outstanding as of June 30, 2004 and December 31, 2003, respectively		—			—
Preferred stock, $0.01 par value; 10,000,000 shares authorized; no shares issued and outstanding as of June 30, 2005 and December 31, 2004, respectively		—			—
Common stock, $0.01 par value; 50,000,000 shares authorized; 33,795,935 shares issued and 33,788,795 shares outstanding as of June 30, 2004 and 33,385,248 shares issued and 33,374,844 shares outstanding as of December 31, 2003		338			334
Common stock, $0.01 par value; 50,000,000 shares authorized; 34,105,433 shares issued and 34,101,493 shares outstanding as of June 30, 2005 and 33,927,158 shares issued and 33,920,018 shares outstanding as of December 31, 2004		341			339
Additional paid-in capital		~~609~~617,~~191~~552			~~599~~612,~~532~~920
Retained earnings		~~177~~234,~~291~~347			~~145~~199,~~949~~882
Less: Treasury stock, at cost, 7,140 and 10,404 shares as of June 30, 2004 and December 31, 2003, respectively		(18	)		(26	)
Less: Treasury stock, at cost, 3,940 shares and 7,140 shares as of June 30, 2005 andDecember 31, 2004, respectively		(10	)		(18	)
Accumulated other comprehensive loss		(4,044	)		(1,728	)
Unearned compensation		(1,506	)		—
Total equity		782,758			744,061
Accumulated other comprehensive income (loss)		(6,681	)		963
Total liabilities and equity	$	1,086,946		$	990,582
Total equity		844,043			814,086
Total liabilities and equity	$	1,264,909		$	1,150,931

The accompanying notes are an integral part of these consolidated financial statements.

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share data)

(Unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
	2005			2004			2005			2004
REVENUES	$	7991,~~824~~970		$	5579,~~931~~824		$	~~139~~170,~~615~~293		$	~~127~~139,~~602~~615
EXPENSES:
Lease operating expenses		67,~~530~~496			56,~~208~~530			1114,~~243~~143			1011,~~701~~243
Depreciation, depletion and amortization – oil and gas properties		4042,~~403~~194			3140,~~242~~403			6983,~~404~~631			6469,~~077~~404
Depreciation and amortization – other		~~350~~316			~~322~~350			~~696~~584			~~633~~696
Accretion expense		538			569			1,254			1,064
Impairment of international oil and gas properties		735			—			8,478			—
Gain on settlement of asset retirement obligations		—			(171	)		(126	)		(171	)
Accretion of asset retirement obligations		929			538			1,611			1,254
General and administrative		4,227			3,001			7,725			6,040
Gain on settlement of asset retirement obligations		(13	)		—			(128	)		(126	)
Total expenses		52,048			40,171			90,196			82,344
General and administrative		4,272			4,227			8,354			7,725
INCOME FROM OPERATIONS		27,776			15,760			49,419			45,258
Total expenses		55,929			52,048			116,673			90,196
INCOME FROM OPERATIONS		36,041			27,776			53,620			49,419
OTHER INCOME (EXPENSE):
Interest income		36100			6236			68197			~~127~~68
Interest expense, net		(~~304~~277	)		(~~153~~304	)		(~~515~~548	)		(~~302~~515	)
Total other income (expense)		(~~268~~177	)		(91268	)		(~~447~~351	)		(~~175~~447	)
INCOME BEFORE INCOME TAXES		2735,~~508~~864			1527,~~669~~508			4853,~~972~~269			4548,~~083~~972
Income tax expense		912,~~903~~660			59,~~641~~903			1718,~~630~~804			1617,~~230~~630
INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		17,605			10,028			31,342			28,853
NET INCOME	$	23,204		$	17,605		$	34,465		$	31,342
Cumulative effect of change in accounting principle		—			—			—			(3,527	)
NET INCOME PER COMMON SHARE:
NET INCOME	$	17,605		$	10,028		$	31,342		$	25,326
Basic	$	0.68		$	0.52		$	1.01		$	0.93
BASIC INCOME PER COMMON SHARE:
Diluted	$	0.66		$	0.51		$	0.99		$	0.90
Income before cumulative effect of change in accounting principle	$	0.52		$	0.30		$	0.93		$	0.87
Cumulative effect of change in accounting principle		—			—			—			(0.11	)
NET INCOME PER COMMON SHARE	$	0.52		$	0.30		$	0.93		$	0.76
DILUTED INCOME PER COMMON SHARE:
Income before cumulative effect of change in accounting principle	$	0.51		$	0.30		$	0.90		$	0.85
Cumulative effect of change in accounting principle		—			—			—			(0.10	)
NET INCOME PER COMMON SHARE	$	0.51		$	0.30		$	0.90		$	0.75
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		3334,~~719~~036			33,~~207~~719			33,~~633~~989			33,~~199~~633
Diluted		34,~~779~~954			3334,~~859~~779			34,~~708~~935			3334,~~776~~708

The accompanying notes are an integral part of these consolidated financial statements.

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended June 30,
	2004			2003
	2005			2004
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	3134,~~342~~465		$	2531,~~326~~342
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		7084,~~100~~215			6470,~~710~~100
Accretion expense		1,254			1,064
Impairment of international oil and gas properties		8,478			—
Gain on settlement of asset retirement obligations		(126	)		(171	)
Accretion of asset retirement obligations		1,611			1,254
Deferred income tax expense		17,630			15,970
Gain on settlement of asset retirement obligations		(128	)		(126	)
Cumulative effect of change in accounting principle		—			3,527
Amortization of unearned stock compensation		41			—
Other		415			132
Deferred income tax expense		18,226			17,630
Other		1,575			415
Change in operating assets and liabilities:
Accounts receivable		(2313,~~729~~504	)		10(23,~~657~~729	)
Accounts payable and accrued liabilities		4(12,~~653~~639	)		54,~~891~~653
Other assets		~~938~~7,450			~~3,034~~938
Net cash provided by operating activities		~~102~~129,~~477~~790			~~130~~102,~~140~~477
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties		(~~150~~145,~~041~~266	)		(~~144~~150,~~203~~974	)
Proceeds from sale of oil and gas property and equipment		—			1,148
Purchases of other property and equipment		(478	)		(123	)
Purchases of other property and equipment		(1,056	)		(757	)
Net cash used in investing activities		(145,744	)		(151,097	)
Net cash used in investing activities		(151,097	)		(143,812	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		4313,~~000~~500			—43,000
Debt issue costs		(101	)		—
Payments on borrowings		(13,500	)		—
Proceeds from exercise of stock options		61,~~433~~922			~~347~~6,433
Net cash provided by financing activities		49,332			347
Debt issue costs		—			(101	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		712			(13,325	)
Net cash provided by financing activities		1,922			49,332
CASH AND CASH EQUIVALENTS, beginning of year		15,315			32,543
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(14,032	)		712
CASH AND CASH EQUIVALENTS, end of period	$	16,027		$	19,218
CASH AND CASH EQUIVALENTS, beginning of year		21,830			15,315
CASH AND CASH EQUIVALENTS, end of period	$	7,798		$	16,027
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts capitalized	$	1,365		$	149
Cash paid for interest	$	2,497		$	1,365
Cash paid for income taxes	$	—160		$	~~260~~—

The accompanying notes are an integral part of these consolidated financial statements.

SPINNAKER EXPLORATION COMPANY

Notes to Interim Consolidated Financial Statements (Unaudited)

June 30, ~~2004~~2005

1. Basis of Presentation

The accompanying unaudited consolidated financial statements of Spinnaker Exploration Company (“Spinnaker” or the “Company”) have been prepared in accordance with generally accepted accounting principles for interim financial information and the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by accounting principles generally accepted in the United States for complete financial statements. In the opinion of management, all adjustments (consisting only of normal and recurring adjustments) necessary to present a fair statement of the results for the periods included herein have been made and the disclosures contained herein are adequate to make the information presented not misleading. Interim period results are not necessarily indicative of results of operations or cash flows for a full year. These consolidated financial statements and the notes thereto should be read in conjunction with the Company’s Annual Report on Form 10-K for the year ended December 31, ~~2003~~2004.

2. Summary of Significant Accounting Policies

Stock-Based Compensation

Statement of Financial Accounting Standards (“SFAS”) No. ~~123~~148, “Accounting for Stock-Based Compensation,” ~~encourages,~~– ~~but~~Transition ~~does~~and ~~not require~~Disclosure, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to account for stock-based compensation using the intrinsic value method prescribed in Accounting Principles Board (“APB”) ~~Opinion~~amends SFAS No. ~~25,~~123 ~~“Accounting for Stock Issued~~ to ~~Employees,”~~provide ~~and~~alternative ~~related~~methods ~~interpretations.~~of ~~Accordingly,~~transition ~~compensation cost~~ for ~~stock~~an ~~options~~entity ~~is measured~~that asvoluntarily ~~the~~changes ~~excess,~~to ~~if any, of~~ the fair value ofbased ~~the~~method ~~common~~of accounting for stock,-based ~~par~~employee ~~value~~compensation ~~$0.01~~and ~~per~~to ~~share~~require ~~(“Common~~prominent ~~Stock”),~~disclosure atabout the ~~date~~effects ofon ~~the~~reported ~~grant~~net ~~over~~income ~~the~~of ~~amount~~ an ~~employee~~entity’s ~~must~~accounting ~~pay~~policy todecisions ~~acquire the Common Stock. In accordance~~ with ~~APB~~respect ~~Opinion No. 25, compensation expense related~~ to stock-based ~~compensation~~employee ~~was $0~~compensation.2 ~~million~~SFAS ~~and $0 in the second quarter of 2004 and 2003, respectively, and $0~~No.2 ~~million~~148 ~~and~~amends ~~$0 in the first six months of 2004 and 2003, respectively. Had compensation cost for~~Accounting ~~the~~Principles ~~Company’s~~Board ~~stock~~(“APB”) ~~option~~Opinion ~~compensation plans been determined based on the fair value at the grant dates for awards under these plans consistent with the method of SFAS~~ No. ~~123~~28, ~~the~~“Interim ~~Company’s~~Financial ~~pro~~Reporting,” ~~forma~~to ~~net~~require ~~income~~disclosure ~~and~~about ~~pro~~those ~~forma~~effects ~~net income per share of Common Stock would have been as follows (~~in ~~thousands,~~interim ~~except~~financial ~~per~~information. ~~share amounts):~~

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Net income, as reported	$	17,605		$	10,028		$	31,342		$	25,326
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		126			—			126			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2,115	)		(3,021	)		(4,654	)		(4,867	)
Pro forma net income	$	15,616		$	7,007		$	26,814		$	20,459
Net income per common share:
Basic, as reported	$	0.52		$	0.30		$	0.93		$	0.76
Basic, pro forma	$	0.46		$	0.21		$	0.80		$	0.62
Diluted, as reported	$	0.51		$	0.30		$	0.90		$	0.75
Diluted, pro forma	$	0.43		$	0.20		$	0.75		$	0.60

SFAS No. 123, “Accounting for Stock-Based Compensation,” encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. The Company has chosen to account for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the fair value of the Company’s common stock, par value $0.01 per share (“Common Stock”), at the date of the grant over the amount an employee must pay to acquire the Common Stock. In accordance with APB Opinion No. 25, compensation expense related to stock-based compensation was $0 and $0.2 million in the second quarter of 2005 and 2004, respectively, and $0 and $0.2 million in the first six months of 2005 and 2004, respectively. Had compensation cost for the Company’s stock option compensation plans been determined based on the fair value at the grant dates for awards under these plans consistent with the method of SFAS No. 123, the Company’s pro forma net income and pro forma net income per share of Common Stock would have been as follows (in thousands, except per share amounts):

Leasehold Costs


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Net income, as reported	$	23,204		$	17,605		$	34,465		$	31,342
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		—			126			—			126
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(1,806	)		(2,115	)		(3,076	)		(4,654	)

Pro forma net income	$	21,398		$	15,616		$	31,389		$	26,814

Net income per common share:
Basic, as reported	$	0.68		$	0.52		$	1.01		$	0.93

Basic, pro forma	$	0.63		$	0.46		$	0.92		$	0.80

Diluted, as reported	$	0.66		$	0.51		$	0.99		$	0.90

Diluted, pro forma	$	0.59		$	0.43		$	0.87		$	0.75

In6 June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141, “Business Combinations,” which requires the use of the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates

On December 16, 2004, the Financial Accounting Standards Board (“FASB”) revised SFAS No. 123 (revised 2004), “Share-Based Payment,” (“SFAS No. 123R”) that will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS No. 123R replaces SFAS No. 123 and supersedes APB Opinion No. 25. Adoption of SFAS No. 123R will require the Company to recognize compensation expense for all awards the Company grants after the date of adoption and for the unvested portion of all options granted that remain outstanding on the date of adoption.

On April 14, 2005, the Securities and Exchange Commission (“Commission”) announced that it would permit additional time to implement the requirements in SFAS No. 123R. As originally issued by the FASB, public companies were required to implement SFAS No. 123R as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Commission will permit companies to implement SFAS No. 123R at the beginning of their next fiscal year, instead of the next reporting period beginning after June 15, 2005 as required by SFAS No. 123R. The Commission is not changing any of the accounting requirements in SFAS No. 123R. The Company will be required to implement SFAS No. 123R as of January 1, 2006. All options that the Company granted prior to December 31, 2001 will be fully vested prior to adoption of SFAS No. 123R and will not be considered as part of the adoption in accordance with the new standard. The Company is currently evaluating the effect of adopting SFAS No. 123R.

In May 2005, Spinnaker’s Compensation Committee of the Board of Directors authorized the issuance of 48,275 restricted shares of common stock to all employees. The restricted shares of common stock were issued under the Company’s 1999 Stock Incentive Plan and 2001 Stock Incentive Plan. The restricted stock awards are amortized ratably over the vesting period of four years. Spinnaker recorded $1.6 million of unearned compensation in connection with this grant, representing the fair value of the restricted stock awards on the date of grant. Unearned compensation will be recognized as compensation expense within general and administrative expenses and oil and gas properties ratably over the remaining vesting periods. The related compensation expense totaled $0.1 million for the three months ended June 30, 2005.

3. Deferred Tax Assets

The Company was in a tax loss position as of December 31, 2004, and based on the results in the first six months of 2005 and review of the Company’s outlook on future operations, the Company expects that it will have taxable income in the next twelve months. As a result, the Company has reclassified from deferred income taxes liability a current deferred tax asset of $37.8 million related to net operating loss carryforwards that it expects to utilize to offset taxable income in the next twelve months. As of June 30, 2005, deferred tax assets also included $4.2 million related to hedging activities.

4. Long-Term Debt

On December 19, 2003, the Company’s wholly-owned subsidiary, Spinnaker Exploration Company, L.L.C., entered into a $200.0 million revolving credit agreement (the “Revolver”) with a group of eight banks. The Revolver consists of two tranches, Tranche A and Tranche B. The $50.0 million Tranche B commitment was terminated on July 21, 2005 (with no borrowings then outstanding under Tranche B) upon closing of the spar production facility sale-leaseback transaction related to the Company’s deepwater project at Green Canyon Blocks 338/339/382 (“Front Runner”). See Note 10 for further information concerning the sale-leaseback transaction. Borrowings under Tranche A constitute senior indebtedness. The obligations under the Revolver are fully and unconditionally guaranteed by Spinnaker.

Tranche A is available on a revolving basis through December 19, 2006, the maturity date of the Revolver, and availability is subject to the borrowing base determined by the banks. The borrowing base was $160.0 million as of June 30, 2005. The obligations under Tranche A are unsecured. The borrowing base is re-determined semi-annually by the banks in their sole discretion and in their usual and customary manner. Spinnaker and the banks also have the right to request one additional re-determination annually. The amount of the borrowing base is a function of the banks’ view of Spinnaker’s reserve profile, future commodity prices and projected cash flows. In addition to the semi-annual re-determinations, the banks have the right to re-determine the borrowing base in the event of the sale, transfer or disposition of assets included in the borrowing base exceeding $25.0 million.

The Company has the option to elect to use a base interest rate as described below or the London Interbank Offered Rate (“LIBOR”) plus, for each such rate, a spread based on the percentage of the borrowing base used at that time. The base rate spread ranges from 0.0% to 0.5%, and the LIBOR spread ranges from 1.25% to 2.0% for Tranche A

an borrowings. ~~annual~~The ~~review~~base ofinterest ~~impairment.~~rate ~~The~~under ~~new~~the ~~standard~~Revolver ~~also~~is ~~requires~~a ~~that,~~fluctuating atrate aof ~~minimum,~~interest ~~all~~equal ~~intangible~~to ~~assets~~the bebase ~~aggregated~~rate spread plus the higher of either (i) The ~~and~~Toronto-Dominion ~~presented~~Bank’s asbase arate ~~separate~~for ~~line~~dollar ~~item~~advances made in the ~~balance~~United ~~sheet~~States or (ii) the Federal Funds Rate plus 0.5% per annum. The ~~adoption~~weighted ofaverage ~~SFAS~~interest Norate was 4.6% ~~141~~in ~~and~~the ~~142~~first ~~had~~six nomonths ~~impact~~of 2005. The commitment fee rate ranges from 0.375% to 0.5%, depending on the ~~Company’s~~borrowing ~~financial~~base ~~position~~usage orfor ~~results~~Tranche ~~of operations~~A.

