Edgar Filing: SPINNAKER EXPLORATION CO

Quarterly Report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2004.

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

For the transition period from to .

Commission file number 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)

(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 November 5, 2004 was 33,917,049.

SPINNAKER EXPLORATION COMPANY

Form 10-Q

For the Three and Nine Months Ended September 30, 2004


		Page
PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets September 30, 2004 (unaudited) and December 31, 2003		3

Consolidated Statements of Operations Three and Nine Months Ended September 30, 2004 and 2003 (unaudited)		4

Consolidated Statements of Cash Flows Nine Months Ended September 30, 2004 and 2003 (unaudited)		5

Notes to Interim Consolidated Financial Statements (unaudited)		6

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		22

Item 4. Controls and Procedures		25

PART II - OTHER INFORMATION

Item 6. Exhibits and Reports on Form 8-K		25

SIGNATURES		26

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)


	As of September 30, 2004			As of December 31, 2003
	(Unaudited)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	16,205		$	15,315
Accounts receivable, net of allowance for doubtful accounts of $3,232 as of September 30, 2004 and December 31, 2003, respectively		47,856			30,067
Hedging assets		—			203
Other		9,617			4,193

Total current assets		73,678			49,778
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		1,367,426			1,175,443
Unproved properties and properties under development, not being amortized		161,242			151,214
Other		18,899			17,309

		1,547,567			1,343,966
Less – Accumulated depreciation, depletion and amortization		(512,339	)		(404,298	)

Total property and equipment		1,035,228			939,668
OTHER ASSETS		709			1,136

Total assets	$	1,109,615		$	990,582

LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable	$	20,348		$	18,723
Accrued liabilities and other		42,519			60,874
Hedging liabilities		7,084			2,903
Asset retirement obligations, current portion		7,382			446

Total current liabilities		77,333			82,946
LONG-TERM DEBT		105,000			50,000
HEDGING LIABILITIES		519			—
ASSET RETIREMENT OBLIGATIONS		31,348			32,548
DEFERRED INCOME TAXES		100,910			81,027
COMMITMENTS AND CONTINGENCIES
EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; no shares issued and outstanding as of September 30, 2004 and December 31, 2003, respectively		—			—
Common stock, $0.01 par value; 50,000,000 shares authorized; 33,919,162 shares issued and 33,912,022 shares outstanding as of September 30, 2004 and 33,385,248 shares issued and 33,374,844 shares outstanding as of December 31, 2003		339			334
Additional paid-in capital		612,682			599,532
Retained earnings		186,368			145,949
Less: Treasury stock, at cost, 7,140 and 10,404 shares as of September 30, 2004 and December 31, 2003, respectively		(18	)		(26	)
Accumulated other comprehensive loss		(4,866	)		(1,728	)

Total equity		794,505			744,061

Total liabilities and equity	$	1,109,615		$	990,582

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 September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
REVENUES	$	63,191		$	50,138		$	202,806		$	177,740
EXPENSES:
Lease operating expenses		6,627			7,322			17,870			18,023
Depreciation, depletion and amortization – oil and gas properties		35,715			30,399			105,119			94,476
Depreciation and amortization – other		344			333			1,040			966
Accretion expense		910			529			2,164			1,593
Gain on settlement of asset retirement obligations		(50	)		(90	)		(176	)		(261	)
General and administrative		4,226			3,925			11,951			9,965

Total expenses		47,772			42,418			137,968			124,762

INCOME FROM OPERATIONS		15,419			7,720			64,838			52,978
OTHER INCOME (EXPENSE):
Interest income		58			49			126			176
Interest expense, net		(395	)		(234	)		(910	)		(536	)

Total other income (expense)		(337	)		(185	)		(784	)		(360	)

INCOME BEFORE INCOME TAXES		15,082			7,535			64,054			52,618
Income tax expense		6,005			2,713			23,635			18,943

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE		9,077			4,822			40,419			33,675
Cumulative effect of change in accounting principle		—			—			—			(3,527	)

NET INCOME	$	9,077		$	4,822		$	40,419		$	30,148

BASIC INCOME PER COMMON SHARE:
Income before cumulative effect of change in accounting principle	$	0.27		$	0.15		$	1.20		$	1.02
Cumulative effect of change in accounting principle		—			—			—			(0.11	)

NET INCOME PER COMMON SHARE	$	0.27		$	0.15		$	1.20		$	0.91

DILUTED INCOME PER COMMON SHARE:
Income before cumulative effect of change in accounting principle	$	0.26		$	0.14		$	1.16		$	0.99
Cumulative effect of change in accounting principle		—			—			—			(0.10	)