AAs ~~reporting~~of ~~issue~~June ~~has~~30, ~~arisen~~2005, ~~regarding~~ the ~~application~~Company ofhad ~~certain~~outstanding ~~provisions~~borrowings of ~~SFAS No~~$105.0 ~~141~~million, and ~~142~~the toCompany ~~companies~~was in ~~the extractive~~compliance ~~industries,~~with ~~including~~the ~~oil~~provisions ~~and~~of ~~gas~~the ~~companies~~Revolver. ~~The~~Subsequent ~~issue is whether SFAS No. 141 requires registrants~~ to ~~classify~~June ~~the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet~~30, ~~apart from other capitalized oil and gas property costs~~2005, ~~and~~Spinnaker ~~provide~~had ~~specific~~no ~~footnote~~additional ~~disclosures. Historically~~borrowings, ~~the~~made ~~Company and the extractive industries have included the costs of mineral rights associated with extracting oil and gas as~~ a ~~component~~payment of ~~oil and gas~~ ~~properties~~$75.0 Ifmillion itusing isproceeds ~~ultimately~~from ~~determined~~the ~~that~~Front ~~SFAS~~Runner ~~No.~~sale-leaseback ~~141~~transaction ~~requires oil~~ and ~~gas~~issued ~~companies~~a toletter ~~classify costs~~ of ~~mineral~~credit ~~rights~~in ~~associated~~the ~~with~~amount ~~extracting~~of ~~oil~~$15.0 ~~and~~million ~~gas~~under ~~as a separate intangible assets line item on~~ the ~~balance~~Revolver. ~~sheet,~~Current ~~the~~availability ~~Company~~is ~~would be required to reclassify approximately~~ $85115.80 million ~~and~~under ~~$72.2~~Tranche ~~million~~A as of ~~June~~the ~~30, 2004 and December 31, 2003, respectively, from oil and gas properties to a separate intangible assets line item~~Revolver. ~~These costs include those to acquire contract-based drilling and mineral use rights such as delay rentals, lease bonuses, commission fees and other leasehold costs.~~ The Company~~’s cash flows and results of operations would not be affected since such intangible assets would continue~~ expects to beincur ~~depleted~~additional ~~and~~borrowings ~~assessed for impairment~~ in ~~accordance~~the ~~with~~remainder ~~full~~of ~~cost accounting rules~~2005. ~~Spinnaker will continue to classify its oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided.~~

35. Asset Retirement Obligations

~~Effective January 1, 2003, Spinnaker adopted~~ SFAS No. 143, “Accounting ~~for~~ for Asset Retirement Obligations.” ~~SFAS No. 143~~ requires entities to record aliabilities ~~liability~~ for asset retirement obligations at fair value in the period in which itthe isobligations are incurred and a corresponding increase in the carrying amount of the related long-lived asset. AsThe reconciliation of ~~January 1, 2003,~~ the ~~Company~~beginning ~~recorded asset retirement costs of $21.4 million~~ and ending asset retirement obligations ofis ~~$26.0~~as ~~million.~~follows ~~The cumulative effect of change~~ (in ~~accounting~~thousands): ~~principle was $3.5 million, after taxes of $2.0 million.~~

The reconciliation of the beginning and ending asset retirement obligations for the three and six months ended June 30, 2004 and 2003 was as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Asset retirement obligations, beginning of period	$	45,591		$	33,974		$	40,485		$	32,994
Liabilities incurred		1,645			2,261			6,484			2,834
Liabilities settled (1)		(381	)		—			(923	)		—
Accretion expense		929			538			1,611			1,254
Revisions in estimated cash flows		147			(511	)		274			(820	)

Asset retirement obligations, end of period	$	47,931		$	36,262		$	47,931		$	36,262

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Asset retirement obligations, beginning of period	$	33,974		$	27,275		$	32,994		$	—
Liabilities upon adoption of SFAS No. 143 on January 1, 2003		—			—			—			25,954
Liabilities incurred		2,261			5,019			2,834			5,845
Liabilities settled		—			(2,638	)		—			(2,638	)
Accretion expense		538			569			1,254			1,064
Revisions in estimated cash flows		(511	)		(108	)		(820	)		(108	)
Asset retirement obligations, end of period	$	36,262		$	30,117		$	36,262		$	30,117

(1)

The costs associated with asset retirements in the second quarter of 2005 were approximately $0.4 million, resulting in a gain on settlement of asset retirement obligations of less than $0.1 million. The costs associated with asset retirements in the first six months of 2005 were approximately $0.8 million, resulting in a gain on settlement of asset retirement obligations of approximately $0.1 million.

6. Commodity Price Risk Management Activities

The Company enters into New York Mercantile Exchange (“NYMEX”) related swap contracts and collar arrangements from time to time. The natural gas swap contracts and collar arrangements will settle based on the reported settlement price on the NYMEX for the last trading day of each month. The crude oil swap contracts and collar arrangements will settle based on the average of the settlement price for each commodity business day in the contract month.

In a swap transaction, the counterparty is required to make a payment to Spinnaker for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. Spinnaker is required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the settlement price is above the fixed price. In a collar arrangement, the counterparty is required to make a payment to Spinnaker for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. Spinnaker is required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price. Neither party is required to make a payment if the settlement price falls between the fixed floor and ceiling prices. As of June 30, 2005, Spinnaker’s commodity price risk management positions in swap contracts and collar arrangements were as follows:

Natural Gas


	Fixed Price Swaps			Collars
Period	Average Daily Volume (MMBtus)	Weighted Average Price (Per MMBtu)		Average Daily Volume (MMBtus)	Weighted Average Price (Per MMBtu)
Period	Average Daily Volume (MMBtus)	Weighted Average Price (Per MMBtu)		Average Daily Volume (MMBtus)	Floor		Ceiling
Third Quarter 2005	10,000	$	6.40	—	$	—	$	—
Fourth Quarter 2005	3,370		6.40	—		—		—

4.Oil ~~Earnings Per Share~~

Basic and diluted net income per common share is computed based on the following information (in thousands, except per share amounts):


	Fixed Price Swaps			Collars
	Average Daily Volume	Weighted Average Price		Average Daily Volume	Weighted Average Price (Per Bbl)
Period	(Bbls)	(Per Bbl)		(Bbls)	Floor		Ceiling
Third Quarter 2005	1,000	$	39.69	3,000	$	38.67	$	44.73
Fourth Quarter 2005	1,000		38.78	3,000		38.67		44.73

	Three Months Ended June 30,				Six Months Ended June 30,
	2004		2003		2004		2003
Numerator:
Net income available to common stockholders	$	17,605	$	10,028	$	31,342	$	25,326
Denominator:
Basic weighted average number of shares		33,719		33,207		33,633		33,199
Dilutive securities:
Stock options		1,060		652		1,075		577
Diluted adjusted weighted average number of shares and assumed conversions		34,779		33,859		34,708		33,776
Basic income per common share:
Income before cumulative effect of change in accounting principle	$	0.52	$	0.30	$	0.93	$	0.87
Cumulative effect of change in accounting principle		—		—		—		(0.11	)
Net income per common share	$	0.52	$	0.30	$	0.93	$	0.76
Diluted income per common share:
Income before cumulative effect of change in accounting principle	$	0.51	$	0.30	$	0.90	$	0.85
Cumulative effect of change in accounting principle		—		—		—		(0.10	)
Net income per common share	$	0.51	$	0.30	$	0.90	$	0.75

The Company reported a net liability of $11.8 million and a net asset of $1.2 million related to financial derivative contracts as of June 30, 2005 and December 31, 2004, respectively. Amounts related to hedging activities were as follows (in thousands):

5. Debt


	As of June 30, 2005			As of December 31, 2004
Current assets:
Hedging assets	$	—		$	2,829
Deferred tax asset related to hedging activities		4,182			—

Current liabilities:
Hedging liabilities	$	11,848		$	1,628
Deferred tax liability related to hedging activities		—			432

Equity:
Accumulated other comprehensive income (loss)	$	(6,681	)	$	963

OnThe ~~December~~ineffective component ~~19,~~of ~~2003,~~derivatives ~~Spinnaker revised~~ and ~~renewed~~net ~~the~~hedging ~~$200.0~~gains ~~million revolving credit agreement~~ (~~the “Revolver”~~losses) ~~with~~were arecorded ~~group~~in ofrevenues ~~eight~~in ~~banks.~~the ~~The~~three ~~Revolver consists of two tranches, Tranche A~~ and ~~Tranche~~six B,months ~~and~~ended ~~matures~~June ~~on December 19~~30, ~~2006.~~2005 ~~Borrowings~~and ~~under~~2004 ~~each~~as ~~tranche~~follows ~~constitute~~(in ~~senior~~thousands): ~~indebtedness.~~

Tranche A is available on a revolving basis through the maturity of the Revolver, and availability is subject to the borrowing base, currently $140.0 million, as determined by the banks. Tranche B is $50.0 million, is available in multiple advances through April 1, 2005 and is not subject to the borrowing base. The Company has made no borrowings under Tranche B. Borrowings under Tranche B cannot be reborrowed once repaid. Total availability under Tranche A and Tranche B cannot exceed $200.0 million. Should the borrowing base exceed $150.0 million, Tranche B would be reduced by a like amount for the period the borrowing base exceeds $150.0 million until the maturity of Tranche B. At such time Tranche B is utilized, the banks are to be provided with security interests in virtually all of Spinnaker’s reserve base. Upon repayment of Tranche B, the security interests are to be released.


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Ineffective component of derivatives	$	160		$	—		$	(1,328	)	$	—

Net hedging losses	$	(3,719	)	$	(3,285	)	$	(3,126	)	$	(1,546	)

~~The~~Based ~~borrowing~~on ~~base~~future ~~is re-determined semi-annually by the banks in their sole discretion~~ oil and ingas ~~their~~prices ~~usual~~as ~~and~~of ~~customary~~June ~~manner.~~30, ~~The~~2005, ~~banks and~~ the Company ~~also~~ ~~have~~would ~~the~~reclassify ~~right~~a tonet ~~request~~loss ~~one~~of ~~additional~~approximately ~~re-determination annually~~$6.7 ~~The~~million ~~amount~~from ofaccumulated ~~the~~other ~~borrowing~~comprehensive ~~base~~income is(loss) ato ~~function~~earnings ofin the ~~banks’~~remainder ~~view~~ of ~~Spinnaker’s~~2005. ~~reserve~~The ~~profile,~~amounts ~~future~~ultimately ~~commodity~~reclassified ~~prices~~into ~~and~~earnings ~~projected cash flows. In addition to the~~will ~~semi-annual~~vary ~~re-determinations,~~due ~~the banks have the right~~ to ~~re-determine~~changes ~~the borrowing base~~ in the ~~event~~fair ofvalue ~~the sale, transfer or disposition~~ of ~~assets included in~~ the ~~borrowing~~open ~~base~~derivative ~~exceeding~~contracts ~~$25.0~~prior ~~million,~~to ~~or $10~~settlement.0 ~~million when Tranche B is utilized.~~

The Company has the option to elect to use a base interest rate as described below or London Interbank Offered Rate (“LIBOR”) plus, for each such rate, a spread based on the percentage of the borrowing base used at that time. The base interest rate spread ranges from 0.0% to 0.5% for Tranche A borrowings and from 2.0% to 2.75% for Tranche B borrowings. The LIBOR spread ranges from 1.25% to 2.0% for Tranche A borrowings and from 3.0% to 3.75% for Tranche B

~~borrowings~~7. ~~The~~Earnings ~~base~~Per ~~interest~~Share rate under the Revolver is a fluctuating rate of interest equal to the higher of either (i) The Toronto-Dominion Bank’s base rate for dollar advances made in the United States or (ii) the Federal Funds Rate plus 0.5% per annum. The commitment fee rate ranges from 0.375% to 0.5%, depending on the borrowing base usage for Tranche A, and is 0.625% for Tranche B. The Revolver contains various restrictions and covenants.

OnBasic ~~June 30, 2004, the Company had outstanding borrowings under Tranche A of $93.0 million~~ and ~~was~~diluted innet ~~compliance~~income ~~with~~per ~~the~~common ~~covenants~~share ~~and~~is ~~restrictive~~computed ~~provisions~~based ~~under~~on the ~~Revolver.~~following ~~Subsequent~~information to(in ~~June 30~~thousands, ~~2004,~~except ~~the Company~~per ~~had~~share noamounts): ~~additional borrowings; however, the Company expects to incur additional borrowings under Tranche A of the Revolver in the remainder of 2004.~~

6. Commodity Price Risk Management Activities:


	Three Months Ended June 30,				Six Months Ended June 30,
	2005		2004		2005		2004
Numerator:
Net income available to common stockholders	$	23,204	$	17,605	$	34,465	$	31,342

Denominator:
Basic weighted average number of shares		34,036		33,719		33,989		33,633

Dilutive securities:
Stock options		918		1,060		946		1,075


Diluted adjusted weighted average number of shares and assumed conversions		34,954		34,779		34,935		34,708

Net income per common share:
Basic	$	0.68	$	0.52	$	1.01	$	0.93

Diluted	$	0.66	$	0.51	$	0.99	$	0.90

~~The Company enters into New York Mercantile Exchange (“NYMEX”) related swap contracts and collar arrangements from time to time~~8. ~~These~~Comprehensive ~~swap~~Income ~~contracts and collar arrangements will settle based on the reported settlement price on the NYMEX for the last trading day of each month for natural gas.~~

In a swap transaction, the counterparty is required to make a payment to the Company for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. The ~~Company~~following isare ~~required~~components ~~to make a payment to the counterparty for the difference between the fixed price and the settlement price if the settlement price is above the fixed price. As~~ of ~~June~~comprehensive ~~30, 2004,~~income ~~Spinnaker’s commodity price risk management positions~~ (in ~~fixed price natural gas swap contracts and related fair values were as follows~~ thousands):

Period	AverageDailyVolume(MMBtus)		WeightedAveragePrice(Per MMBtu)			Fair Value (in thousands)
	Three Months Ended June 30,							Six Months Ended June 30,
Third Quarter 2004	30,000		$	5.13		$	(2,826	)
	2005			2004				2005			2004
Fourth Quarter 2004	8,370			4.92			(1,100	)
Net income	$	23,204		$	17,605			$	34,465		$	31,342
First Quarter 2005	5,000			7.05			144
Other comprehensive income (loss), net of tax:
Total						$	(3,782	)
Net change in fair value of derivative financial instruments		1,193			(943	)			(9,667	)		(3,305	)
Financial derivative settlements reclassified to income		2,407			2,102				2,023			989
Comprehensive income	$	26,804		$	18,764			$	26,821		$	29,026

In a collar arrangement, the counterparty is required to make a payment to the Company for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price9. ~~The~~Impairment ~~Company~~of isInternational ~~required to make a payment to~~Oil ~~the counterparty for the difference between the fixed ceiling price~~ and ~~the~~Gas ~~settlement~~Properties price if the settlement price is above the fixed ceiling price. Neither party is required to make a payment if the settlement price falls between the fixed floor and ceiling price. As of June 30, 2004, Spinnaker’s commodity price risk management positions in natural gas collar arrangements and related fair values were as follows:

Period	AverageDaily Volume(MMBtus)	WeightedAverageCeiling Price(Per MMBtu)		WeightedAverageFloor Price(Per MMBtu)		Fair Value (in thousands)
Third Quarter 2004	20,000	$	5.48	$	4.38	$	(1,413	)
Fourth Quarter 2004	18,370		6.56		4.73		(1,124	)
Total						$	(2,537	)

The Company recorded an impairment charge of $0.7 million and $8.5 million in the three and six months ended June 30, 2005, respectively, as a result of an unsuccessful well in its West African venture. The transfer of the 12.5% interest to the Company is still pending various approvals within the Nigerian government.

10. Subsequent Event

Effective July 21, 2005, Spinnaker consummated a sale-leaseback transaction under which the Company sold its 25% undivided interest in the Front Runner spar production facility for $75.0 million. This lease has an initial 12-year term that expires on July 21, 2017 and has a full-term effective interest rate of 3.6%. The lease includes a fixed-price early buy-out option exercisable by Spinnaker in year seven of the lease term. The effective interest rate for the seven-year term is 6.4%. The lease also grants the Company an option to purchase the spar production facility at fair market value at the end of the lease term. The Company will make quarterly rental payments over the term of the lease based upon a fixed payment schedule set forth in the lease.

Spinnaker issued a guaranty, also effective July 21, 2005, guaranteeing the rental payments and other obligations. The guaranty is limited to the payments as they become due. The Company must also comply with certain on-going financial and operating covenants related to Front Runner.

Spinnaker used the $75.0 million proceeds from the sale-leaseback transaction to pay outstanding borrowings under the Revolver on July 21, 2005. In connection with the transaction, the $50.0 million Tranche B commitment under the Revolver was terminated on July 21, 2005, and a letter of credit in the amount of $15.0 million was issued under the Revolver.

~~The Company reported net liabilities of $6.3 million and $2.7 million related to its financial derivative~~ ~~contracts~~Cautionary asStatement ofAbout ~~June~~Forward-Looking ~~30,~~Statements ~~2004 and December 31, 2003, respectively. Amounts related to hedging activities were as follows (in thousands):~~

	As ofJune 30,2004			As ofDecember 31,2003
Current assets:
Hedging assets	$	—		$	203
Deferred tax asset related to hedging activities	$	2,275		$	972
Current liabilities:
Hedging liabilities	$	6,319		$	2,903
Equity:
Accumulated other comprehensive loss	$	(4,044	)	$	(1,728	)

In this quarterly report on Form 10-Q (“Quarterly Report”), unless the context requires otherwise, when we refer to “Spinnaker,” the “Company,” “we,” “us” or “our” we are describing Spinnaker Exploration Company and its subsidiaries.

~~The~~Some ~~Company~~of ~~recognized no~~the ~~ineffective~~information ~~component~~in ofthis Quarterly Report contains forward-looking statements within the ~~derivatives~~meaning inof Section 27A of the ~~three~~Securities Act of 1933, as amended, and ~~six~~Section ~~months~~21E ~~ended~~of ~~June~~the 30Securities Exchange Act of 1934, as ~~2004~~amended ~~and~~(the ~~2003~~“Exchange Act”). ~~The~~These ~~Company~~forward-looking ~~recognized~~statements amay ~~net~~be ~~hedging~~identified ~~loss~~by inthe ~~revenues~~use inof the ~~three~~words ~~and~~“anticipate,” ~~six~~“believe,” ~~months~~“contemplate,” ~~ended~~“estimate,” ~~June~~“expect,” 30“may,” “plan,” ~~2004~~“will,” “would” and ~~2003~~similar asexpressions ~~follows~~that (contemplate future events. Forward-looking statements include all statements under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and elsewhere in ~~thousands)~~this Quarterly Report involving the discussion of the following:

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Net hedging loss	$	(3,285	)	$	(9,167	)	$	(1,546	)	$	(26,910	)

•

financial position;

~~Based~~• onbusiness future natural gas prices as of June 30, 2004, the Company would reclassify a net loss of $6.4 million from accumulated other comprehensive loss to earnings in the remainder of 2004 and a gain of $0.1 million from accumulated other comprehensive loss to earnings in the first quarter of 2005. The amounts ultimately reclassified into earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement. strategy;

7.• ~~Comprehensive Income~~ budgets;

~~The~~• ~~following~~amount, ~~are~~nature ~~components~~and timing of ~~comprehensive~~capital ~~income~~expenditures, ~~(in~~including ~~thousands):~~future development costs;

	Three Months Ended June 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Net income	$	17,605		$	10,028		$	31,342		$	25,326
Other comprehensive income (loss), net of tax:
Net change in fair value of derivative financial instruments		(943	)		(3,102	)		(3,305	)		(16,780	)
Financial derivative settlements reclassified to income		2,102			5,867			989			17,222
Comprehensive income	$	18,764		$	12,793		$	29,026		$	25,768

•

drilling of wells;

•

oil and gas reserves;

•

timing and amount of future production of oil and gas;

•

marketing of oil and gas;

•

operating costs and other expenses;

•

cash flow and anticipated liquidity; and

•

prospect development and property acquisitions.

Although we believe that these forward-looking statements are based on reasonable assumptions, our expectations may not occur and we cannot provide assurance that the anticipated future operating results will meet our expectations or be achieved. Numerous factors, risks and uncertainties could cause our actual future results to differ materially from the results implied by these or other forward-looking statements made by us or on our behalf. These factors include, among other things:

•

the risks associated with exploration;

•

delays in anticipated production start-up dates;

•

shut-ins of production for platform, pipeline and facility maintenance, additions and removals;

•

potential mechanical failure or under-performance of significant wells;

•

the relatively short production lives of certain properties;

•

the concentration of production and reserves in a small number of properties;

•

maturity of the Gulf of Mexico shelf;

•

oil and gas price volatility;

•

our hedging activities;

•

our ability to find, replace, develop and acquire oil and gas reserves;

•

uncertainties in the estimation of proved reserves and in the projection of future rates of production and the timing and amount of development expenditures;

•

downward revisions of proved reserves and the related negative impact on the depreciation, depletion and amortization (“DD&A”) rate;

•

write-downs of oil and gas properties if oil and gas prices decline, proved reserves are revised downward or our finding and development costs continue to increase;

•

operating hazards attendant to the oil and gas business;

•

drilling and completion risks, which costs are generally not recoverable from third parties or insurance;

•

weather risks and natural disasters;

•

availability and cost of material and equipment;

•

actions or inactions of third-party operators of our properties;

•

risks inherent in international operations;

•

our ability to find and retain skilled personnel;

•

availability of capital;

•

the strength and financial resources of competitors and customers;

•

regulatory developments;

•

environmental risks; and

•

general economic conditions.

For additional discussion of these and other factors, risks and uncertainties, see “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in this Quarterly Report. You should pay particular attention to the risk factors and cautionary statements described in our annual report on Form 10-K for the year ended December 31, 2004. The forward-looking statements speak only as of the date made, and we undertake no obligation to update such forward-looking statements.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Overview

Our primary objective since inception has been to assemble a large 3-D seismic database and focus on exploration activities ~~exclusively~~ in the Gulf of Mexico ~~because~~ because we believe that this area represents one of the most attractive exploration regions in North America. We also believe that a geographic focus provides an excellent opportunity to develop and maintain competitive advantages through our regional exploration and operating expertise. We try to maintain balance and diversity in our exploration approach by drilling both shallow water and deepwater prospects, ranging from lower-risk prospects to higher-risk, higher-potential prospects. We have also evaluated onshore and offshore opportunities outside the Gulf of Mexico in the past. In order to diversify our operations and apply our skill set to other opportunities, we entered into a farm-out agreement in December 2004 covering a 12.5% interest in OPL Block 256 offshore Nigeria from Devon Energy Corporation (“Devon”). The transfer of interest is pending various approvals within the Nigerian government. This opportunity gives us exposure to a large acreage position that contains multiple prospects in a prolific basin. We expect our capital requirements for exploratory activities in connection with this venture to be approximately $50 million to $60 million over a two to three year period. The first well offshore Nigeria was determined to be unsuccessful in April 2005. As a result, we recorded an $8.5 million pre-tax impairment charge related to our international oil and gas properties in the first six months of 2005. We have a commitment to drill a minimum of two additional exploratory wells on OPL Block 256, including one well we expect to drill later this year.

WeSecond ~~recognized net income of $17.6 million, or $0.51 per diluted share, in the second~~ quarter of2005 ~~2004 compared to net income of $10.0 million, or $0.30 per diluted share, in the second quarter of 2003. These~~ financial ~~results were impacted by 11% higher production~~ and ~~a 30% higher realized commodity price in the second quarter of 2004 compared to the second quarter of 2003. Our lease~~ operating ~~expense~~highlights ~~(“LOE”)~~were rate per Mcfe in the second quarter of 2004 increased 14% to $0.48 compared to the same period in 2003, primarily due to higher LOE rates on new wells. The depreciation, depletion and amortization (“DD&A”) expense rate per Mcfe increased 17% in the second quarter of 2004 to $2.97 compared to the same period in 2003 primarily due to costs associated with unsuccessful drilling operations, higher finding costs and the timing of reserve recognition, as ~~more~~follows: reservoir and production information becomes available, compared to the related amortized costs. Of the total increase in the DD&A rate from the first quarter of 2004, $0.12 per Mcfe resulted from the retraction of royalty suspension volumes of 2.4 million barrels of oil (“MMBbls”), or 14.3 Bcfe, on Green Canyon 338/339/382 (“Front Runner”).

We• ~~had~~Net ~~$16.0~~income ~~million~~was ~~in cash and cash equivalents and outstanding borrowings under the Revolver of~~ $9323.02 million ~~as of June 30~~, ~~2004.~~or ~~We have experienced and expect to continue to experience substantial capital requirements. We have incurred capital costs of approximately~~ $1.0.66 ~~billion~~per indiluted ~~the past three years. Additionally~~share, we ~~have~~up ~~had~~31% ~~negative~~from ~~working~~second ~~capital~~quarter at2004 ~~the~~net ~~end~~income of ~~each of the last three years. Our working capital deficit decreased to~~ $517.56 million ~~as of June 30~~, ~~2004~~or ~~compared to~~ $~~33.2 million as of December 31, 2003. We have capital expenditure plans for 2004 totaling approximately $270.~~0 ~~million~~.51 Weper ~~believe~~diluted that cash flows from operations, proceeds from available borrowings under the Revolver and Front Runner spar production facility financing opportunities will be sufficient to meet our capital requirements in the next twelve monthsshare.

~~Although~~• weRevenues ~~have~~were ~~been able~~$92.0 tomillion, ~~maintain~~up ~~a drilling success rate of approximately 60~~15% ~~since~~from ~~inception,~~second ~~our~~quarter ~~exploratory~~2004 ~~drilling~~revenues ~~successes on the shelf and deep shelf since the second half~~ of ~~2001~~$79.8 ~~have~~million, ~~been smaller in size~~ and ~~had~~were ~~less~~primarily ~~impact~~impacted onby ~~our operating results than those prior to that time, resulting in~~ a ~~negative~~19% ~~impact~~increase ~~on our subsequent production and reserve growth. Additionally, several of our discoveries since mid-2001 were~~ in the ~~deep~~average ~~water~~commodity price, ~~and~~partially weoffset doby ~~not expect to see~~ the ~~full~~ impact onof ~~production~~a ~~and reserve~~4% ~~recognition~~decrease ~~from~~in ~~these projects until after 2004~~production.

• Production was 13.0 Bcfe, down 4% from second quarter 2004 production of 13.6 Bcfe. Oil revenues increased 95% as a result of a 46% increase in oil production and a 34% increase in the average oil price, and natural gas revenues decreased 18% as a result of a 26% decrease in natural gas production, partially offset by an 11% increase in the average natural gas price.

~~Since~~• ~~inception,~~Proved ~~approximately~~oil ~~90% of~~and ~~our total production has consisted of natural~~ gas. ~~Approximately~~reserves ~~74%~~were ~~of our total production in the second quarter of 2004 was natural gas~~373.3 ~~Considering oil and condensate production from deepwater projects in 2004 and 2005~~Bcfe, weup ~~anticipate that this concentration in natural gas production will be approximately 75~~22% offrom ~~total~~year-end ~~production in~~ 2004 ~~and~~proved ~~approximately~~reserves ~~50%~~ of ~~total production in 2005~~306.7 ~~As a result, we believe our revenues, profitability and cash flows will be less sensitive to natural gas prices and more sensitive to oil and condensate prices~~Bcfe.

~~Generally,~~We ~~our~~had ~~producing~~$7.8 ~~properties~~million onin cash and cash equivalents and outstanding borrowings of $105.0 million under the ~~shelf~~Revolver as of June 30, 2005. We have ~~high~~experienced ~~initial~~and ~~production~~expect ~~rates~~to ~~followed~~continue byto ~~steep~~experience ~~declines~~substantial capital requirements. AsWe aincurred ~~result,~~capital wecosts ~~must~~of ~~continually~~approximately ~~drill~~$175.5 ~~for~~million ~~and~~in ~~develop~~the ~~new~~first ~~oil~~six ~~and~~months ~~gas~~of ~~reserves~~2005, toincluding ~~replace~~$84.2 ~~those~~million ~~being~~in ~~depleted~~the bysecond ~~production~~quarter. ~~Substantial~~Additionally, we have had negative working capital ~~expenditures~~at ~~are~~the ~~required~~end toof ~~find~~each ~~and~~of ~~develop~~the ~~these~~past ~~reserves~~four years. ~~Our~~Excluding ~~challenge~~current isdeferred totax ~~find~~assets ~~and~~of ~~develop~~$42.0 ~~reserves~~million, atour ~~economic~~working ~~rates~~capital ~~and~~deficit ~~commence~~was ~~production~~$37.2 million as of ~~these~~June ~~reserves~~30, 2005 compared to a deficit of $13.5 million as ~~quickly~~of December 31, 2004. We have capital expenditure plans for 2005 totaling approximately $310.0 million. We believe that cash flows from operations and ~~efficiently~~proceeds asfrom ~~possible~~available borrowings under the Revolver will be sufficient to meet our capital requirements in the next twelve months.

~~Oil~~Although we have been able to maintain a drilling success rate of approximately 60% since inception, our exploratory drilling successes on the shelf and ~~Gas~~deep ~~Property~~shelf ~~Costs~~since the second half of 2001 were smaller and had less impact on our operating results than those prior to that time, resulting in a negative impact on our subsequent production and reserve growth and an increase in our DD&A rate per Mcfe through March 31, 2005. Additionally, several of our discoveries since mid-2001 were in the deep water where longer lead times are required before first production. In particular, we had our first discovery at Front Runner in early 2001 and production commenced in December 2004. Proved reserve additions in the second quarter of 2005 contributed to a 22% increase in reserves from year-end 2001 and an 8% decrease in the second quarter 2005 DD&A rate compared to the first quarter 2005 DD&A rate.

Spinnaker participated in three successful wells in six attempts in the second quarter of 2004. Property and equipment additions of $68.1 million in the second quarter of 2004 included leasehold and other acquisition costs of approximately $9.9 million, exploration costs of $39.0 million, development costs of $19.0 million and other property and equipment costs of $0.2 million. We currently plan to drill approximately 12 wells on the shelf and 8 wells in the deep water in the second half of 2004. We expect more than 50% of our 2004 capital expenditure budget to be used for exploration activities, up from 34% in 2003.

Production

Since inception, 86% of our total production has been natural gas and related natural gas liquids, including 61% in the second quarter of 2005. Oil production increased 46% in the second quarter of 2005 compared to the second quarter of 2004 primarily due to production at Front Runner. Five additional wells will be completed at the Front Runner spar production facility as ramp-up activities continue. Considering the oil and condensate production from deepwater projects in 2005, we anticipate that the historical concentration in natural gas production will decrease to approximately one-half of total production by year-end 2005. As a result, our revenues, profitability and cash flows will be less sensitive to natural gas prices and more sensitive to oil prices.

Generally, our producing properties on the shelf have high initial production rates followed by steep declines. As a result, we must continually drill for and develop new oil and gas reserves on the shelf and in deep water to replace those being depleted by production. Substantial capital expenditures are required to find and develop these reserves. Our challenge is to find and develop reserves at economic rates and commence production of these reserves as quickly and efficiently as possible. Our near-term production growth is dependent upon the success of our shelf drilling activities since large deepwater development projects require significantly more time before production commences.

Drilling Activities and Oil and Gas Property Costs

From inception through June 30, 2005, we participated in drilling 183 wells in the Gulf of Mexico resulting in 109 discoveries. Historically, most of the wells we drilled were on the shelf. However, we are transitioning to more deepwater operations. Prior to 2001, we drilled nine deepwater wells, three of which were successful. Since 2001 and through June 30, 2005, we have drilled 35 deepwater wells, 23 of which were successful. Our most significant deepwater projects include oil discoveries at Front Runner and at Mississippi Canyon 734 (“Thunder Hawk”) and natural gas discoveries in the Eastern Gulf of Mexico at DeSoto Canyon Blocks 618/619/620/621 (“Eastern Gulf Project”) and at Mississippi Canyon 961 (“Q”). Front Runner commenced production in December 2004. The Eastern Gulf Project development plan is complete. Our fields, along with several other dedicated fields in the Eastern Gulf, will be developed via subsea tieback to a floating production facility located in Mississippi Canyon 920 that will be capable of processing 850 MMcf of natural gas per day. We own 10.6% of the processing rights associated with this facility and the export pipelines. We anticipate first production from the Eastern Gulf Project and Q in 2007. We are currently evaluating development options at Thunder Hawk.

We participated in two successful wells in four attempts in the second quarter of 2005. Capital costs incurred totaled $84.2 million in the second quarter of 2005, including approximately $22.4 million for leasehold and other acquisition activities, $37.4 million for exploration activities, $24.2 million for development activities and $0.2 million for acquisitions of other property and equipment.

Our current capital expenditure budget for 2005 is approximately $310.0 million, including $190.0 million for exploration activities and geological and geophysical expenditures, $75.0 million for development activities, $42.0 million for leasehold acquisitions and $3.0 million for other property and equipment. We currently plan to drill and evaluate 14 wells in the remainder of 2005, including nine wells on the Gulf of Mexico shelf, four wells in the deep water of the Gulf of Mexico and one additional deepwater well in West Africa. Exploration and development activities in deep water require significant capital commitments. If we experience continued success in our exploration efforts in 2005, currently budgeted capital requirements in 2005 may increase.

Finding and Development Costs

We believe that the DD&A rate is the best measure for evaluating finding and development costs per Mcfe since the rate generally considers all acquisition, exploration and development costs. The rate also considers any additional development costs associated with proved reserves, such as costs for drilling new wells, sidetracks and recompletions, which awe ~~company~~ will incur in the future to produce the oil and gas reserves and an estimate of the costs to abandon wells, platforms, facilities and pipelines after reservoirs are depleted. However, other factors must also be considered when relying on the DD&A rate as a measure for evaluating a company’s finding and development costs per Mcfe. In most cases, the total estimated resource of a reservoir is not usually proved with only one well, and the initial proved reserves are generally burdened with 100% of ~~all~~the ~~future~~ development costs. ~~The~~as ~~DD&A~~well ~~rate~~as ~~increases~~any ~~due~~future todevelopment costs. ~~incurred~~In ~~without~~addition, ~~related reserve additions and~~ the ~~timing~~costs of ~~reserve~~successful ~~recognition,~~wells asmay ~~more~~impact ~~reservoir~~the ~~and~~DD&A ~~production~~rate ~~information~~before ~~becomes~~associated ~~available,~~proved ~~compared to~~reserves ~~the~~are ~~related~~booked ~~amortized~~in ~~costs~~some instances.

The DD&A rate per Mcfe is calculated quarterly and increased 5% to $2.97 in the second quarter of 2004 from $2.82 in the first quarter of 2004. The increase in the DD&A rate was primarily due to the retraction of royalty suspension volumes of 2.4 MMBbls, or 14.3 Bcfe, on Front Runner.

Oil and Gas Reserves

We have achieved reserve growth through exploration activities. We have not acquired reserves through acquisition activities. Ryder Scott Company, L.P. (“Ryder Scott”) prepares estimates of our proved oil and gas reserves as of June 30 and December 31 each year. As of June 30, 2004, Ryder Scott estimated net proved reserves at approximately 319.0 Bcfe, with a present value, discounted at 10% per annum, of pre-tax future net cash flows of approximately $1.1 billion. The discovery of the Front Runner field in 2001 significantly changed our reserve profile. Proved oil and condensate reserves were 50% of total proved reserves as of June 30, 2004 compared to 10% as of December 31, 2000. Proved undeveloped reserves were approximately 64% of total proved reserves as of June 30, 2004. Reserves associated with Front Runner represented approximately 72% of total proved undeveloped reserves. As each Front Runner well is completed over the next 12 months, the majority of these proved undeveloped reserves will be reclassified as proved developed reserves.

Natural Gas and Oil Prices and Hedging Activities

Prices for natural gas and oil fluctuate widely, primarily affecting the amount of cash flow available for capital expenditures, our ability to borrow and raise additional capital and the amount of natural gas and oil that we can economically produce. Natural gas prices have been extremely volatile recently as a result of various factors, including weather, industrial demand and uncertainty related to the ability of the energy industry to provide supply to meet future demand.

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. However, these contracts also limit the benefits we would realize if prices increase. We recorded a net hedging loss of $3.3 million in the second quarter of 2004 compared to a net hedging loss of $9.2 million in the second quarter of 2003. The net hedging loss in the first six months of 2004 was $1.5 million compared to $26.9 million in the same period of 2003. Major challenges related to our hedging activities include a determination of the proper production volumes to hedge and acceptable commodity price levels for each hedge transaction.

Revenues, profitability, cash flow and future growth depend substantially on prevailing oil and gas prices and our ability to find and develop oil and gas reserves that are economically recoverable. A substantial or extended decline in the prices for oil and gas could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and ability to access capital.

The DD&A rate per Mcfe is calculated quarterly and increased 9% to $3.24 in the second quarter of 2005 from $2.97 in the second quarter of 2004. The DD&A rate decreased 8% in the second quarter of 2005 from $3.51 in the first quarter of 2005. Of the $0.27 decrease in the DD&A rate from the first quarter of 2005, approximately $0.31 related to three successful operations, offset in part by $0.04 related to increased future development and other costs.

Proved Oil and Gas Reserves

We have achieved reserve growth through exploration activities and have not acquired any reserves through acquisition activities. As of June 30, 2005, Ryder Scott Company, L.P. (“Ryder Scott”) estimated net proved reserves at approximately 373.3 Bcfe, with a present value of future net cash flows (before income taxes) of approximately $1.605 billion. Proved reserves were up 22% from the end of 2004. Oil and condensate reserves were 46% of total proved reserves, and proved undeveloped reserves were approximately 66% of total proved reserves as of June 30, 2005. Front Runner represented approximately 40% of our total proved undeveloped reserves. Our proved reserve additions in the first half of 2005 totaled approximately 91.4 Bcfe. For the first six months of 2005, we replaced 369% of production. Three fields, including Front Runner, Thunder Hawk and Q, comprise approximately 60% of our total proved reserves. Thunder Hawk and Q are in active development and are expected to commence production in 2007 or 2008.