NET INCOME PER COMMON SHARE	$	0.26		$	0.14		$	1.16		$	0.89

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		33,896			33,226			33,721			33,208

Diluted		34,922			33,865			34,780			33,806

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

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Nine Months Ended September 30,
	2004			2003
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	40,419		$	30,148
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		106,159			95,442
Accretion expense		2,164			1,593
Gain on settlement of asset retirement obligations		(176	)		(261	)
Deferred income tax expense		23,635			18,683
Cumulative effect of change in accounting principle		—			3,527
Other		529			272
Change in operating assets and liabilities:
Accounts receivable		(17,789	)		10,872
Accounts payable and accrued liabilities		7,153			4,101
Other assets		(3,318	)		2,130

Net cash provided by operating activities		158,776			166,507
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties		(220,263	)		(205,906	)
Proceeds from sale of oil and gas property and equipment		—			1,148
Purchases of other property and equipment		(1,590	)		(2,089	)

Net cash used in investing activities		(221,853	)		(206,847	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		55,000			18,000
Debt issue costs		(101	)		—
Proceeds from exercise of stock options		9,068			442

Net cash provided by financing activities		63,967			18,442

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		890			(21,898	)
CASH AND CASH EQUIVALENTS, beginning of year		15,315			32,543

CASH AND CASH EQUIVALENTS, end of period	$	16,205		$	10,645

SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest	$	2,308		$	296

Cash paid for income taxes	$	—		$	260

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

SPINNAKER EXPLORATION COMPANY

Notes to Interim Consolidated Financial Statements (Unaudited)

September 30, 2004

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.

2. Summary of Significant Accounting Policies

Stock-Based Compensation

Statement of Financial Accounting Standards (“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 Accounting Principles Board (“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, 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 in each of the third quarter of 2004 and 2003, respectively, and $0.2 million and $0 in the first nine months of 2004 and 2003, 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):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net income, as reported	$	9,077		$	4,822		$	40,419		$	30,148
Add: Stock-based employee compensation expense included in reported net income, net of related tax effects		—			—			126			—
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards, net of related tax effects		(2,157	)		(1,666	)		(6,812	)		(4,694	)

Pro forma net income	$	6,920		$	3,156		$	33,733		$	25,454

Net income per common share:
Basic, as reported	$	0.27		$	0.15		$	1.20		$	0.91

Basic, pro forma	$	0.20		$	0.09		$	1.00		$	0.77

Diluted, as reported	$	0.26		$	0.14		$	1.16		$	0.89

Diluted, pro forma	$	0.19		$	0.09		$	0.94		$	0.74

Leasehold Costs

As of the end of 2003, the Financial Accounting Standards Board (“FASB”) was considering whether oil and gas drilling rights were subject to the classification and disclosure provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” In September 2004, the FASB issued FASB Staff Position (“FSP”) FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to Oil and Gas Producing Entities.” This FSP confirms that SFAS No. 142 did not

change the balance sheet classification or disclosure requirements for drilling and mineral rights of oil and gas producing entities. Spinnaker classifies the cost of oil and gas drilling and mineral rights as property and equipment.

3. Asset Retirement Obligations

Effective January 1, 2003, Spinnaker adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 requires entities to record a liability for asset retirement obligations at fair value in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. As of January 1, 2003, the Company recorded asset retirement costs of $21.4 million and asset retirement obligations of $26.0 million. The cumulative effect of change in accounting 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 nine months ended September 30, 2004 and 2003 was as follows (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Asset retirement obligations, beginning of period	$	36,262		$	30,117		$	32,994		$	—
Liabilities upon adoption of SFAS No. 143 on January 1, 2003		—			—			—			25,954
Liabilities incurred		1,764			1,210			4,598			7,055
Liabilities settled		(469	)		(761	)		(469	)		(3,399	)
Accretion expense		910			529			2,164			1,593
Revisions in estimated cash flows		263			(607	)		(557	)		(715	)

Asset retirement obligations, end of period	$	38,730		$	30,488		$	38,730		$	30,488

4. Earnings Per Share

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2004		2003		2004		2003
Numerator:
Net income available to common stockholders	$	9,077	$	4,822	$	40,419	$	30,148

Denominator:
Basic weighted average number of shares		33,896		33,226		33,721		33,208

Dilutive securities:
Stock options		1,026		639		1,059		598

Diluted adjusted weighted average number of shares and assumed conversions		34,922		33,865		34,780		33,806

Basic income per common share:
Income before cumulative effect of change in accounting principle	$	0.27	$	0.15	$	1.20	$	1.02
Cumulative effect of change in accounting principle		—		—		—		(0.11	)

Net income per common share	$	0.27	$	0.15	$	1.20	$	0.91

Diluted income per common share:
Income before cumulative effect of change in accounting principle	$	0.26	$	0.14	$	1.16	$	0.99
Cumulative effect of change in accounting principle		—		—		—		(0.10	)

Net income per common share	$	0.26	$	0.14	$	1.16	$	0.89

5. Debt

On December 19, 2003, Spinnaker revised and renewed the $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, and matures on December 19, 2006. Borrowings under each tranche constitute senior 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.

The borrowing base is re-determined semi-annually by the banks in their sole discretion and in their usual and customary manner. The banks and the Company 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, or $10.0 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. 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 contains various restrictions and covenants.

On September 30, 2004, the Company had outstanding borrowings under Tranche A of $105.0 million and was in compliance with the covenants and restrictive provisions under the Revolver. Current availability is $35.0 million and $50.0 million under Tranche A and Tranche B, respectively. Subsequent to September 30, 2004, the Company had no 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:

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 the Company for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. The Company 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 the Company for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. The Company 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 September 30, 2004, our commodity price risk management positions in fixed price 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
Fourth Quarter 2004	8,370	$	4.92	18,370	$	4.73	$	6.56
First Quarter 2005	10,000		7.36	—		—		—

Oil


	Fixed Price Swaps			Collars
	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
Fourth Quarter 2004	1,000	$	42.86	1,000	$	40.00	$	50.25
Calendar 2005	1,000		40.34	3,000		38.67		44.73

We reported net liabilities of $7.6 million and $2.7 million related to our financial derivative contracts as of September 30, 2004 and December 31, 2003, respectively. Amounts related to hedging activities were as follows (in thousands):


	As of September 30, 2004			As of December 31, 2003
Current assets:
Hedging assets	$	—		$	203
Deferred tax asset related to hedging activities		2,550			972
Current liabilities:
Hedging liabilities	$	7,084		$	2,903
Non-Current liabilities:
Hedging liabilities	$	519		$	—
Equity:
Accumulated other comprehensive loss	$	(4,866	)	$	(1,728	)

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net hedging loss	$	(2,607	)	$	(6,432	)	$	(4,153	)	$	(33,342	)

Based on future natural gas and oil prices as of September 30, 2004, we would reclassify a net loss of $3.1 million from accumulated other comprehensive loss to earnings in the fourth quarter of 2004 and a loss of $4.5 million from accumulated other comprehensive loss to earnings in 2005. The amounts ultimately reclassified into earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement.

7. Comprehensive Income

The following are components of comprehensive income (in thousands):


	Three Months Ended September 30,					Nine Months Ended September 30,
	2004			2003		2004			2003
Net income	$	9,077		$	4,822	$	40,419		$	30,148
Other comprehensive income (loss), net of tax:
Net change in fair value of derivative financial instruments		(2,490	)		4,659		(5,795	)		(12,121	)
Financial derivative settlements reclassified to income		1,669			4,117		2,658			21,339

Comprehensive income	$	8,256		$	13,598	$	37,282		$	39,366

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 we undertake 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 our 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 our 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 our actual results to differ materially from the results implied by these or any other forward-looking statements made by us or on our behalf. We cannot provide assurance that future results will meet our expectations. 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, 2003.

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 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. However, we have been and continue to be exposed to concentration risk since we currently operate in only one oil and gas basin. In response to this concentration risk, as well as the opportunity for exposure to a large acreage position that contains multiple prospects, we are currently evaluating an international exploration opportunity to diversify our operations. We are negotiating with an experienced international operator for a minority, non-operator working interest in a prolific offshore area. If we successfully negotiate our arrangement with this operator and we receive governmental approval to participate in operations in this area, we expect our capital requirements for exploratory activities in connection with this venture to be $30 million to $60 million over a two to three year period beginning in the first half of 2005.