Oil and Gas Prices and Hedging Activities

Oil and gas prices fluctuate widely, primarily affecting the amount of cash flow available for capital expenditures, our ability to borrow and raise additional capital and the amount of oil and gas that we can economically produce. Oil and gas prices have been extremely volatile recently as a result of various factors, including weather, industrial demand and uncertainty related to the ability of the energy industry to provide supply to meet future demand. There are questions whether fundamentals support current prices.

We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in oil and gas prices and to achieve more predictable cash flow. However, these contracts limit the benefits we would realize if prices increase. We recorded net hedging losses of $3.7 million and $3.3 million in the second quarter of 2005 and 2004, respectively, and net hedging losses of $3.1 million and $1.5 million in the first six months of 2005 and 2004, respectively. If oil and gas prices stabilize at current levels, we will incur additional hedging losses in the remainder of 2005. Major challenges related to our hedging activities include a determination of the proper production volumes to hedge and acceptable commodity price levels for each hedge transaction.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates include DD&A of proved oil and gas properties. Oil and gas reserve estimates, which are the basis for unit-of-production DD&A and the full cost ceiling test, are inherently imprecise and are expected to change as future information becomes available. In addition, alternatives may exist among various accounting methods. In such cases, the choice of accounting method may also have a significant impact on reported amounts. Our critical accounting policies are as follows:

Full Cost Method of Accounting

The accounting for oil and gas exploration and production is subject to special accounting rules that are specific to the industry. Two allowable methods exist for these activities: the successful efforts method and the full cost method. Several significant differences exist between the two methods. The major difference is under the successful efforts method, costs such as geological and geophysical, exploratory dry holes and delay rentals are expensed as incurred whereas under the full cost method, these types of charges are capitalized into the full cost amortization ~~pool~~base.

We use the full cost method of accounting for investments in oil and gas properties. Under this method, ~~all~~cost ~~acquisition,~~centers ~~exploration~~are ~~and~~established ~~development~~on ~~costs,~~a ~~including~~country-by-country ~~certain related employee costs~~basis, ~~incurred for the purpose of exploring for~~ and ~~developing~~all ~~oil and gas properties are capitalized. Acquisition costs include costs incurred to purchase~~acquisition, ~~lease~~exploration orand ~~otherwise~~development ~~acquire property. Exploration~~ costs ~~include the costs of drilling exploratory wells~~, including ~~those~~ incertain progress, geological and geophysical service costs and depreciation of support equipment used in exploration activities. Development costs include the costs of drilling development wells, completions, platforms, facilities, pipelines and the costs related to the retirement of these assets. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for ~~as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and gas reserves.~~

Application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs, no exploration expenses and higher DD&A rates than the application of the successful efforts method of accounting. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. As a result, we believe that the full cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas investments.

Oil and Gas Reserve Estimates

Ryder Scott prepares estimates of our proved oil and gas reserves as of June 30 and December 31 each year. These estimates of proved reserves are based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate, among others, the amount and timing of future production, operating, workover and transportation expenses and development and abandonment costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our oil and gas reserves.

The Minerals Management Service (“MMS”) allows royalty relief under the Deep Water Royalty Relief Act subject to certain oil and gas price thresholds on eligible leases in the Gulf of Mexico. If the average annual NYMEX oil and gas prices exceed the price thresholds, royalty suspension volumes are retracted in that year. Average natural gas and oil prices have exceeded these thresholds in recent years for certain leases. At or near current levels, average annual NYMEX oil and gas prices in 2004 may exceed these thresholds.

Front Runner area reserves are subject to royalty relief on the first 87.5 million equivalent barrels of oil produced. At the end of each period, reserves are estimated based on oil and gas prices then in effect. Prior to June 30, 2004, our share of gross Front Runner reserves excluded royalty relief volumes for future natural gas production and included royalty relief volumes for future oil production. The MMS has estimated a 2004 oil price threshold of $33.29 per barrel that is applicable to Green Canyon Blocks 338 and 339 and $29.86 per barrel that is applicable to Green Canyon Block 382. Based on the average oil price as of June 30, 2004, we believe the thresholds will be exceeded and the leases will not qualify for royalty relief. As a result, we incurred a downward reserve revision of approximately 2.4 million barrels, or 14.3 Bcfe, in the second quarter of 2004.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, we use the units-of-production method to amortize our oil and gas properties, and the quantity of reserves could significantly impact our DD&A rate and related expense. Our oil and gas properties are also subject to a ceiling limitation based in part on the quantity of our proved reserves. Finally, these proved reserves are the basis for our supplemental oil and gas disclosures included in our annual report on Form 10-K.

employee costs incurred for the purpose of exploring for and developing oil and gas properties, are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress, and geological and geophysical service costs. Development costs include the costs of drilling development wells, completions, platforms, facilities, pipelines and the costs related to the retirement of these assets. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas properties, whether or not being amortized currently, are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved oil and gas reserves.

Application of the full cost method of accounting for oil and gas properties generally results in higher capitalized costs, no exploration costs and higher DD&A rates than the application of the successful efforts method of accounting. Although some of these costs will ultimately result in no additional proved reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. As a result, we believe that the full cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas investments.

Since inception, we have had a single cost center for our U.S. Gulf of Mexico operations. In connection with our West African venture, we have a separate cost center for our Nigerian operations.

Proved Oil and Gas Reserve Estimates

Despite the inherent imprecision in these engineering estimates, our proved reserves are used throughout our financial statements. For example, we use the unit-of-production method to amortize our oil and gas properties and the quantity of proved reserves could significantly impact our DD&A rate and related expense. Our oil and gas properties are also subject to a ceiling limitation based in part on the quantity of our proved reserves. Finally, these proved reserves are the basis for our supplemental oil and gas disclosures.

Depreciation, Depletion & Amortization

~~Our~~ DD&A expense is comprised of many factors, including costs incurred in the acquisition, exploration and development of proved oil and gas reserves, production levels, estimates of proved reserve quantities and future development and abandonment costs. We compute the provision for DD&A of oil and gas properties on a quarterly basis using the unit-of-production method. The calculation is based ~~upon~~on quarterly production and estimates of proved ~~reserve quantities~~reserves. Unevaluated costs ~~and related carrying costs~~ are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs and dismantlement, restoration and abandonment costs and estimated salvage values of platforms and other equipment associated with future asset retirement obligations.

Certain future development costs may be excluded from amortization when incurred in connection with major development projects expected to entail significant costs to ascertain the quantities of proved reserves attributable to the properties under development. The amounts that may be excluded are portions of the costs that relate to the major development project and have not previously been included in the amortization base and the estimated future expenditures associated with the development project. Such costs may be excluded from costs to be amortized until the earlier determination of whether additional reserves are proved or impairment occurs.

As of June 30, ~~2004~~2005, we excluded from the amortization base estimated future expenditures of $2928.59 million associated with common development costs for ~~the~~our deepwater discovery at Front Runner. This estimate of future expenditures associated with common development costs is based on existing proved reserves to total proved reserves expected to be ~~established upon completion of the Front Runner project. If the $29.5 million had been included in the amortization~~ base as of June 30, 2004, and no additional reserves were assigned to the Front Runner project, the DD&A rate in the second quarter of 2004 would have been $3.06 per Mcfe, or an increase of $0.09 over the actual DD&A rate of $2.97 per Mcfe. All future development costs associated with the deepwater discovery at Front Runner are included in the determination of estimated future net cash flows from proved oil and gas reserves used in the full cost ceiling calculation, as discussed below.

established upon completion of the Front Runner project. If the $28.9 million had been included in the amortization base as of June 30, 2005, and no additional reserves were assigned to the Front Runner project, the DD&A rate would have been $3.31 per Mcfe, or an increase of $0.07 over the actual second quarter 2005 DD&A rate of $3.24 per Mcfe. All future development costs associated with the deepwater discovery at Front Runner are included in the determination of estimated future net cash flows from proved oil and gas reserves used in the full cost ceiling calculation.

Full Cost Ceiling

~~Capitalized~~Under ~~costs~~full ofcost ~~oil~~accounting ~~and~~rules, ~~gas~~total ~~properties,~~capitalized ~~net~~costs ofwithin ~~accumulated~~each ~~DD&A,~~of our ~~asset~~cost ~~retirement~~centers ~~obligations~~are ~~and~~limited ~~related~~to ~~deferred~~a ~~taxes,~~ceiling ~~are~~equal ~~limited~~ to the ~~estimated~~present value of future net cash flows from proved oil and gas reserves, ~~including~~located ~~the~~within ~~effects of hedging activities in place as of end of~~ the ~~quarter~~applicable region, discounted at 10% per annum, plus the lower of cost or fair value of unproved properties, less ~~as adjusted for related~~ income tax effects (the “ceiling limitation”). We perform a quarterly ceiling test to determine whether the net book value of our full cost amortization base within each of our cost centers exceeds the ceiling) limitation. If capitalized costs, net of ~~the~~accumulated ~~full~~DD&A, ~~cost~~less ~~pool~~related ~~exceed~~deferred taxes are greater than the ceiling limitation, a write-down or impairment of the ~~excess~~full cost amortization base is ~~charged~~required. toA write-down of the carrying value of oil and gas properties is a non-cash charge that reduces earnings and typically results in lower DD&A expense in future periods.

AsIn ofaccordance ~~June~~with ~~30,~~Commission ~~2004~~guidelines, ~~Spinnaker’s~~we ~~full~~include ~~cost ceiling, including~~ estimated future ~~net~~ cash flows ~~calculated~~from ~~using~~our ~~commodity~~hedging ~~prices~~program ofin ~~$6.45~~our ~~per~~ceiling ~~Mcf~~test ofcalculation. ~~natural~~In ~~gas~~addition, subsequent ~~and~~to ~~$32.95~~the ~~per~~adoption ~~barrel~~ of ~~oil~~SFAS ~~and~~No. ~~condensate~~143, ~~exceeded~~the ~~capitalized~~future ~~costs~~cash ofoutflows ~~oil~~associated ~~and~~with ~~gas~~the ~~properties,~~settlement ~~net~~ of ~~accumulated DD&A,~~ asset retirement obligations ~~and related~~are ~~deferred~~not ~~taxes,~~included byin ~~approximately $194.6 million. Considering~~ the ~~volatility~~computation of ~~natural~~the ~~gas~~discounted ~~and~~present ~~oil~~value ~~prices, it is probable that our estimate~~ of ~~discounted~~ future net cash flows ~~from~~for ~~proved oil and gas reserves will change in~~ the ~~near~~purposes ~~term. If natural gas or oil prices decline, even if for only a short period~~ of ~~time, if we incur significant costs associated with unsuccessful drilling operations or if we have downward revisions to our estimated proved reserves, it is possible that~~the ~~write-downs~~ceiling oftest ~~oil and gas properties could occur in the future~~calculation.

In calculating the ceiling test for our U.S. cost center as of June 30, 2005, we estimated a full cost ceiling “cushion” of $456.0 million, using prices of $7.11 per Mcf of natural gas, $52.32 per barrel of oil and $27.34 per barrel of natural gas liquids. Considering the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. Capitalized costs related to our operations in Nigeria are subject to a separate ceiling limitation as the costs are evaluated. If oil and gas prices decline, even if for only a short period of time, if we incur significant costs associated with unsuccessful drilling operations or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.

Unproved Properties

The costs associated with unproved properties and properties under development are not initially included in the amortization base and primarily relate to unevaluated leasehold ~~acreage~~costs, ~~and~~ delay rentals, ~~seismic~~geological ~~data, wells in-progress~~ and ~~wells~~geophysical ~~pending determination. Unevaluated leasehold~~ costs, and delay rentals are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value. Unevaluated leasehold costs and delay rentals are transferred to the amortization base if a reduction in value has occurred. The costs of seismic data are transferred to the amortization base using the sum-of-the-year’s-digits method over a period of six years. The costs associated with wells in-progress and wells pending determination ~~are transferred to the amortization base once a determination is made whether or not proved reserves can be assigned to the property~~. ~~The costs of drilling exploratory dry holes and associated leasehold costs are included in the amortization base immediately upon determination that the well is unsuccessful.~~

15Geological and geophysical costs, including 3-D seismic data costs and related seismic hardware and software costs, are included in the full cost amortization base as incurred when such costs cannot be associated with specific unevaluated properties for which we own a direct interest. Seismic data costs are associated with specific unevaluated properties if the seismic data may be used to evaluate acreage that is covered by a leasehold interest owned by Spinnaker. We make this determination based on an analysis of leasehold and seismic maps and discussions with our management and exploration managers. Seismic hardware and software costs are associated with specific unevaluated properties if the hardware and software was acquired specifically to process or reprocess certain 3-D seismic data that covers an area or trend containing a leasehold interest owned by Spinnaker. We make this determination based on discussions with our management and information technology and seismic processing specialists. When such seismic data, hardware and software costs can be associated with specific unevaluated properties and excluded from the full cost amortization base, we allocate the costs based on management’s judgment of the potential economic value to be realized upon determination of whether or not proved reserves can be assigned to the properties. Significant assumptions used by management in determining the potential economic value of an owned leasehold interest include the number of successful and unsuccessful wells drilled within and around the lease and trend, the number of prospects on the lease and the size of the potential resource associated with the lease.

Unevaluated leasehold costs, delay rentals and geological and geophysical costs associated with specific properties are transferred to the amortization base either upon determination of whether or not proved reserves can be assigned to the properties or if impairment has occurred. The costs of drilling exploratory dry holes are transferred to the amortization base immediately upon determination that the well is unsuccessful. The costs associated with wells in-progress and wells pending determination are transferred to the amortization base upon determination of whether or not proved reserves can be assigned to the properties.

Leasehold Costs

In ~~June~~September ~~2001~~2004, the FASB issued ~~SFAS~~FASB ~~No.~~Staff ~~141,~~Position (“~~Business Combinations,~~FSP”) ~~which~~No. ~~requires~~FAS ~~the use of the purchase method of accounting for business combinations initiated after June 30~~142-2, ~~2001~~“Application ~~and eliminates the pooling-~~of~~-interests~~ ~~method. In July 2001, the~~ FASB ~~also issued SFAS~~ Statement No. 142, “Goodwill and Other Intangible Assets,” ~~which~~to ~~discontinues~~Oil ~~the practice of amortizing goodwill~~ and ~~indefinite~~Gas ~~lived~~Producing ~~intangible~~Entities.” ~~assets~~This ~~and~~FSP ~~initiates~~confirms anthat ~~annual~~SFAS ~~review of impairment~~No. ~~The~~142 ~~new~~did ~~standard~~not ~~also~~change ~~requires~~the ~~that,~~balance atsheet aclassification ~~minimum,~~or ~~all~~disclosure ~~intangible~~requirements ~~assets~~for bedrilling ~~aggregated~~ and ~~presented~~mineral asrights aof ~~separate~~oil ~~line~~and ~~item~~gas producing inentities. ~~the~~We ~~balance sheet.~~classify ~~The~~the ~~adoption~~costs of ~~SFAS~~oil ~~No. 141~~ and ~~142~~gas ~~had~~drilling noand ~~impact~~mineral onrights ~~Spinnaker’s~~as ~~financial~~property ~~position~~and ~~or results of operations~~equipment.

A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 141 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, we and the extractive industries have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 141 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $85.8 million and $72.2 million as of June 30, 2004 and December 31, 2003, respectively, from oil and gas properties to a separate intangible assets line item. These costs include those to acquire contract-based drilling and mineral use rights such as delay rentals, lease bonuses, commission fees and other leasehold costs. Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. Spinnaker will continue to classify its oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided.

Asset Retirement Obligations

We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the asset. The fair value of a liability for an asset retirement obligation is the amount which that liability could be settled in a current transaction between willing parties. We use the expected cash flow approach for calculating asset retirement obligations. The liability is discounted using the credit-adjusted risk-free interest rate in effect when the liability is initially recognized. The changes in the liability for an asset retirement obligation due to the passage of time are measured by applying an interest method of allocation to the amount of the liability at the beginning of the period. This amount is recognized as an increase in the carrying amount of the liability and as accretion expense classified as an operating item in the statement of operations.

Financial Instruments and Price Risk Management Activities

As of June 30, ~~2004~~2005, our financial instruments consisted of cash and cash equivalents, receivables, payables and derivative instruments. The carrying amounts of cash and cash equivalents, receivables and payables approximate fair value because of the short-term nature of these items. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in ~~natural~~oil ~~gas~~ and ~~oil~~gas prices and to achieve more predictable cash flow. These hedging arrangements take the form of swap contracts or cashless collars and are placed with major ~~financial~~trading ~~institutions~~counterparties. ~~We recorded a net hedging loss of $3.3 million and a net hedging loss of $1.5 million in the three and six months ended June 30, 2004, respectively.~~

Stock-Based Compensation

SFAS No. 148, ~~“Accounting for Stock-Based Compensation – Transition and Disclosure,”~~ amends SFAS No. 123 to provide alternative methods of transition for an entity that voluntarily changes to the fair value based method of accounting for stock-based employee compensation and to require prominent disclosure about the effects on reported net income of an entity’s accounting policy decisions with respect to stock-based employee compensation. SFAS No. 148 amends APB Opinion No. 28, ~~“Interim Financial Reporting,”~~ to require disclosure about those effects in interim financial information.

SFAS No. 123, “Accounting for Stock-Based Compensation,” encourages, but does not require, companies to record compensation cost for stock-based employee compensation plans at fair value. We ~~have~~elected ~~chosen~~ to account for stock-based compensation using the intrinsic value method prescribed in APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. Accordingly, compensation cost for stock options is measured as the excess, if any, of the fair value of the Common Stock at the date of the grant over the amount an employee must pay to acquire the Common Stock. In accordance with APB Opinion No. 25, compensation expense related to stock-based compensation was $0.2 million and $0 in the second quarter of 2004 and 2003, respectively, and $0.2 million and $0 in the first six months of 2004 and 2003, respectively. For further information concerning SFAS 123 see Note 2 of the Notes to Consolidated Financial Statements.

On December 16, 2004, the FASB revised SFAS No. 123 that will require compensation costs related to share-based payment transactions to be recognized in the financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity or liability instruments issued. In addition, liability awards will be remeasured each reporting period. Compensation cost will be recognized over the period that an employee provides service in exchange for the award. SFAS No. 123(R) replaces SFAS No. 123 and supersedes APB Opinion No. 25. Adoption of SFAS No. 123R will require us to recognize compensation expense for all awards we grant after the date of adoption and for the unvested portion of all options granted that remain outstanding on the date of adoption.