We recognized net income of $9.1 million, or $0.26 per diluted share, in the third quarter of 2004 compared to net income of $4.8 million, or $0.14 per diluted share, in the third quarter of 2003. These financial results were impacted by 3% lower production and a 30% higher realized commodity price in the third quarter of 2004 compared to the third quarter of 2003. Excluding a third quarter 2003 major workover that impacted the lease operating expense (“LOE”) rate by $0.23 per Mcfe, our LOE rate per Mcfe in the third quarter of 2004 increased 48% to $0.59 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 21% to $3.17 in the third quarter of 2004 compared to the same period in 2003 primarily due to costs associated with unsuccessful drilling operations, net downward revisions to proved oil and gas reserves and the timing of reserve recognition, as more reservoir and production information becomes available, compared to the related amortized costs. The net downward revisions to proved oil and gas reserves included negative adjustments for the retraction of royalty suspension volumes due to the high commodity price environment.

We had $16.2 million in cash and cash equivalents and outstanding borrowings under the Revolver of $105.0 million as of September 30, 2004. We have experienced and expect to continue to experience substantial capital requirements. We have incurred capital costs of approximately $1.0 billion in the past three years. Additionally, we have had negative working capital at the end of each of the last three years. Our working capital deficit decreased to $3.7 million as of September 30, 2004 compared to $33.2 million as of December 31, 2003. Our total capital expenditure plans for 2004 are approximately $275.0 million, of which approximately $71.0 million are planned for the fourth quarter of 2004. 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.

Although we have been able to maintain a drilling success rate of approximately 60% since inception, our exploratory drilling successes on the shelf and deep shelf since the second half of 2001 have been smaller in size 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. Additionally, several of our discoveries since mid-2001 were in the deep water, and we do not expect to see the full impact on production and reserve recognition from these projects until after 2004.

Production

Since inception, approximately 90% of our total production has consisted of natural gas. Approximately 81% of our total production in the third quarter of 2004 consisted of natural gas. Considering oil and condensate production from deepwater projects in 2004 and 2005, we anticipate that this concentration in natural gas production will be approximately 75% of total production in 2004 and approximately 50% of total production in 2005. 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 than in the past.

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 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.

Oil and Gas Property Costs

Spinnaker participated in one successful well in five attempts in the third quarter of 2004. Property and equipment additions of $60.6 million in the third quarter of 2004 included leasehold and other acquisition costs of approximately $3.0 million, exploration costs of $48.3 million, development costs of $8.8 million and other property and equipment costs of $0.5 million. We currently plan to drill approximately nine wells on the shelf and three wells in the deep water in the fourth quarter of 2004. We expect more than 50% of our 2004 capital expenditure budget to be used for exploration activities, up from 34% in 2003.

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 a 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 future development costs. The DD&A rate increases due to costs incurred without related reserve additions and the timing of reserve recognition, as more reservoir and production information becomes available, compared to the related amortized costs.

The DD&A rate per Mcfe is calculated quarterly and increased 7% to $3.17 in the third quarter of 2004 from $2.97 in the second quarter of 2004. The increase in the DD&A rate was primarily due to costs associated with unsuccessful drilling operations and a net downward revision to proved oil and gas reserves in the third quarter of 2004. The net downward reserve revision primarily resulted from unsuccessful sidetrack operations at a High Island 202 well in the related Rob L-3 and Rob L-5 sands.

Natural Gas and Oil Prices and Hedging Activities

Revenues, profitability, cash flow and future growth depend substantially on prevailing oil and gas prices. Prices for natural gas and oil fluctuate widely, affecting the amount of cash flow available for capital expenditures 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 our ability to borrow and access capital. 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 $2.6 million in the third quarter of 2004 compared to a net hedging loss of $6.4 million in the third quarter of 2003. The net hedging loss in the first nine months of 2004 was $4.2 million compared to $33.3 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.

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 pool.

We use the full cost method of accounting for investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related 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, 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 will 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 $33.91 per barrel that is applicable to Green Canyon Blocks 338 and 339 and $30.41 per barrel that is applicable to Green Canyon Block 382. We believe the thresholds will be exceeded and the Front Runner area leases, as well as our other deepwater leases, will not qualify for royalty relief in 2004. 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 estimates of proved 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.

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 using the unit-of-production method based upon production and estimates of proved reserve quantities. 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 estimated salvage values 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 September 30, 2004, we excluded from the amortization base estimated future expenditures of $27.3 million associated with common development costs for the 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 $27.3 million had been included in the amortization base as of September 30, 2004, and no additional reserves were assigned to the Front Runner project, the DD&A rate in the third quarter of 2004 would have been $3.26 per Mcfe, or an increase of $0.09 over the actual DD&A rate of $3.17 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.

Full Cost Ceiling

Capitalized costs of oil and gas properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves discounted at 10% and including the effects of hedging activities in place as of end of the quarter, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (full cost ceiling). If capitalized costs of the full cost pool exceed the ceiling limitation, the excess is charged to expense.

As of September 30, 2004, Spinnaker’s full cost ceiling, including estimated future net cash flows calculated using commodity prices of $6.62 per Mcf of natural gas and $35.91 per barrel of oil and condensate, exceeded capitalized costs of oil and gas properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, by approximately $164.8 million. Considering the volatility of natural gas and oil 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. 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 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 and delay rentals, seismic data, wells in-progress and wells 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.

Leasehold Costs

As of the end of 2003, the FASB was considering whether oil and gas drilling rights were subject to the classification and disclosure provisions of SFAS No. 142, “Goodwill and Other Intangible Assets.” In September 2004, the FASB issued FSP FAS 142-2, “Application of FASB Statement No. 142, Goodwill and Other Intangible Assets to Oil and Gas Producing Entities.” This FSP confirms that SFAS No. 142 did not change the balance sheet classification or disclosure requirements for drilling and mineral rights of oil and gas producing entities. We classify the cost of oil and gas drilling and mineral rights as property and equipment.

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 September 30, 2004, 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 gas and oil 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 institutions. We recorded a net hedging loss of $2.6 million and $4.2 million in the three and nine months ended September 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 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 in each of the third quarter of 2004 and 2003, respectively, and $0.2 million and $0 in the first nine months of 2004 and 2003, respectively. For further information concerning SFAS 123 see Note 2 of the Notes to Consolidated Financial Statements.

Related Parties

We purchase oilfield goods, equipment and services from Baker Hughes Incorporated (“Baker Hughes”), Cooper Cameron Corporation (“Cooper Cameron”), National-Oilwell, Inc. (“National-Oilwell”) and other oilfield services companies in the ordinary course of business. Spinnaker incurred charges of $10.3 million in the first nine months of 2004 from affiliates of Baker Hughes. Mr. Michael E. Wiley, a director of Spinnaker, served as Chairman of the Board and Chief Executive Officer of Baker Hughes through October 25, 2004. Spinnaker incurred charges of less than $0.1 million in the first nine months of 2004 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 incurred charges of less than $0.1 million in the first nine months of 2004 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 nine months ended September 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 respective segments of the oilfield services sector. We could be at a disadvantage if we were to discontinue using these companies as vendors.

Results of Operations


	Three Months Ended September 30,								Nine Months Ended September 30,
	2004			2003			% Change		2004			2003			% Change
Production:
Natural gas (MMcf)		9,060			9,438		(4	%)		27,481			31,229		(12	%)
Oil and condensate (MBbls)		365			351		4	%		1,279			1,046		22	%
Total (MMcfe)		11,251			11,543		(3	%)		35,157			37,506		(6	%)
Revenues (in thousands):
Natural gas	$	50,756		$	45,967		10	%	$	159,135		$	178,161		(11	%)
Oil and condensate		15,009			10,355		45	%		47,867			32,339		48	%
Net hedging income (loss)		(2,607	)		(6,432	)	(59	%)		(4,153	)		(33,342	)	(88	%)
Other		33			248		(87	%)		(43	)		582		(107	%)

Total	$	63,191		$	50,138		26	%	$	202,806		$	177,740		14	%
Average realized sales price per unit:
Natural gas revenues from production (per Mcf)	$	5.60		$	4.87		15	%	$	5.79		$	5.71		1	%
Effects of hedging activities (per Mcf)		(0.28	)		(0.68	)	(59	%)		(0.15	)		(1.07	)	(86	%)

Average realized price (per Mcf)	$	5.32		$	4.19		27	%	$	5.64		$	4.64		22	%

Oil and condensate revenues from production (per Bbl)	$	41.10		$	29.50		39	%	$	37.42		$	30.91		21	%
Effects of hedging activities (per Bbl)		(0.25	)		—		—			(0.07	)		—		—

Average realized price (per Bbl)	$	40.85		$	29.50		38	%	$	37.35		$	30.91		21	%

Total revenues from production (per Mcfe)	$	5.85		$	4.88		20	%	$	5.89		$	5.61		5	%
Effects of hedging activities (per Mcfe)		(0.24	)		(0.56	)	(57	%)		(0.12	)		(0.89	)	(87	%)

Total average realized price (per Mcfe)	$	5.61		$	4.32		30	%	$	5.77		$	4.72		22	%