On April 14, 2005, the Commission announced that it would permit additional time to implement the requirements in SFAS No. 123R. As originally issued by the FASB, public companies were required to implement SFAS No. 123R as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Commission will permit companies to implement SFAS No. 123R at the beginning of their next fiscal year, instead of the next reporting period beginning after June 15, 2005 as required by SFAS No. 123R. The Commission is not changing any of the accounting requirements in SFAS No. 123R. We will be required to implement SFAS No. 123R as of January 1, 2006. All options that we granted prior to December 31, 2001 will be fully vested prior to adoption of SFAS No. 123R and will not be considered as part of the adoption in accordance with the new standard. We are currently evaluating the effect of adopting SFAS No. 123R.

Related Parties

We purchase oilfield goods, equipment and services from ~~Baker Hughes Incorporated (“Baker Hughes”),~~ Cooper Cameron Corporation (“Cooper Cameron”), and National-Oilwell Varco, Inc. (“National-Oilwell”) and other oilfield services companies in the ordinary course of business. ~~Spinnaker~~We incurred charges of $6.4 million in the first six months of 2004 from affiliates of Baker Hughes. Mr. Michael E. Wiley, a director of Spinnaker, serves as Chairman of the Board and Chief Executive Officer of Baker Hughes. Spinnaker incurred charges of less than $0.1 million in the first six months of ~~2004~~2005 from Cooper Cameron. Mr. Sheldon R. Erikson, a director of Spinnaker, serves as Chairman of the Board, Chief Executive Officer and President of Cooper Cameron. ~~Spinnaker~~We incurred charges of less than $0.1 million in the first six months of ~~2004~~2005 from National-Oilwell. Mr. Roger L. Jarvis, Chairman of the Board, Chief Executive Officer and President of Spinnaker, serves as a director of National-Oilwell. These amounts represent less than 1% of ~~Baker Hughes’,~~ Cooper Cameron’s and National-Oilwell’s total revenues in the first six months ~~ended~~of 2005 ~~June 30, 2004~~ and only reflect charges directly incurred by us. Our partners may incur charges from these related parties that are not included above.

We believe that these transactions are at arm’s-length and the charges we pay for such goods, equipment and services are competitive with the charges and fees of other companies providing oilfield goods, equipment and services to the oil and gas exploration and production industry. Each of these companies is a leader in ~~their~~its respective segments of the oilfield services sector. ~~Spinnaker~~We could be at a disadvantage if itwe were to discontinue using these companies as vendors.

~~Oil~~New ~~and~~Accounting ~~Gas~~Pronouncements ~~Reserves~~

~~The~~On ~~following~~December ~~table~~16, ~~presents~~2004, ~~estimated~~the ~~net~~FASB ~~proved~~issued ~~oil~~SFAS ~~and~~No. ~~gas~~153, ~~reserves~~“Exchanges ~~and~~of Nonmonetary Assets,” an amendment of APB Opinion No. 29, to clarify the ~~related~~accounting ~~present~~for nonmonetary exchanges of similar productive assets. SFAS No. 153 eliminates the exception from the fair value measurement for nonmonetary exchanges of ~~future~~similar ~~net~~productive assets and replaces it with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the ~~reserves~~entity asare ofexpected ~~June 30,~~to ~~2004~~change significantly as ~~prepared~~a byresult ~~Ryder~~of ~~Scott~~the exchange. ~~The~~SFAS ~~present~~No. ~~value~~153 ofwill ~~future~~be ~~net~~applied ~~cash~~prospectively ~~flows~~and ~~(before~~is ~~income~~effective ~~taxes)~~for ~~discounted~~nonmonetary atasset ~~10%~~exchanges ~~shown~~occurring in ~~the~~fiscal ~~table~~periods beginning ~~are~~after ~~not~~June ~~intended~~15, to2005. ~~represent~~We ~~the~~do ~~current~~not ~~market~~expect ~~value~~the adoption of ~~the~~SFAS ~~estimated~~No. ~~oil~~153 ~~and~~to ~~gas~~have ~~reserves~~a wematerial ~~own~~impact on our consolidated financial statements.

~~The~~Proved ~~present~~Oil ~~value of future net cash flows as of June 30, 2004 was determined by using prices of $6.45 per Mcf of natural gas~~ and ~~$32.95~~Gas ~~per~~Reserves ~~barrel of oil as of June 30, 2004.~~

	Proved Reserves
	Developed		Undeveloped		Total
Natural gas (MMcf)		81,157		77,893		159,050
Oil and condensate (MBbls)		5,538		21,115		26,653
Total proved reserves (MMcfe)		114,386		204,583		318,969
Present value of future net cash flows (before income taxes) discounted at 10% (in thousands) (1)	$	491,693	$	614,138	$	1,105,831

The following table presents estimated net proved oil and gas reserves and the related net present value of the reserves as of June 30, 2005 as prepared by Ryder Scott. The present value of future net cash flows (before income taxes) discounted at 10% shown in the table is not intended to represent the current market value of the estimated oil and gas reserves we own.

~~(1)~~The ~~Excludes~~present value of future net ~~pre-tax~~cash ~~unrealized~~flows ~~losses~~as of ~~$6.3~~June ~~million~~30, ~~for~~2005 ~~the~~was ~~effects~~determined using prices of ~~hedging~~$7.11 ~~activities~~per ~~using~~Mcf of natural gas, ~~prices~~$52.32 inper ~~effect~~barrel of oil and $27.34 per barrel of natural gas liquids as of June 30, ~~2004~~2005.

The process of estimating oil and gas reserves is complex. Ryder Scott prepares our reserve estimates as of June 30 and December 31 each year. In order to assist in the preparation of these estimates, we must project production rates and timing of development expenditures. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds. Therefore, estimates of oil and gas reserves are inherently imprecise.


	Proved Reserves
	Developed		Undeveloped		Total
Natural gas (MMcf)		61,008		121,840		182,848
Oil and condensate (MBbls)		9,074		19,481		28,555
Natural gas liquids (MBbls)		1,710		1,473		3,183
Total proved reserves (MMcfe)		125,706		247,569		373,275
Present value of future net cash flows (before income taxes) discounted at 10% (in thousands)(1)	$	678,554	$	926,405	$	1,604,959

~~Actual~~(1) ~~future~~Excludes ~~production,~~a ~~oil~~net ~~and~~pre-tax ~~gas~~unrealized ~~prices,~~loss ~~revenues, taxes, development expenditures, operating expenses and quantities~~ of ~~recoverable oil and gas reserves most likely will vary from estimates~~$11.8 ~~Any~~million ~~significant~~for ~~variance could materially affect~~ the ~~estimated~~effects ~~quantities and net present value~~ of ~~reserves.~~hedging Inactivities ~~addition,~~using ~~we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing~~ oil and gas prices ~~and~~in ~~other~~effect ~~factors,~~as ~~many~~ of ~~which are beyond our control. As of~~ June 30, ~~2004, approximately 80% of our proved reserves were either undeveloped or non-producing~~2005. Because most of the reserve estimates are not based on a lengthy production history and are calculated using volumetric analysis, these estimates are less reliable than estimates based on a lengthy production history.

17The process of estimating oil and gas reserves is complex. Ryder Scott prepares our proved oil and gas reserve estimates as of June 30 and December 31 each year. In order to assist in the preparation of these estimates, we must project production rates and timing of development expenditures. We also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds. Therefore, estimates of oil and gas reserves are inherently imprecise.

AsActual offuture ~~June~~production, 30oil and gas prices, ~~2004~~revenues, ~~approximately~~taxes, ~~64%~~development expenditures, operating expenses and quantities of ~~our~~recoverable ~~proved~~oil and gas reserves ~~were~~most ~~undeveloped~~likely will vary from estimates. Any significant variance could materially affect the estimated quantities and ~~primarily~~net ~~related~~present ~~to Front~~value ~~Runner~~of reserves. ~~Recovery~~In ofaddition, ~~undeveloped~~we may adjust estimates of proved reserves ~~generally~~to ~~requires~~reflect ~~significant~~production ~~capital~~history, ~~expenditures~~results of exploration and ~~successful~~development, ~~drilling~~prevailing ~~operations.~~oil ~~The~~and ~~reserve~~gas ~~data~~prices ~~assumes~~and ~~that~~other wefactors, ~~will~~many ~~make~~of ~~these~~which ~~expenditures~~are beyond our control. ~~Although~~As ~~the~~of ~~estimates~~June 30, 2005, approximately 85% of our proved reserves ~~and~~were ~~the~~either ~~costs~~undeveloped ~~associated~~or ~~with~~non-producing. ~~developing~~Because ~~them~~most of the reserve estimates are ~~prepared~~not inbased ~~accordance~~on ~~with~~a ~~industry~~lengthy ~~standards,~~production ~~the~~history ~~estimated~~and ~~costs~~are ~~may~~calculated beusing ~~inaccurate~~volumetric analysis, ~~development~~these ~~may~~estimates ~~not~~are ~~occur~~less asreliable ~~scheduled~~than ~~and~~estimates ~~the~~based ~~results~~on ~~may~~a ~~not~~lengthy beproduction ~~as estimated~~history.

ItAs ~~should~~of ~~not~~June be30, ~~assumed~~2005, ~~that~~approximately ~~the~~66% ~~present~~of ~~value~~our ofproved ~~future~~oil ~~net~~and gas ~~cash~~reserves ~~flows~~were ~~from~~ undeveloped and primarily related to Front Runner, Thunder Hawk and Q. We anticipate that a large percentage of our proved undeveloped reserves isat ~~the~~Front ~~current~~Runner, ~~market~~although ~~value~~not ofall, ~~our~~will ~~estimated~~be ~~oil~~re-categorized ~~and~~as ~~gas~~proved developed reserves. as Inadditional ~~accordance~~wells ~~with~~in ~~Securities~~the ~~and~~Front ~~Exchange~~Runner ~~Commission~~field ~~requirements,~~are wecompleted ~~base~~and ~~the~~commence ~~estimated~~production ~~discounted~~in ~~future~~2005 ~~net~~and ~~cash~~2006. ~~flows~~Recovery ~~from~~of ~~proved~~undeveloped reserves ongenerally ~~prices~~requires significant capital expenditures and successful drilling operations. The reserve data assumes ~~costs~~that onwe ~~the~~will ~~date~~make ofthese ~~the~~capital ~~estimate~~expenditures. ~~Actual~~Although ~~future~~we ~~prices~~estimate our reserves and the costs ~~may~~associated ~~differ~~with ~~materially~~developing ~~from~~them ~~those~~in ~~used~~accordance inwith industry standards, the ~~present~~estimated ~~value~~costs ofmay ~~future~~be ~~net~~inaccurate, ~~cash~~development ~~flows~~may ~~estimate~~not occur as scheduled and results may not be as estimated.

It should not be assumed that the present value of future net cash flows from our proved reserves is the current market value of our estimated oil and gas reserves. In accordance with Commission requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value of future net cash flows estimate.

Results of Operations

	Three Months Ended June 30,								Six Months Ended June 30,
	2004			2003			% Change		2004			2003			% Change
Production:
Natural gas (MMcf)		10,118			10,206		(1	)%		18,421			21,791		(15	)%
Oil and condensate (MBbls)		582			343		70	%		914			695		32	%
Total (MMcfe)		13,611			12,264		11	%		23,906			25,963		(8	)%
Revenues (in thousands):
Natural gas	$	62,157		$	54,706		14	%	$	108,379		$	132,194		(18	)%
Oil and condensate		21,311			9,909		115	%		32,858			21,984		49	%
Net hedging income (loss)		(3,285	)		(9,167	)	64	%		(1,546	)		(26,910	)	94	%
Other		(359	)		483		(174	)%		(76	)		334		(123	)%
Total	$	79,824		$	55,931		43	%	$	139,615		$	127,602		9	%
Average realized sales price per unit:
Natural gas revenues from production (per Mcf)	$	6.14		$	5.36		15	%	$	5.88		$	6.07		(3	)%
Effects of hedging activities (per Mcf)		(0.32	)		(0.89	)	64	%		(0.08	)		(1.24	)	94	%
Average realized price (per Mcf)	$	5.82		$	4.47		30	%	$	5.80		$	4.83		20	%
Oil and condensate revenues from production (per Bbl)	$	36.61		$	28.89		27	%	$	35.95		$	31.62		14	%
Effects of hedging activities (per Bbl)		—			—		—			—			—		—
Average realized price (per Bbl)	$	36.61		$	28.89		27	%	$	35.95		$	31.62		14	%
Total revenues from production (per Mcfe)	$	6.13		$	5.27		16	%	$	5.91		$	5.94		(1	)%
Effects of hedging activities (per Mcfe)		(0.24	)		(0.75	)	68	%		(0.07	)		(1.04	)	93	%
Total average realized price (per Mcfe)	$	5.89		$	4.52		30	%	$	5.84		$	4.90		19	%
Expenses:
Lease operating expenses	$	6,530		$	5,208		25	%	$	11,243		$	10,701		5	%
Lease operating expenses (per Mcfe)	$	0.48		$	0.42		14	%	$	0.47		$	0.41		15	%
Depreciation, depletion and amortization – oil and gas properties	$	40,404		$	31,242		29	%	$	69,404		$	64,077		8	%
Depreciation, depletion and amortization – oil and gas properties (per Mcfe)	$	2.97		$	2.55		17	%	$	2.90		$	2.47		18	%

Three Months Ended June 30, 2005 as Compared to the Three Months Ended June 30, 2004

Three Months Ended June 30, 2004 as Compared to the Three Months Ended June 30, 2003


	Three Months Ended June 30,
	2005			2004			Variance
Production:
Natural gas (MMcf)		7,041			9,463			(2,422	)	(26	)%
Oil and condensate (MBbls)		849			582			267		46	%
Natural gas liquids (MBbls)		148			109			39		36	%
Total (MMcfe)		13,023			13,611			(588	)	(4	)%

Revenues (in thousands):
Natural gas	$	49,283		$	59,737		$	(10,454	)	(18	)%
Oil and condensate		41,523			21,311			20,212		95	%
Natural gas liquids		4,487			2,420			2,067		85	%
Net hedging income (loss)		(3,719	)		(3,285	)		(434	)	(13	)%
Other		396			(359	)		755		210	%

Total	$	91,970		$	79,824		$	12,146		15	%

Average realized sales price per unit:
Natural gas revenues from production (per Mcf)	$	7.00		$	6.31		$	0.69		11	%
Effects of hedging activities (per Mcf)		(0.04	)		(0.34	)		0.30		88	%

Average realized price (per Mcf)	$	6.96		$	5.97		$	0.99		17	%

Oil and condensate revenues from production (per Bbl)	$	48.92		$	36.61		$	12.31		34	%
Effects of hedging activities (per Bbl)		(4.03	)		—			(4.03	)	—

Average realized price (per Bbl)	$	44.89		$	36.61		$	8.28		23	%

Natural gas liquids revenues from production (per Bbl)	$	30.24		$	22.26		$	7.98		36	%
Effects of hedging activities (per Bbl)		—			—			—		—

Average realized price (per Bbl)	$	30.24		$	22.26		$	7.98		36	%

Total revenues from production (per Mcfe)	$	7.32		$	6.13		$	1.19		19	%
Effects of hedging activities (per Mcfe)		(0.29	)		(0.24	)		(0.05	)	(21	)%

Total average realized price (per Mcfe)	$	7.03		$	5.89		$	1.14		19	%

Expenses (per Mcfe):
Lease operating expenses	$	0.58		$	0.48		$	0.10		21	%
Depreciation, depletion and amortization – oil and gas properties	$	3.24		$	2.97		$	0.27		9	%

~~Revenues~~19 ~~and Production~~

Revenues increased $23.9 million, or 43%, in the second quarter of 2004 compared to the second quarter of 2003. The increase was due to a 16% higher commodity price, 11% higher production and a decrease in net hedging losses and other of $5.0 million.

~~Production~~Revenues increased approximately 1.3 Bcfe, or 11%, in the second quarter of 2004 compared to the second quarter of 2003, primarily due to new wells that commenced production subsequent to June 30, 2003, partially offset by normal production declines. Average daily production in the second quarter of 2004 was 150 MMcfe compared to 135 MMcfe in the second quarter of 2003. Natural gas revenues increased $7.5 million, or 14%, due to a 15% higher natural gas price, partially offset by the impact of a decrease in production of 0.1 Bcf, or 1%, in the second quarter of 2004. Excluding the effects of hedging activities, the second quarter 2004 natural gas price was $6.14 per Mcf compared to $5.36 per Mcf in the second quarter of 2003. Oil and ~~condensate~~Production revenues increased $11.4 million, or 115%, due to an increase in production of 239 MBbls, or 70%, and a 27% higher price in the second quarter of 2004. The second quarter 2004 oil and condensate price was $36.61 per barrel compared to $28.89 per barrel in the second quarter of 2003.

Revenues increased $12.1 million, or 15%, in the second quarter of 2005 compared to the second quarter of 2004. The increase was primarily due to a 19% higher average commodity price and a $0.8 million net increase in other revenues, partially offset by the impact of 4% lower production and a $0.4 million increase in hedging losses.

Production decreased approximately 0.6 Bcfe, or 4%, in the second quarter of 2005 compared to the second quarter of 2004. Average daily production in the second quarter of 2005 was 143 MMcfe compared to 150 MMcfe in the second quarter of 2004. Natural gas revenues decreased $10.5 million, or 18%, due primarily to lower production of 2.4 Bcf, or 26%, partially offset by an 11% higher average price in the second quarter of 2005. Excluding the effects of hedging activities, the second quarter 2005 average natural gas price was $7.00 per Mcf compared to $6.31 per Mcf in the same period of 2004. Oil and condensate revenues increased $20.2 million, or 95%, due primarily to an increase in production of 267 MBbls, or 46%, and a 34% higher average price. The increase in oil production was primarily due to Front Runner. Front Runner commenced production in December 2004, and four of the nine wells have been completed and are producing in 2005 as ramp-up activities continue. Excluding the effects of hedging activities, the second quarter 2005 average oil price was $48.92 per barrel compared to $36.61 per barrel in the same period of 2004. Natural gas liquids revenues increased $2.1 million, or 85%, in the second quarter of 2005 compared to the same period of 2004 based on natural gas production and related processing requirements.