Expenses:
Lease operating expenses	$	6,627		$	7,322		(9	%)	$	17,870		$	18,023		(1	%)
Lease operating expenses (per Mcfe)	$	0.59		$	0.63		(6	%)	$	0.51		$	0.48		6	%
Depreciation, depletion and amortization – oil and gas properties	$	35,715		$	30,399		17	%	$	105,119		$	94,476		11	%
Depreciation, depletion and amortization – oil and gas properties (per Mcfe)	$	3.17		$	2.63		21	%	$	2.99		$	2.52		19	%

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

Revenues and Production

Revenues increased $13.1 million, or 26%, in the third quarter of 2004 compared to the third quarter of 2003. The increase was due to a 20% higher commodity price and a decrease in net hedging losses and other of $3.6 million, partially offset by 3% lower production.

Production decreased approximately 0.3 Bcfe, or 3%, in the third quarter of 2004 compared to the third quarter of 2003, primarily due to weather-related shut-ins as well as normal production declines. Average daily production in the third quarter of 2004 was 122 MMcfe compared to 125 MMcfe in the third quarter of 2003. Natural gas revenues increased $4.8 million, or 10%, due to a 15% higher natural gas price before the effects of hedging, partially offset by the impact of a decrease in production of 0.4 Bcf, or 4%, in the third quarter of 2004. Excluding the effects of hedging activities, the third quarter 2004 natural gas price was $5.60 per Mcf compared to $4.87 per Mcf in the third quarter of 2003. Oil and condensate revenues

increased $4.7 million, or 45%, due to a 39% higher price and an increase in production of 14 MBbls, or 4%, in the third quarter of 2004. The third quarter 2004 oil and condensate price was $41.10 per barrel compared to $29.50 per barrel in the third quarter of 2003.

Lease Operating Expenses

LOE includes costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, labor, materials, supplies, property taxes, insurance, severance taxes and transportation, gathering and processing expenses. LOE decreased $0.7 million, or 9%, in the third quarter of 2004 compared to the third quarter of 2003. Of the total decrease in LOE, approximately $2.7 million related to a major workover in the third quarter of 2003, partially offset by an increase of $0.9 million in operating costs associated with new wells that commenced production subsequent to September 30, 2003 and an increase of $1.1 million related to higher LOE rates on new wells. Excluding the third quarter 2003 major workover that impacted the LOE rate by $0.23 per Mcfe, the LOE rate per Mcfe in the third quarter of 2004 increased 48% to $0.59 compared to the same period of 2003. The LOE rate increased primarily due to higher LOE rates on new wells.

Depreciation, Depletion and Amortization

DD&A increased $5.3 million, or 17%, in the third quarter of 2004 compared to the third quarter of 2003. Of the total increase in DD&A, $6.2 million related to a higher DD&A rate, partially offset by $0.9 million related to lower production volumes of 0.3 Bcfe. The increase in the DD&A rate was primarily due to costs associated with unsuccessful drilling operations and a net downward revision to proved oil and gas reserves in the third quarter of 2004. Dry hole costs, including associated leasehold costs, were approximately $26.7 million in the third quarter of 2004. We recorded a net downward revision of proved oil and gas reserves of 11.2 Bcfe, or 3.5% of proved oil and gas reserves as of the beginning of the third quarter of 2004. The net downward reserve revision primarily resulted from unsuccessful sidetrack operations at a High Island 202 well in the related Rob L-3 and Rob L-5 sands.

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, insurance, office rent, travel and entertainment, computer supplies and maintenance and investor relations expenses. General and administrative expenses increased $0.3 million, or 8%, in the third quarter of 2004 compared to the third quarter of 2003. The increase was primarily due to higher employment-related costs associated with an increase in the number of employees since September 30, 2003 and business interruption insurance expense of $0.3 million for the period prior to first production related to Front Runner, partially offset by a net decrease in other general and administrative expenses.

Nine Months Ended September 30, 2004 as Compared to the Nine Months Ended September 30, 2003

Revenues and Production

Revenues increased $25.1 million, or 14%, in the first nine 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 $28.6 million and a 5% higher commodity price, partially offset by 6% lower production.

Production decreased approximately 2.3 Bcfe, or 6%, in the first nine 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 weather-related shut-ins, partially offset by production from new wells subsequent to September 30, 2003. Average daily production in the first nine months of 2004 was 128 MMcfe compared to 137 MMcfe in the same period of 2003. Natural gas revenues decreased $19.0 million, or 11%, due to a decrease in production of 3.7 Bcf, or 12%, partially offset by a 1% higher price before the effects of hedging. Excluding the effects of hedging activities, the natural gas price was $5.79 per Mcf in the first nine months of 2004 compared to $5.71 per Mcf in the same period of 2003. Oil and condensate revenues increased $15.5 million, or 48%, due to an increase in production of 233 MBbls, or 22%, and a 21% higher price in the first nine months of 2004. The oil and condensate price was $37.42 per barrel in the first nine months of 2004 compared to $30.91 per barrel in the same period of 2003.

Lease Operating Expenses

Lease operating expenses decreased $0.2 million, or less than 1%, in the first nine months of 2004 compared to the same period of 2003. Of the total decrease in LOE, workovers decreased $3.1 million and transportation expenses decreased $2.0 million, partially offset by an increase of $1.5 million in operating costs associated with new wells that commenced production subsequent to September 30, 2003 and an increase of $3.4 million related to higher LOE rates on new wells. Excluding a third quarter 2003 major workover that impacted the LOE rate by $0.07 per Mcfe in the first nine months of 2003, the LOE rate per Mcfe in the first nine months of 2004 increased 24% to $0.51 compared to the same period in 2003 primarily due to higher LOE rates on new wells and lower production in the first nine months of 2004 compared to the same period in 2003.

Depreciation, Depletion and Amortization

DD&A increased $10.6 million, or 11%, in the first nine months of 2004 compared to the same period of 2003. Of the total increase in DD&A, $17.6 million related to a higher DD&A rate, offset in part by $7.0 million related to lower production volumes of 2.3 Bcfe. The increase in the DD&A rate was primarily due to costs associated with unsuccessful drilling operations, net downward revisions to proved oil and gas reserves and the timing of reserve recognition, as more reservoir and production information becomes available, compared to the related amortized costs. Dry hole costs, including associated leasehold costs, were approximately $58.7 million in the first nine months of 2004.

General and Administrative

General and administrative expenses increased $2.0 million, or 20%, in the first nine months of 2004 compared to the same period of 2003. The increase was primarily due to higher employment-related costs associated with an increase in the number of employees since September 30, 2003 and business interruption insurance expense of $0.7 million for the period prior to first production related to Front Runner.

Liquidity and Capital Resources

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 natural gas or 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 our ability to borrow and 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. We have capital expenditure plans for 2004 totaling approximately $275.0 million. We use a risk-weighted model to calculate budgeted capital expenditures on a project-by-project basis. If we experience greater than anticipated success on budgeted projects, capital expenditures will increase.

Property and equipment additions in the third quarter of 2004 were $60.6 million. We incurred capital expenditures of approximately $8.8 million in the third quarter of 2004 related to development activities, including $4.0 million associated with the deepwater discovery at Front Runner. Inception-to-date capital expenditures through September 30, 2004 on the Front Runner project were $151.1 million. As of September 30, 2004, we expect to incur approximately $68.5 million in future development costs related to Front Runner, including approximately $3.5 million in the remainder of 2004, $27.8 million in 2005 and $37.2 million thereafter. The contractor completed construction of and handed over the Front Runner spar to the Front Runner partners in August 2004. First production is expected in November 2004.

Natural gas and oil prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under the Revolver is subject to semi-annual re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and oil that we can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the Revolver, thus reducing the amount of financial resources available to meet our capital requirements. 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. However, additional debt or equity financing may be required in the future to fund growth and exploration and development activities. In the event 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 September 30, 2004, we had borrowings of $105.0 million and were in compliance with the covenants and restrictive provisions under the Revolver. Subsequent to September 30, 2004, we had no additional borrowings; however, we expect to incur additional borrowings under Tranche A of the Revolver in the remainder of 2004.

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 Stock, Common 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

We lease administrative offices, office equipment and oil and gas equipment under non-cancelable operating leases. As of September 30, 2004, we had borrowings of $105.0 million outstanding under Tranche A of the Revolver, which are due on December 19, 2006. We had no capital lease or purchase obligations or other contractual long-term liabilities as of September 30, 2004, except for obligations incurred in the ordinary course of business.

Components of Cash Flow

Cash and cash equivalents increased $0.9 million to $16.2 million as of September 30, 2004. The components of the increase in cash and cash equivalents included $158.8 million provided by operating activities, $221.9 million used in investing activities and $64.0 million provided by financing activities.

Operating Activities

Net cash provided by operating activities in the first nine months of 2004 decreased 5% to $158.8 million. Cash flow from operations is dependent upon our ability to increase production through exploration and development activities and the prices of natural gas and oil. We have made significant investments to expand our operations in the Gulf of Mexico.