Lease Operating Expenses

~~LOE~~Lease ~~includes~~operating expenses are costs incurred to operate and maintain wells and related equipment and facilities. These costs may include, among others, workover expenses, labor, materials, supplies, property taxes, insurance, severance taxes and transportation, gathering and processing expenses. ~~LOE~~Lease operating expenses increased $1.30 million, or 2515%, in the second quarter of ~~2004~~2005 compared to the ~~second~~same ~~quarter~~period ofin ~~2003~~2004. Of the total increase ~~in LOE~~, approximately $2.1.7 million was ~~attributable~~related to lease operating ~~costs~~expenses ~~associated~~at ~~with~~Front ~~new~~Runner, ~~wells~~our deepwater project that commenced production ~~subsequent~~in toDecember ~~June 30~~2004, ~~2003,~~and ~~partially offset~~$0.3 bymillion arelated ~~net~~to ~~decrease~~lease inoperating ~~LOE~~expenses ofon ~~$0.8~~other ~~million~~blocks ~~associated~~where ~~with~~production ~~all~~commenced ~~other~~subsequent ~~producing~~to ~~properties.~~the ~~The~~second ~~LOE~~quarter ~~rate~~of ~~increased~~2004, ~~14%~~offset toin part by a net $01.480 ~~per~~million ~~Mcfe~~decrease ~~primarily~~in ~~due~~costs toassociated with ~~higher~~producing ~~LOE~~blocks ~~rates~~as onof ~~new~~June ~~wells~~30, 2004.

Depreciation, Depletion and Amortization

DD&A increased $91.2 8 million, or 294%, in the second quarter of ~~2004~~ 2005 compared to the second quarter of ~~2003~~2004. Of the total increase in DD&A, $53.25 million related to a higher DD&A rate, ~~and~~offset in part by $41.07 million related to ~~higher~~lower production ~~volumes~~ of 10.36 Bcfe. The 9% increase in the DD&A rate ~~was~~per ~~primarily~~Mcfe ~~due~~ to ~~costs associated~~$3.24 ~~with~~in ~~unsuccessful drilling operations, higher finding costs and~~ the ~~timing~~second quarter of ~~reserve~~2005 ~~recognition,~~from as$2.97 ~~more~~in ~~reservoir~~the ~~and~~same ~~production~~period ~~information~~of ~~becomes~~2004 ~~available,~~was ~~compared~~primarily due to ~~the related amortized~~ costs. ~~Dry hole costs, including~~ associated ~~leasehold~~with ~~costs,~~unsuccessful ~~were~~wells ~~approximately~~since ~~$9.3~~June ~~million~~30, ~~in the second quarter of~~ 2004., Ofa ~~the~~net ~~total~~downward ~~$0.15~~revision ~~per~~to ~~Mcfe~~proved ~~increase~~reserves in ~~the~~2004 and ~~DD&A~~higher ~~rate~~finding ~~from~~costs ~~the~~associated ~~first~~with ~~quarter~~certain ofdiscoveries ~~2004,~~due ~~$0.12~~primarily ~~per~~to ~~Mcfe resulted from~~ the ~~retraction~~timing of ~~royalty~~reserve ~~suspension volumes of 2~~recognition.4 ~~MMBbls, or 14.3 Bcfe, on Front Runner.~~

Impairment of International Oil and Gas Properties

We recorded a $0.7 million impairment charge in the second quarter of 2005 as a result of an unsuccessful well in our West African venture. The transfer of the 12.5% interest to Spinnaker is still pending various approvals within the Nigerian government.

General and Administrative

General and administrative expenses are overhead-related expenses, including among others, wages and benefits for non-capitalized employees, auditing fees, legal fees, Sarbanes-Oxley Section 404 compliance fees, insurance, office rent, travel and entertainment, computer supplies and maintenance and investor relations expenses. General and administrative expenses ~~increased $1.2 million, or 41%,~~ in the second quarter of ~~2004~~2005 ~~compared to the second quarter of 2003. The increase was primarily due to higher employment-related costs of $0.5 million~~were ~~associated~~consistent with anexpenses ~~increase~~ in the ~~number~~same ~~of employees since June 30, 2003, catastrophic loss insurance expense of $0.5 million for the~~ period ~~prior to first production related to Front Runner and stock compensation expense~~ of $02004.2 ~~million.~~

~~Six Months Ended June 30, 2004 as Compared to the Six Months Ended June~~Income ~~30,~~Tax ~~2003~~Expense

~~Revenues~~Income ~~and~~tax ~~Production~~expense increased $2.8 million, or 28%, due to higher pre-tax income, offset in part by a reduction in the effective tax rate to 35.3% in the second quarter of 2005 from 36.0% in the second quarter of 2004. The effective tax rate was reduced to 35.3% beginning in the first quarter of 2005 due to lower expected deferred state income taxes resulting from a lower state apportionment factor.

~~Revenues~~20 increased $12.0 million, or 9%, in the first six months of 2004 compared to the same period of 2003. The increase was primarily due to a decrease in net hedging losses and other of $25.0 million, partially offset by the impact of 8% lower production and a 1% lower commodity price.

Production decreased approximately 2.1 Bcfe, or 8%, in the first six months of 2004 compared to the same period of 2003 primarily due to the rapid production decline of certain producing wells, timing related to first production from recent shelf discoveries and shut-ins for facility work not related to our properties, partially offset by new wells that commenced production subsequent to June 30, 2003. Average daily production in the first six months of 2004 was 131 MMcfe compared to 143 MMcfe in the same period of 2003. Natural gas revenues decreased $23.8 million, or 18%, due to a decrease in production of 3.4 Bcf, or 15%, and a 3% lower price before the effects of hedging. Excluding the effects of hedging activities, the natural gas price was $5.88 per Mcf in the first six months of 2004 compared to $6.07 per Mcf in the same period of 2003. Oil and condensate revenues increased $10.9 million, or 49%, due to an increase in production of 219 MBbls, or 32%, and a 14% higher price in the first six months of 2004. The oil and condensate price was $35.95 per barrel in the first six months of 2004 compared to $31.62 per barrel in the same period of 2003.

Six Months Ended June 30, 2005 as Compared to the Six Months Ended June 30, 2004


	Six Months Ended June 30,
	2005			2004			Variance
Production:
Natural gas (MMcf)		13,743			17,279			(3,536	)	(20	)%
Oil and condensate (MBbls)		1,542			914			628		69	%
Natural gas liquids (MBbls)		307			190			117		62	%
Total (MMcfe)		24,834			23,906			928		4	%

Revenues (in thousands):
Natural gas	$	91,900		$	103,935		$	(12,035	)	(12	)%
Oil and condensate		73,914			32,858			41,056		125	%
Natural gas liquids		8,769			4,444			4,325		97	%
Net hedging income (loss)		(3,126	)		(1,546	)		(1,580	)	(102	)%
Other		(1,164	)		(76	)		(1,088	)	(1,432	)%

Total	$	170,293		$	139,615		$	30,678		22	%

Average realized sales price per unit:
Natural gas revenues from production (per Mcf)	$	6.69		$	6.02		$	0.67		11	%
Effects of hedging activities (per Mcf)		0.17			(0.09	)		0.26		289	%

Average realized price (per Mcf)	$	6.86		$	5.93		$	0.93		16	%

Oil and condensate revenues from production (per Bbl)	$	47.95		$	35.95		$	12.00		33	%
Effects of hedging activities (per Bbl)		(3.58	)		—			(3.58	)	—

Average realized price (per Bbl)	$	44.37		$	35.95		$	8.42		23	%

Natural gas liquids revenues from production (per Bbl)	$	28.56		$	23.52		$	5.04		21	%
Effects of hedging activities (per Bbl)		—			—			—		—

Average realized price (per Bbl)	$	28.56		$	23.52		$	5.04		21	%

Total revenues from production (per Mcfe)	$	7.03		$	5.91		$	1.12		19	%
Effects of hedging activities (per Mcfe)		(0.13	)		(0.07	)		(0.06	)	(86	)%

Total average realized price (per Mcfe)	$	6.90		$	5.84		$	1.06		18	%

Expenses (per Mcfe):
Lease operating expenses	$	0.57		$	0.47		$	0.10		21	%
Depreciation, depletion and amortization – oil and gas properties	$	3.37		$	2.90		$	0.47		16	%

Revenues and Production

Revenues increased $30.7 million, or 22%, in the first six months of 2005 compared to the first six months of 2004. The increase was primarily due to 4% higher production and a 19% higher average commodity price in the first six months of 2005, partially offset by a $1.6 million increase in hedging losses and a $1.1 million net decrease in other revenues resulting primarily from the ineffective component of derivatives of $1.3 million.

Production increased approximately 0.9 Bcfe, or 4%, in the first six months of 2005 compared to the first six months of 2004 primarily due to Front Runner oil production. Average daily production in the first six months of 2005 was 137 MMcfe compared to 132 MMcfe in the first six months of 2004. Natural gas revenues decreased $12.0 million, or 12%, due primarily to lower production of 3.5 Bcf, or 20%, partially offset by an 11% higher average price in the first six months of 2005. Excluding the effects of hedging activities, the average natural gas price in the first six months of 2005 was $6.69 per Mcf compared to $6.02 per Mcf in the same period of 2004. Oil and condensate revenues increased $41.1 million, or 125%, due primarily to an increase in production of 628 MBbls, or 69%, and a 33% higher average price. Excluding the effects of hedging activities, the average oil price in the first six months of 2005 was $47.95 per barrel compared to $35.95 per barrel in the same period of 2004. Natural gas liquids revenues increased $4.3 million, or 97%, in the first six months of 2005 compared to the same period of 2004 based on natural gas production and related processing requirements.

Lease Operating Expenses

Lease operating expenses increased $02.59 million, or 526%, in the first six months of ~~2004~~2005 compared to the same period ofin ~~2003~~2004. Of the total increase ~~in lease operating expenses~~, approximately $2.58 million was ~~attributable~~related to lease operating ~~costs~~expenses ~~associated~~at ~~with~~Front ~~new wells that commenced production subsequent to June 30~~Runner, ~~2003,~~our ~~partially offset by a net decrease in LOE of $2.0~~ million associated with all other producing properties. The LOE rate increased 15% to $0.47 per Mcfe primarily due to lower production in the first six months of 2004 and higher LOE rates on new wells.

deepwater project that commenced production in December 2004, and $0.4 million related to lease operating expenses on other blocks where production commenced subsequent to June 30, 2004, offset in part by a net $0.3 million decrease in costs associated with producing blocks as of June 30, 2004.

Depreciation, Depletion and Amortization

DD&A increased $514.32 million, or 820%, in the first six months of ~~2004~~ 2005 compared to the ~~same~~first ~~period~~six months of ~~2003~~2004. Of the total increase in DD&A, $11.35 million related to a higher DD&A rate, ~~offset~~and ~~in part by~~ $62.07 million related to ~~lower~~higher production ~~volumes~~ of 20.19 Bcfe. The 16% increase in the DD&A rate ~~was~~per ~~primarily due~~Mcfe to ~~costs~~$3.37 ~~associated~~in ~~with~~the ~~unsuccessful~~first ~~drilling~~six ~~operations,~~months ~~higher~~of ~~finding~~2005 ~~costs~~from ~~and~~$2.90 in the ~~timing~~same ofperiod ~~reserve~~in ~~recognition,~~2004 aswas ~~more~~primarily due ~~reservoir~~to ~~and~~costs ~~production~~associated ~~information~~with ~~becomes~~unsuccessful ~~available~~wells, ~~compared~~a net downward revision to ~~the~~proved ~~related~~reserves ~~amortized~~in ~~costs.~~2004 ~~Dry~~and ~~hole~~higher finding costs~~, including~~ associated ~~leasehold~~with ~~costs,~~certain ~~were~~discoveries ~~approximately~~due ~~$32.0~~primarily ~~million~~to in the ~~first~~timing ~~six months~~ of ~~2004~~reserve recognition.

Impairment of International Oil and Gas Properties

We recorded an $8.5 million impairment charge in the first six months of 2005 as a result of an unsuccessful well in our West African venture.

General and Administrative

General and administrative expenses increased $10.76 million, or 288%, in the first six months of ~~2004~~2005 compared to the ~~same~~first ~~period~~six months of ~~2003~~2004. The increase was primarily due to higher employment-related ~~costs~~expenses, oflegal ~~approximately~~fees ~~$0.8~~and ~~million~~costs associated with ~~an increase in the number of employees since June 30, 2003, catastrophic loss insurance expense of $0.5 million for the period prior to first production~~ ~~related~~Sarbanes-Oxley toSection ~~Front~~404 ~~Runner and stock compensation expense of $0~~compliance.2 ~~million.~~

Income Tax Expense

Income tax expense increased $1.2 million, or 7%, due to higher pre-tax income, offset in part by a reduction in the effective tax rate to 35.3% in the first six months of 2005 from 36.0% in the first six months of 2004. The effective tax rate was reduced to 35.3% beginning in the first quarter of 2005 due to lower expected deferred state income taxes resulting from a lower state apportionment factor.

Liquidity and Capital Resources

~~Revenues~~Our revenues, profitability, cash flow and future growth depend substantially on prevailing oil and gas prices and our ability to find and develop oil and gas reserves that are economically recoverable. A substantial or extended decline in oil ~~the~~and ~~prices for natural~~ gas orprices ~~oil~~ could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and ~~ability~~access to ~~access~~ capital.

We have experienced and expect to continue to experience substantial capital requirements, primarily due to our active exploration and development programs in the Gulf of Mexico and offshore Nigeria. Net additions to property and equipment in the first six months of 2005 were $175.5 million. We have capital expenditure plans for ~~2004~~2005 totaling approximately $~~270~~310.0 million. WeBased ~~use~~on athis ~~risk-weighted~~level ~~model~~of capital expenditures and current oil and gas prices, we expect our cash flow from operations to ~~calculate~~exceed ~~budgeted~~our capital expenditures onin 2005 for the first time since our inception. We use a ~~project-by-project~~systematic ~~basis~~risking process to select prospects for drilling. If we experience greater than anticipated success on budgeted projects, capital expenditures will increase.

~~Property~~Oil and ~~equipment~~gas ~~additions~~prices inhave ~~the~~a ~~second~~significant ~~quarter~~impact ofon ~~2004~~our ~~were~~cash ~~$68.1~~flows ~~million.~~available Wefor ~~incurred~~ capital expenditures ofand ~~approximately~~our ~~$18~~ability to borrow and raise additional capital.1 ~~million~~The inamount ~~the second~~we ~~quarter~~can ofborrow ~~2004~~under ~~related~~the Revolver is subject to ~~development~~semi-annual ~~activities,~~re-determination ~~including~~based $9in part on changing expectations of future prices.5 ~~million~~Lower ~~associated~~prices ~~with~~may also reduce the ~~deepwater~~amount ~~discovery~~of atoil ~~Front~~and ~~Runner~~gas that we can economically produce. ~~Inception-to-date~~Lower ~~capital~~prices ~~expenditures~~and/or ~~through~~lower ~~June~~production 30may decrease revenues, ~~2004~~cash onflows and the ~~Front~~borrowing ~~Runner~~base ~~project~~under ~~were~~the ~~$142.9~~Revolver, ~~million. As~~thus ofreducing ~~June~~the ~~30,~~amount ~~2004,~~of wefinancial ~~expect~~resources available to ~~incur~~meet ~~approximately~~our ~~$51~~capital requirements.6 ~~million~~We inbelieve ~~future~~that ~~development~~cash flows ~~costs~~from ~~related~~operations toand ~~Front~~proceeds ~~Runner,~~from ~~including~~available ~~approximately~~borrowings ~~$13.1~~under ~~million~~the Revolver will be sufficient to meet our capital requirements in the ~~remainder~~next oftwelve ~~2004~~months. ~~and~~However, ~~$38.5~~additional ~~million~~debt ~~thereafter.~~or Onequity ~~August~~financing 3,may ~~2004,~~be required in the ~~contractor~~future to fund growth ~~completed~~and ~~construction~~acquisition, ofexploration and ~~handed~~development ~~over~~activities. In the ~~Front~~event ~~Runner~~additional ~~spar~~capital toresources ~~the~~are ~~Front~~unavailable, ~~Runner~~we ~~partners.~~may ~~First~~curtail ~~production~~drilling, isdevelopment ~~expected~~and inother ~~the~~activities ~~fourth~~or ~~quarter~~be forced to sell some of ~~2004~~our assets on an untimely or unfavorable basis.

~~Natural~~As ~~gas~~of ~~and~~June ~~oil~~30, ~~prices~~2005, ~~have~~we ahad ~~significant~~outstanding ~~impact~~borrowings ~~on our cash flows available for capital expenditures and our ability to borrow and raise additional~~of ~~capital~~$105.0 ~~The~~million, ~~amount~~and we ~~can~~were ~~borrow under the Revolver is subject to semi-annual re-determination based~~ in ~~part~~compliance onwith ~~changing~~the ~~expectations~~provisions of ~~future prices. Lower prices may also reduce~~ the ~~amount of natural gas and oil that we can economically produce~~Revolver. ~~Lower~~ ~~prices~~Subsequent ~~and/or~~to ~~lower~~June ~~production~~30, ~~may decrease revenues~~2005, ~~cash~~we ~~flows~~had ~~and~~no ~~the~~additional ~~borrowing base under the Revolver~~borrowings, ~~thus~~made ~~reducing~~a ~~the~~payment ~~amount~~ of ~~financial resources available to meet our capital requirements~~$75.0 Wemillion ~~believe~~using ~~that cash flows from operations,~~ proceeds from ~~available borrowings under~~ the ~~Revolver and~~ Front Runner ~~spar~~sale-leaseback ~~production~~transaction ~~facility~~and ~~financing~~issued ~~opportunities~~a letter ~~will~~of becredit ~~sufficient to meet our capital requirements~~ in the ~~next~~amount ~~twelve~~of ~~months~~$15.0 ~~However,~~million ~~additional~~under ~~debt or equity financing may be required in~~ the ~~future to fund growth and exploration and development activities~~Revolver. InCurrent ~~the~~availability ~~event~~is additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. As of June 30, 2004, we had borrowings of $93115.0 million ~~and~~under ~~were~~Tranche inA ~~compliance~~of ~~with~~ the ~~covenants and restrictive provisions under the~~ Revolver. ~~Subsequent~~We ~~to June 30, 2004, we had no additional borrowings; however, we~~ expect to incur additional borrowings ~~under~~in ~~Tranche~~the Aremainder of ~~the~~2005. ~~Revolver~~See in“–Financing Activities” ~~the~~for ~~remainder~~more ~~of 2004~~information.

2022

We have an effective shelf registration statement relating to the potential public offer and sale by us or certain of our affiliates of up to $500.0 million of any combination of debt securities, ~~Preferred~~preferred ~~Stock~~stock, ~~Common~~common ~~Stock~~stock, warrants, stock purchase contracts and trust preferred securities from time to time or when financing needs arise. The registration statement does not provide assurance that we will or could sell any such securities.

Contractual Obligations

WeEffective ~~lease~~July ~~administrative~~21, ~~offices~~2005, ~~office~~we ~~equipment~~consummated ~~and~~a ~~oil~~sale-leaseback ~~and~~transaction ~~gas~~under ~~equipment~~which ~~under~~we ~~non-cancelable~~sold ~~operating~~our ~~leases.~~25% Asundivided ofinterest ~~June~~in ~~30,~~our ~~2004,~~Front weRunner ~~had~~spar ~~borrowings~~production offacility for $9375.0 million ~~outstanding under Tranche A of the Revolver, which is due on December 19, 2006~~. WeScheduled ~~had no capital~~ lease orpayments ~~purchase~~under ~~obligations~~the orinitial ~~other contractual long~~12-year term ~~liabilities~~are as offollows: ~~June 30, 2004, except for obligations incurred in the ordinary course of business.~~


	Payments Due by Period
	Total		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years
Capital lease obligation	$	87,963	$	10,608	$	23,471	$	18,797	$	35,087

As of June 30, 2005, we had borrowings of $105.0 million outstanding under Tranche A of the Revolver. We used the $75.0 million proceeds from the sale-leaseback transaction to pay outstanding borrowings under the Revolver on July 21, 2005. As of August 8, 2005, we had borrowings of $30.0 million outstanding under Tranche A of the Revolver which are due on December 19, 2006.

Components of Cash Flow

Cash and cash equivalents ~~increased~~decreased $014.70 million to $167.0 8 million as of June 30, ~~2004~~2005. The components of the ~~increase~~decrease in cash and cash equivalents included $~~102~~129.58 million provided by operating activities, $~~151~~145.17 million used in investing activities and $491.39 million provided by financing activities.

Operating Activities

Net cash provided by operating activities in the first six months of ~~2004 decreased~~2005 21increased 27% to $~~102~~129.58 million, primarily due to ahigher ~~significant~~commodity ~~net increase in operating assets and liabilities~~prices. Cash flow from operations is dependent upon our ability to increase production through exploration and development activities and ~~the prices~~oil ofand ~~natural~~ gas ~~and oil~~prices. We have made significant investments to expand our operations in the Gulf of Mexico.

We23 sell our natural gas and oil production under fixed or floating market price contracts. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. However, these contracts may also limit the benefits we would realize if prices increase. See “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”

AsTable of June 30, 2004, we had negative working capital of $5.5 million. We believe that cash flows from operations, proceeds from available borrowings under the Revolver and Front Runner spar production facility financing opportunities will be sufficient to meet our capital requirements in the next twelve months. Our cash flow from operations depends on our ability to manage working capital, including accounts receivable, accounts payable and accrued liabilities. The net increase of $23.7 million in accounts receivable was primarily related to increases of $12.4 million in joint interest billings, $8.1 million in oil and gas revenues receivable and $0.9 million in insurance claims receivable compared to December 31, 2003. Joint interest billings fluctuate from period to period based on the number of wells operated by Spinnaker and the timing of billings to and collections from other working interest owners. Oil and gas revenues receivable increased primarily due to a 30% higher commodity price in June 2004 compared to December 2003. The increase in insurance claims receivable related primarily to two new claims in the second quarter of 2004, offset in part by collections on prior claims. Accounts payable and accrued liabilities decreased $6.8 million. Fluctuations in accounts payable and accrued liabilities from period to period occur based primarily on exploratory and development activities in progress and the timing of payments we make to vendors and other operators. We expect to settle asset retirement obligations of approximately $1.1 million in the next twelve months. Contents

~~Accounts~~We ~~receivable~~sell ~~includes~~our ~~insurance~~oil ~~claims~~and ~~receivable~~gas ofproduction ~~$3.7~~under ~~million.~~fixed ~~When~~and anfloating ~~event~~market ~~occurs,~~price wecontracts ~~assess~~each ~~the~~month. ~~incident~~We ~~for~~enter into ~~insurability~~hedging ~~and~~arrangements ~~estimate~~from ~~the~~time ~~recovery.~~to ~~All~~time ~~claims~~to ~~are~~reduce ~~subject~~our exposure to ~~customary~~fluctuations ~~underwriter~~in ~~review~~ oil and ~~assessment.~~gas Weprices ~~anticipate~~and ~~that~~to ~~our~~achieve ~~well~~more ~~control~~predictable ~~insurance~~cash ~~will~~flow. ~~cover~~However, these ~~claims;~~contracts ~~however,~~limit ~~any~~the ~~portion~~benefits ofwe awould ~~claim~~realize ~~that~~if isprices ~~denied~~increase. bySee ~~underwriters~~“Item is3. Quantitative ~~transferred~~and toQualitative ~~the~~Disclosures ~~full~~About ~~cost~~Market ~~pool and amortized through DD&A~~Risk.”

As of June 30, 2005, we had working capital of $4.8 million. Excluding current deferred tax assets of $42.0 million, we had negative working capital $37.2 million as of June 30, 2005. Our cash flow from operations depends on our ability to manage working capital, including accounts receivable, accounts payable and accrued liabilities. The net increase of $13.5 million in accounts receivable since December 31, 2004 was primarily related to increases of $11.4 million in joint interest billings and $2.8 million in oil and gas revenues receivable, offset in part by a net $0.7 million decrease other receivables. Joint interest billings fluctuate from period to period based on the number of wells we operate and the timing of billings to and collections from other working interest owners. Oil and gas revenues receivable increased primarily due to higher oil volumes and prices in June 2005 compared to December 2004, offset in part by lower natural gas volumes and prices in June 2005 compared to December 2004. Accounts payable and accrued liabilities increased $10.7 million from December 31, 2004. Fluctuations from period to period occur based on exploratory and development activities in progress and the timing of our payments to vendors and other operators.

Investing Activities

Net cash used in investing activities was $~~151~~145.17 million asin ofthe ~~June~~first ~~30,~~six ~~2004~~ months of 2005 and included oil and gas property ~~cash~~ expenditures of $~~150~~145.03 million and purchases of other property and equipment of $10.15 million.

As part of our strategy, we explore for oil and gas at deeper drilling depths and in the deep ~~waters~~water of the Gulf of Mexico, where operations are more difficult and costly than at shallower drilling depths and in shallower ~~waters~~water. Along with higher risks and costs associated with these areas, greater opportunity exists for reserve additions. We have experienced and will continue to experience significantly higher drilling costs for deep shelf and deepwater projects relative to the drilling costs on shallower depth shelf projects in the Gulf of Mexico. WeHistorically, ~~drilled~~most ~~seven~~of the wells inwe drilled were on the ~~second~~shelf. However, ~~quarter~~we are transitioning to more deepwater operations. Prior to 2001, we drilled nine deepwater wells, three of ~~2004~~which were successful. Since 2001 and through June 30, ~~four~~2005, we have drilled 35 deepwater wells, 23 of which were successful.

21In order to diversify our operations, we entered into a farm-out agreement in December 2004 covering a 12.5% interest in OPL Block 256 offshore Nigeria from Devon. The transfer of interest is pending various approvals within the Nigerian government. We expect our capital requirements for exploratory activities in connection with this venture to be approximately $50 million to $60 million over a two to three year period. The first well offshore Nigeria was determined to be unsuccessful in April 2005. As a result, we recorded an $8.5 million pre-tax impairment charge in the first six months of 2005 related to our international oil and gas properties. We have a minimum of two additional exploratory wells to drill on OPL Block 256, including one well we expect to drill later this year.

We drilled five successful wells in seven attempts in the first six months of 2005. We drilled 27 wells in 2004, 14 of which were successful. Since inception and through June 30, 2005, we drilled 183 wells, 109 of which were successful, representing a success rate of 60%. Dry hole costs, including associated leasehold costs, were approximately $13.0 million in the first six months of 2005. Our current capital expenditure budget for 2005 is approximately $310.0 million, including $190.0 million for exploration activities and geological and geophysical expenditures, $75.0 million for development activities, $42.0 million for leasehold acquisitions and $3.0 million for other property and equipment. We currently plan to drill and evaluate 14 wells in the remainder of 2005, including nine wells on the Gulf of Mexico shelf, four wells in the deep water of the Gulf of Mexico and one additional deepwater well in West Africa. Actual levels of capital expenditures may vary due to many factors, including drilling results, oil and gas prices, the availability of capital, industry conditions, acquisitions, decisions of operators and other prospect owners and the prices of drilling rig dayrates and other oilfield goods and services.

We settled asset retirement obligations of $0.9 million in the first six months of 2005. Current liabilities include asset retirement obligations of $10.5 million, the settlements of which will depend on the timing of abandonment decisions and equipment availability in 2005.

~~were~~The ~~successful.~~costs Weassociated ~~drilled~~with 29unproved ~~wells~~properties inand ~~2003,~~properties 20under ofdevelopment ~~which~~not ~~were~~included ~~successful.~~in ~~Since inception and through June 30, 2004, we~~the ~~drilled~~amortization ~~161~~base ~~wells, 97 of which~~ were ~~successful,~~as ~~representing~~follows ~~a success rate of 60%. Dry hole costs, including associated leasehold costs, were $9.3 million and $32.0 million~~ (in ~~the~~thousands): ~~three and six months ended June 30, 2004, respectively.~~

We have capital expenditure plans for 2004 totaling approximately $270.0 million, primarily for costs related to acquisition, exploration and development activities. Actual levels of capital expenditures may vary due to many factors, including drilling results, oil and gas prices, the availability of capital, industry conditions, acquisitions, decisions of operators and other prospect owners and the prices of drilling rig dayrates and other oilfield goods and services. The costs associated with unproved properties and properties under development not included in the amortization base were as follows (in thousands):


	As of June 30, 2005		As of December 31, 2004
Leasehold, delay rentals and seismic data, hardware and software costs	$	170,410	$	128,465
Wells in-progress		5,194		3,836
Wells pending determination		—		14,820
Other		2,537		1,156

Total	$	178,141	$	148,277

	As of June 30,2004		As ofDecember 31,2003
Leasehold, delay rentals and seismic data	$	138,696	$	119,708
Wells in-progress		10,655		29,459
Other		1,299		2,047
Total	$	150,650	$	151,214

Financing Activities

Net cash provided by financing activities of $491.39 million asin ofthe ~~June~~first ~~30,~~six ~~2004~~months of 2005 related to proceeds offrom ~~$43~~stock option exercises.0 ~~million~~We ~~from~~increased our borrowings ~~and~~by $613.45 million ~~from~~and ~~stock~~made ~~option~~payments ~~exercises.~~on Weour ~~paid~~borrowings ~~debt issue costs~~ of ~~approximately~~ $013.15 million in the first six months of ~~2004 in connection with the Revolver~~2005.

On December 19, 2003, ~~Spinnaker~~our ~~revised~~wholly-owned ~~and~~subsidiary, ~~renewed~~Spinnaker Exploration ~~the~~Company, L.L.C., entered into a $200.0 million Revolver with a group of eight banks. The Revolver consists of two tranches, Tranche A and Tranche B,. ~~and~~The ~~matures~~$50.0 million Tranche B commitment was terminated on ~~December~~July 1921, ~~2006~~2005 (with no borrowings then outstanding under Tranche B) upon closing of the Front Runner spar production facility sale-leaseback transaction. Borrowings under ~~each~~Tranche ~~tranche~~A constitute senior indebtedness. The obligations under the Revolver are fully and unconditionally guaranteed by Spinnaker.

Tranche A is available on a revolving basis through December 19, 2006, the maturity date of the Revolver, and availability is subject to the borrowing base, ~~currently $140.0 million, as~~ determined by the banks. ~~Tranche~~The Bborrowing isbase was $50160.0 million, isas ~~available~~of inJune ~~multiple advances through April 1~~30, 2005. ~~and~~The isobligations ~~not~~under ~~subject~~Tranche toA ~~the~~are ~~borrowing base~~unsecured. ~~We have~~The ~~made~~borrowing nobase ~~borrowings~~is ~~under~~re-determined ~~Tranche~~semi-annually B.by ~~Borrowings~~the ~~under~~banks ~~Tranche~~in Btheir ~~cannot~~sole bediscretion ~~reborrowed~~and ~~once~~in ~~repaid.~~their ~~Total~~usual ~~availability~~and ~~under~~customary ~~Tranche~~manner. ASpinnaker and ~~Tranche~~the Bbanks ~~cannot~~also ~~exceed~~have ~~$200.0~~the ~~million.~~right ~~Should~~to ~~the~~request ~~borrowing~~one ~~base~~additional ~~exceed~~re-determination ~~$150~~annually.0 ~~million,~~The ~~Tranche~~amount Bof ~~would~~the beborrowing ~~reduced~~base byis a ~~like~~function ~~amount~~of ~~for~~ the ~~period~~banks’ ~~the~~view ~~borrowing~~of ~~base~~our ~~exceeds~~reserve ~~$150.0~~profile, ~~million~~future ~~until~~commodity ~~the~~prices ~~maturity~~and ofprojected ~~Tranche~~cash Bflows. AtIn ~~such~~addition ~~time~~to ~~Tranche~~the Bsemi-annual ~~is utilized~~re-determinations, the banks ~~are~~have tothe beright ~~provided~~to ~~with~~re-determine ~~security~~the ~~interests~~borrowing base in ~~virtually~~the ~~all~~event of ~~Spinnaker’s reserve~~the ~~base.~~sale, ~~Upon~~transfer ~~repayment~~or disposition of ~~Tranche~~assets B,included in the ~~security~~borrowing ~~interests~~base ~~are~~exceeding to$25.0 ~~be released~~million.

~~The~~We ~~borrowing~~have ~~base~~the isoption ~~re-determined~~to ~~semi-annually~~elect byto ~~the~~use ~~banks~~a inbase ~~their~~interest ~~sole~~rate ~~discretion~~as ~~and~~described inbelow ~~their~~or ~~usual~~the ~~and~~LIBOR ~~customary~~plus, ~~manner.~~for ~~The~~each ~~banks~~such ~~and~~rate, ~~Spinnaker~~a ~~also~~spread ~~have~~based on the ~~right~~percentage toof ~~request~~the borrowing ~~one~~base ~~additional~~used ~~re-determination annually~~at that time. The ~~amount~~base ofrate ~~the~~spread ~~borrowing~~ranges ~~base~~from is0.0% ato ~~function~~0.5%, ofand the ~~banks’~~LIBOR ~~view~~spread ofranges ~~our~~from ~~reserve~~1.25% ~~profile,~~to ~~future~~2.0% ~~commodity~~for ~~prices~~Tranche ~~and~~A ~~projected~~borrowings. ~~cash~~The ~~flows.~~base Ininterest ~~addition~~rate tounder the ~~semi-annual~~Revolver ~~re-determinations,~~is a fluctuating rate of interest equal to the ~~banks~~base rate ~~have~~spread plus the ~~right~~higher toof reeither (i) The Toronto-~~determine~~Dominion ~~the borrowing~~Bank’s base rate for dollar advances made in the ~~event~~United ofStates or (ii) the ~~sale,~~Federal ~~transfer~~Funds orRate ~~disposition~~plus of0.5% ~~assets~~per ~~included~~annum. The weighted average interest rate was 4.6% in the ~~borrowing~~first ~~base~~six months ~~exceeding~~of ~~$25~~2005.0 ~~million,~~The orcommitment ~~$10~~fee rate ranges from 0.375% to 0.5%, ~~million~~depending ~~when~~on ~~Tranche~~the Bborrowing isbase ~~utilized~~usage for Tranche A.

We have the option to elect to use a base interest rate as described below or LIBOR plus, for each such rate, a spread based on the percentage of the borrowing base used at that time. The base interest rate spread ranges from 0.0% to 0.5% for Tranche A borrowings and from 2.0% to 2.75% for Tranche B borrowings. The LIBOR spread ranges from 1.25% to 2.0% for Tranche A borrowings and from 3.0% to 3.75% for Tranche B borrowings. The base interest rate under the Revolver is a fluctuating rate of interest equal to the higher of either (i) The Toronto-Dominion Bank’s base rate for dollar advances made in the United States or (ii) the Federal Funds Rate plus 0.5% per annum. The commitment fee rate ranges from 0.375% to 0.5%, depending on the borrowing base usage for Tranche A, and is 0.625% for Tranche B.

The Revolver also includes the following restrictions and covenants:

• Incurrence of other debt is prohibited except that senior debt may not exceed $10.0 million ~~($5.0 million when Tranche B is used)~~, vendor indebtedness for the purchase of seismic data may not exceed $25.0 million, subordinated debt is permitted subject to certain conditions and a lease transaction involving the Front Runner spar production facility is specifically permitted.

22• Liens are generally prohibited; however, we may grant a lien in connection with the purchase of seismic data, pledges and deposits to secure hedging arrangements not to exceed $15.0 million and lease financing arrangements involving our interest in the Front Runner spar production facility.

~~Table~~• ofStock ~~Contents~~buy-backs exceeding $10.0 million are prohibited in any fiscal year.

• Liens are generally prohibited; however, we may grant a lien in connection with the purchase of seismic data and pledges and deposits to secure hedging arrangements not to exceed $15.0 million.

• Dividends and stock buy-backs exceeding $10.0 million are prohibited in any fiscal year.

•

The ratio of debt to EBITDA may not exceed 2.50 to 1.00.

•

The ratio of current assets to current liabilities may not be less than 1.00 to 1.00. For purposes of the calculation, availability under the Revolver is added to current assets and maturities of the Revolver are excluded from current liabilities. Hedging assets and liabilities and asset retirement obligations are also excluded from this calculation.

•

Our tangible net worth is required to exceed 80% of the level at September 30, 2003, plus 50% of future net income with certain non-cash gains and losses excluded from net income, plus 75% of future equity issuances.

•

Our hedging transactions must not exceed 66²/3% of estimated future production for the next 18 months and 33¹/3% for the period 19 to 36 months from the date of the transaction. There are also credit rating restrictions on counterparties as well as concentration limits.

On ~~June~~February 308, ~~2004~~2005, weSpinnaker ~~had outstanding borrowings of $93.0 million under Tranche A~~ and ~~were in compliance with~~ the ~~covenants and~~banks ~~restrictive~~amended ~~provisions under~~ the Revolver. ~~Subsequent~~The toamendment ~~June~~was ~~30,~~intended ~~2004, we had no additional borrowings; however, we expect~~ to ~~incur~~give ~~additional~~us: ~~borrowings under Tranche A of the Revolver in the remainder of 2004.~~

•

the flexibility to engage in business activities through entities other than our principal operating subsidiary, Spinnaker Exploration Company, L.L.C., including activities in international locations;

•

the ability to make investments and provide guarantees and extensions of credit to entities other than our principal operating subsidiary;

•

a basket of up to $75.0 million a year to make distributions from our principal operating subsidiary to us, to request letters of credit under the Revolver for activities other than those of our principal operating subsidiary, subject to the limits under the Revolver, and to provide extensions of credit from our principal operating subsidiary to other entities; and

•

an increase in the aggregate amount of the borrowing base available under the Revolver for letters of credit up to $60.0 million, subject to certain limitations.

Effective July 21, 2005, we consummated a sale-leaseback transaction under which we sold our 25% undivided interest in the Front Runner spar production facility for $75.0 million. This lease has an initial 12-year term that expires on July 21, 2017 and has a full-term effective interest rate of 3.6%. The lease includes a fixed-price early buy-out option exercisable by us in year seven of the lease term. The effective interest rate for the seven-year term is 6.4%. The lease also grants us an option to purchase the spar production facility at fair market value at the end of the lease term. We will make quarterly rental payments over the term of the lease based upon a fixed payment schedule set forth in the lease.

We issued a guaranty, also effective July 21, 2005, guaranteeing the rental payments and other obligations. The guaranty is limited to the payments as they become due. We must also comply with certain on-going financial and operating covenants related to Front Runner.

As of June 30, 2005, we had outstanding borrowings of $105.0 million, and we were in compliance with the provisions of the Revolver. Subsequent to June 30, 2005, we had no additional borrowings, made a payment of $75.0 million using proceeds from the Front Runner sale-leaseback transaction and issued a letter of credit in the amount of $15.0 million under the Revolver. Current availability is $115.0 million under Tranche A of the Revolver. We expect to incur additional borrowings in the remainder of 2005.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Commodity Price Risk

Our revenues, profitability and future growth depend substantially on prevailing oil and gas prices. ~~Prices~~Oil and gas prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of ~~natural~~oil ~~gas~~ and ~~oil~~gas that we can economically produce. We sell our ~~natural~~oil ~~gas~~ and ~~oil~~gas production under fixed orand floating market price contracts each month. We enter into hedging arrangements from time to time to reduce our exposure to fluctuations in ~~natural~~oil ~~gas~~ and ~~oil~~gas prices and to achieve more predictable cash flow. We do not enter into such hedging arrangements for ~~trading~~ trading purposes. However, these contracts ~~also~~ limit the benefits we would realize if prices increase. Our current financial derivative contracts include fixed price swap contracts and cashless collar arrangements that have been placed with major ~~financial~~ ~~institutions~~trading counterparties we believe represent minimum credit risks. We cannot provide assurance that these trading counterparties will not become credit risks in the future. Under our current hedging practice, we generally do not hedge more than ~~662~~ 66 2/3% of our estimated twelve-month production quantities without the prior approval of the Risk Management Committee of ~~the~~our Board of Directors.

We enter into NYMEX related swap contracts and collar arrangements from time to time. ~~These~~The natural gas swap contracts and collar arrangements will settle based on the reported settlement price on the NYMEX for the last trading day of each month. The crude oil swap contracts and collar arrangements will settle based on the average of the settlement price for ~~natural~~each ~~gas~~commodity business day in the contract month.

In26 a swap transaction, the counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the settlement price is above the fixed price. As of June 30, 2004, our commodity price risk management positions in fixed price natural gas swap contracts and related fair values were as follows:

Period	AverageDailyVolume(MMBtus)	WeightedAveragePrice(Per MMBtu)		Fair Value (in thousands)
Third Quarter 2004	30,000	$	5.13	$	(2,826	)
Fourth Quarter 2004	8,370		4.92		(1,100	)
First Quarter 2005	5,000		7.05		144
Total				$	(3,782	)

In a swap transaction, the counterparty is required to make a payment to us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are required to make a payment to the counterparty for the difference between the fixed price and the settlement price if the settlement price is above the fixed price. In a collar arrangement, the counterparty is required to make a payment to us for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. We are required to make a payment to the counterparty for the difference between the fixed ceiling price and the settlement price if the settlement price is above the fixed ceiling price. Neither party is required to make a payment if the settlement price falls between the fixed floor and ceiling ~~price~~prices. As of June 30, ~~2004~~2005, our commodity price risk management positions in ~~natural~~swap ~~gas collar~~contracts ~~arrangements~~ and ~~related~~collar ~~fair~~arrangements ~~values~~ were as follows:

Period	AverageDailyVolume(MMBtus)	WeightedAverage Ceiling Price(Per MMBtu)		WeightedAverageFloor Price(Per MMBtu)		Fair Value (in thousands)
Third Quarter 2004	20,000	$	5.48	$	4.38	$	(1,362	)
Fourth Quarter 2004	18,370		6.56		4.73		(1,175	)
Total						$	(2,537	)

Natural Gas

We reported net liabilities of $6.3 million and $2.7 million related to our financial derivative contracts as of June 30, 2004 and December 31, 2003, respectively. Amounts related to hedging activities were as follows (in thousands):


	Fixed Price Swaps			Collars
Period	Average Daily Volume (MMBtus)	Weighted Average Price (Per MMBtu)		Average Daily Volume (MMBtus)	Weighted Average Price (Per MMBtu)
Period	Average Daily Volume (MMBtus)	Weighted Average Price (Per MMBtu)		Average Daily Volume (MMBtus)	Floor		Ceiling
Third Quarter 2005	10,000	$	6.40	—	$	—	$	—
Fourth Quarter 2005	3,370		6.40	—		—		—

	As ofJune 30,2004			As ofDecember 31,2003
Current assets:
Hedging assets	$	—		$	203
Deferred tax asset related to hedging activities	$	2,275		$	972
Current liabilities:
Hedging liabilities	$	6,319		$	2,903
Equity:
Accumulated other comprehensive loss	$	(4,044	)	$	(1,728	)

Oil

We recognized no ineffective component of the derivatives in the three and six months ended June 30, 2004 and 2003. We recognized a net hedging loss in revenues in the three and six months ended June 30, 2004 and 2003 as follows (in thousands):


	Fixed Price Swaps			Collars
Period	Average Daily Volume (Bbls)	Weighted Average Price (Per Bbl)		Average Daily Volume (Bbls)	Weighted Average Price (Per Bbl)
Period	Average Daily Volume (Bbls)	Weighted Average Price (Per Bbl)		Average Daily Volume (Bbls)	Floor		Ceiling
Third Quarter 2005	1,000	$	39.69	3,000	$	38.67	$	44.73
Fourth Quarter 2005	1,000		38.78	3,000		38.67		44.73

	Three Months EndedJune 30,						Six Months Ended June 30,
	2004			2003			2004			2003
Net hedging loss	$	(3,285	)	$	(9,167	)	$	(1,546	)	$	(26,910	)

We reported a net liability of $11.8 million and a net asset of $1.2 million related to financial derivative contracts as of June 30, 2005 and December 31, 2004, respectively. Amounts related to hedging activities were as follows (in thousands):

Based on future natural gas prices as of June 30, 2004, we would reclassify a net loss of $6.4 million from accumulated other comprehensive loss to earnings in the remainder of 2004 and a gain of $0.1 million from accumulated other comprehensive income to earnings in the first quarter of 2005. The amounts ultimately reclassified into earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement.


	As of June 30, 2005			As of December 31, 2004
	As of June 30, 2005			As of December 31, 2004
Current assets:
Hedging assets	$	—		$	2,829
Deferred tax asset related to hedging activities		4,182			—
Current liabilities:
Hedging liabilities	$	11,848		$	1,628
Deferred tax liability related to hedging activities		—			432
Equity:
Accumulated other comprehensive income (loss)	$	(6,681	)	$	963

24The ineffective component of derivatives and net hedging gains (losses) were recorded in revenues in the three and six months ended June 30, 2005 and 2004 as follows (in thousands):


	Three Months Ended June 30,						Six Months Ended June 30,
	2005			2004			2005			2004
Ineffective component of derivatives	$	160		$	—		$	(1,328	)	$	—

Net hedging losses	$	(3,719	)	$	(3,285	)	$	(3,126	)	$	(1,546	)

ToBased ~~calculate the potential effect of the derivative contracts~~ on future ~~revenues,~~oil weand ~~applied NYMEX natural~~ gas ~~forward~~ prices as of June 30, ~~2004~~2005, towe ~~the~~would ~~quantity~~reclassify a net loss of ~~our~~approximately $6.7 ~~natural~~million ~~gas~~from ~~production~~accumulated ~~covered~~other bycomprehensive ~~those~~income ~~derivative~~(loss) ~~contracts~~to asearnings ofin ~~that~~the ~~date~~remainder of 2005. The ~~following~~amounts ~~table~~ultimately ~~shows~~reclassified ~~the~~into ~~estimated~~earnings ~~potential~~will ~~effects~~vary ofdue to changes in the ~~derivative~~fair ~~financial~~value ~~instruments~~of ~~on future~~the ~~revenues~~open ~~(in~~derivative ~~thousands):~~contracts prior to settlement.

Derivative Instrument	Estimated Decreasein Revenues at Current Prices			Estimated Decreasein Revenues with10% Decrease inPrices			Estimated Decreasein Revenues with10% Increase inPrices
Fixed price swap transactions	$	(3,782	)	$	(1,294	)	$	(6,276	)
Collar arrangements	$	(2,537	)	$	(1,150	)	$	(3,746	)

To calculate the potential effect of the derivative contracts on future revenues, we applied NYMEX oil and gas forward prices as of June 30, 2005 to the quantity of our oil and gas production covered by those derivative contracts as of that date. The following table shows the estimated potential effects of the derivative financial instruments on future revenues (in thousands):

Subsequent to June 30, 2004, the fair value of our commodity price risk management positions in fixed price natural gas swap contracts and natural gas collar arrangements using an average natural gas forward price of $6.41 as of August 4, 2004 was a net liability of approximately $2.0 million for the period September through March 2005. July and August 2004 settlements resulted in a net loss of $2.6 million. The following are our commodity price risk management positions in fixed price natural gas swap contracts and natural gas collar arrangements as of August 5, 2004:


Derivative Instrument	Estimated Decrease in Revenues at Current Prices			Estimated Increase (Decrease) in Revenues with 10% Decrease in Prices			Estimated Decrease in Revenues with 10% Increase in Prices
Natural gas swaps	$	(762	)	$	98		$	(1,630	)
Oil swaps		(3,492	)		(2,771	)		(5,260	)
Oil collars		(7,594	)		(4,585	)		(10,743	)

~~Natural~~Subsequent ~~Gas~~to ~~Swap~~June ~~Contracts~~30, 2005, the fair value of our open commodity price risk management positions in swap contracts and collar arrangements using average oil and gas forward prices of $63.26 and $8.73, respectively, as of August 5, 2005 was a net liability of approximately $13.6 million, excluding July and August 2005 settlements resulting in losses of $1.8 million. We did not enter into any additional derivative transactions subsequent to June 30, 2005.

Period	AverageDailyVolume(MMBtus)	WeightedAverage Price (Per MMBtu)
Third Quarter 2004	30,000	$	5.13
Fourth Quarter 2004	8,370		4.92
First Quarter 2005	5,000		7.05

Natural Gas Collar Arrangements

Period	AverageDailyVolume(MMBtus)	WeightedAverageCeiling Price(Per MMBtu)		WeightedAverage Floor Price(Per MMBtu)
Third Quarter 2004	20,000	$	5.48	$	4.38
Fourth Quarter 2004	18,370		6.56		4.73

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on cash and cash equivalents and the interest rate paid on borrowings under the Revolver. We do not currently use interest rate derivative financial instruments to manage exposure to interest rate changes, but may do so in the future.

Item 4. Controls and Procedures.

~~Our~~Conclusion ~~Chief~~Regarding ~~Executive~~the ~~Officer~~Effectiveness ~~and Chief Financial Officer performed an evaluation~~ of ~~our~~Disclosure ~~disclosure~~Controls ~~controls~~ and ~~procedures,~~Procedures which have been designed to permit us to effectively identify and timely disclose important information. They concluded that the controls and procedures were effective as of June 30, 2004. During the three months ended June 30, 2004, we made no change in our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

25Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of our disclosure controls and procedures, as this term is defined under Rule 13a-15(e) promulgated under the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2005.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2005, we made no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

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

~~The~~We ~~Company~~ held ~~its~~our ~~2004~~2005 Annual Meeting of Stockholders (“Annual Meeting”) on Wednesday, May 54, ~~2004~~2005. The meeting was held to elect ~~six~~seven directors to serve until the ~~2005~~2006 Annual Meeting of Stockholders, ~~and~~to approve the Spinnaker Exploration Company 2005 Stock Incentive Plan and to ratify the selection of KPMG LLP as our independent auditors of the Company for the fiscal year ending December 31, ~~2004~~2005.

The ~~“For”~~results ~~column represents affirmative votes by holders~~ of ~~Common Stock represented by either proxy or at~~ the ~~Annual~~voting ~~Meeting.~~related ~~Accordingly, because~~to ~~“broker non-votes” are not counted in determining~~ the ~~total~~nominees ~~number~~to ofserve ~~votes cast~~ on ~~this~~our ~~proposal,~~Board ~~broker non-votes did not affect the outcome~~ of Directors ~~the~~for ~~election of directors. The results of~~ the ~~voting~~ensuing ~~related~~year ~~to the election of the nominees for director~~ were as follows:

Name	For	Withheld
Roger L. Jarvis	29,~~647~~164,~~330~~661	~~410~~704,~~985~~799
Howard H. Newman	29,~~053~~533,~~859~~523	1335,~~004,456~~937
Jeffrey A. Harris	2829,~~761~~581,~~014~~999	1287,~~297,301~~461
Michael E. McMahon	29,~~830~~583,~~400~~639	~~227~~285,~~915~~821
Sheldon R. Erikson	2728,~~876~~527,~~593~~404	21,~~181~~342,~~722~~056
Michael E. Wiley	27,~~884~~727,~~399~~831	2,~~173~~141,~~916~~629
Walter R. Arnheim	29,583,744	285,716

~~Stockholders~~The ~~voted 29,827,478~~results ~~shares~~of ~~“for”~~the voting ~~and~~related ~~228,193~~to ~~shares “against”~~ the proposal to ~~ratify~~approve the ~~selection~~Spinnaker ofExploration ~~KPMG LLP as independent auditors of the~~ Company ~~for~~2005 ~~the~~Stock ~~fiscal~~Incentive ~~year~~Plan ~~ending~~were ~~December~~as ~~31,~~follows: ~~2004, with 2,644 votes abstaining.~~

Item 6. Exhibits and Reports on Form 8-K


For:		23,765,378
Against:		2,545,707
Abstain:		11,634
Not Voted:		3,546,741

~~(a)~~The ~~Exhibits~~results of the voting related to the proposal to ratify the selection of KPMG LLP as independent auditors of the Company for the fiscal year ending December 31, 2005 were as follows:


For:		29,843,742
Against:		19,632
Abstain:		6,086

Item 6. Exhibits.

See “Exhibit Index.”

~~(b)~~29 ~~Reports on Form 8-K~~

A Current Report on Form 8-K dated April 29, 2004 and furnished on April 30, 2004 provided first quarter 2004 earnings and operations information through April 29, 2004 pursuant to Item 12, “Results of Operations and Financial Condition.”

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	~~SPINNAKER EXPLORATION COMPANY~~		SPINNAKER EXPLORATION COMPANY
Date: August 5, 2004	By:	/s/ ROBERT M. SNELL
Date:	August 8, 2005		By:	/s/ ROBERT M. SNELL
		~~Robert M. Snell~~		Robert M. Snell
		~~Vice President, Chief Financial Officer and Secretary~~		Vice President, Chief Financial Officer and Secretary
Date: August 5, 2004	By:	/s/ JEFFREY C. ZARUBA
Date:	August 8, 2005		By:	/s/ JEFFREY C. ZARUBA
		~~Jeffrey C. Zaruba~~		Jeffrey C. Zaruba
		~~Vice President, Treasurer and Assistant Secretary~~		Vice President, Treasurer and Assistant Secretary

2730

EXHIBIT INDEX

ExhibitNumber		Description
10.1 –		Spinnaker Exploration Company 2005 Stock Incentive Plan (filed with the Commission on May 10, 2005 as Exhibit 10.17 to our current report on Form 8-K dated May 4, 2005 and incorporated herein by reference)
10.2 –		Form of Nonstatutory Stock Option Award Agreement for Annual Director Grants (filed with the Commission on May 10, 2005 as Exhibit 10.17.1 to our current report on Form 8-K dated May 4, 2005 and incorporated herein by reference)
10.3 –		Form of Nonstatutory Stock Option Award Agreement for Discretionary Director Grants (filed with the Commission on May 10, 2005 as Exhibit 10.17.2 to our current report on Form 8-K dated May 4, 2005 and incorporated herein by reference)
10.4 –		Form of Nonstatutory Stock Option Award Agreement for Employee Grants (filed with the Commission on May 10, 2005 as Exhibit 10.17.3 to our current report on Form 8-K dated May 4, 2005 and incorporated herein by reference)
10.5 –		Non-Employee Director Compensation Arrangement (filed with the Commission on May 12, 2005 as Exhibit 10.1 to our current report on Form 8-K dated May 6, 2005 and incorporated herein by reference)
10.6 –		Form of Restricted Stock Award Agreement under the Spinnaker Exploration Company 1999 Stock Incentive Plan (filed with the Commission on May 12, 2005 as Exhibit 10.2 to our current report on Form 8-K dated May 6, 2005 and incorporated herein by reference)
10.7 –		Form of Restricted Stock Award Agreement under the Spinnaker Exploration Company 2001 Stock Incentive Plan (filed with the Commission on May 12, 2005 as Exhibit 10.3 to our current report on Form 8-K dated May 6, 2005 and incorporated herein by reference)
10.8 –		Spinnaker Exploration Company Executive Change in Control Severance Plan (filed with the Commission on June 3, 2005 as Exhibit 10.1 to our current report on Form 8-K dated May 31, 2005 and incorporated herein by reference)
10.9 –		Spinnaker Exploration Company Employee Change in Control Severance Plan (filed with the Commission on June 3, 2005 as Exhibit 10.2 to our current report on Form 8-K dated May 31, 2005 and incorporated herein by reference)
12.1 –		Calculation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends
31.1 –		Certification of Principal Executive Officer of Spinnaker Exploration Company Pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 –		Certification of Principal Financial Officer of Spinnaker Exploration Company Pursuant to Section 302 of the Sarbanes-Oxley Act
32.1 –		Certification of Chief Executive Officer of Spinnaker Exploration Company Pursuant to 18 U.S.C. § 1350
32.2 –		Certification of Chief Financial Officer of Spinnaker Exploration Company Pursuant to 18 U.S.C. § 1350

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