We 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.”

As of September 30, 2004, we had negative working capital of $3.7 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 $17.8 million in accounts receivable was primarily related to increases of $15.8 million in joint interest billings and $2.0 million in insurance claims compared to December 31, 2003. Joint interest billings fluctuate from period to period based on the number of wells we operate and the timing of our billings to and collections from other working interest owners. Accounts payable and accrued liabilities decreased $16.7 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 $7.4 million in the next twelve months.

Accounts receivable includes insurance claims receivable of $4.8 million. When an event occurs, we assess the incident for insurability and estimate the recovery. All claims are subject to customary underwriter review and assessment. We anticipate that our well control insurance will cover these claims; however, any portion of a claim that is denied by underwriters is transferred to the full cost pool and amortized through DD&A.

Investing Activities

Net cash used in investing activities was $221.9 million in the first nine months of 2004 and included oil and gas property cash expenditures of $220.3 million and purchases of other property and equipment of $1.6 million.

As part of our strategy, we explore for oil and gas at deeper drilling depths and in the deep waters of the Gulf of Mexico, where operations are more difficult and costly than at shallower drilling depths and in shallower waters. 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. We drilled five wells in the third quarter of 2004, one of which was successful, and 17 wells in the first nine months of 2004, eight of which were successful. We drilled 29 wells in 2003, 20 of which were successful. Since inception and through September 30, 2004, we drilled 166 wells, 98 of which were successful,

representing a success rate of 59%. Dry hole costs, including associated leasehold costs, were $26.7 million and $58.7 million in the three and nine months ended September 30, 2004, respectively.

Our capital expenditure plans for 2004 total approximately $275.0 million, of which approximately $71.0 million are planned for the fourth quarter of 2004. These capital expenditures are 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 September 30, 2004		As of December 31, 2003
Leasehold, delay rentals and seismic data	$	124,636	$	119,708
Wells in-progress		20,491		29,459
Wells pending determination		14,816		—
Other		1,299		2,047

Total	$	161,242	$	151,214

Financing Activities

Net cash provided by financing activities of $64.0 million in the first nine months of September 30, 2004 related to proceeds of $55.0 million from borrowings and $9.1 million from stock option exercises. We paid debt issue costs of approximately $0.1 million in connection with the Revolver.

On December 19, 2003, Spinnaker revised and renewed the $200.0 million Revolver with a group of eight banks. The Revolver consists of two tranches, Tranche A and Tranche B, and matures on December 19, 2006. Borrowings under each tranche constitute senior 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. We have 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.

The borrowing base is re-determined semi-annually by the banks in their sole discretion and in their usual and customary manner. The banks and Spinnaker 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 our 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, or $10.0 million when Tranche B is utilized.

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 is specifically permitted.

•

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 September 30, 2004, we had outstanding borrowings of $105.0 million under Tranche A and were in compliance with the covenants and restrictive provisions under the Revolver. Current availability is $35.0 million and $50.0 million under Tranche A and Tranche B, respectively. Subsequent to September 30, 2004, we had no additional borrowings; however, we expect to incur additional borrowings under Tranche A of the Revolver in the remainder of 2004.

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 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 gas and oil that we can economically produce. We 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. We do not enter into such hedging arrangements for 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 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 66 2/3% of our estimated twelve-month production quantities without the prior approval of the Risk Management Committee of the Board of Directors.

We enter into 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 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 prices. As of September 30, 2004, our commodity price risk management positions in fixed price swap contracts and collar arrangements were as follows:

Natural Gas


	Fixed Price Swaps			Collars
	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
Fourth Quarter 2004	8,370	$	4.92	18,370	$	4.73	$	6.56
First Quarter 2005	10,000		7.36	—		—		—

Oil

	Fixed Price Swaps			Collars
	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
Fourth Quarter 2004	1,000	$	42.86	1,000	$	40.00	$	50.25
Calendar 2005	1,000		40.34	3,000		38.67		44.73


	As of September 30, 2004			As of December 31, 2003
Current assets:
Hedging assets	$	—		$	203
Deferred tax asset related to hedging activities		2,550			972
Current liabilities:
Hedging liabilities	$	7,084		$	2,903
Non-Current liabilities:
Hedging liabilities	$	519		$	—
Equity:
Accumulated other comprehensive loss	$	(4,866	)	$	(1,728	)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2004			2003			2004			2003
Net hedging loss	$	(2,607	)	$	(6,432	)	$	(4,153	)	$	(33,342	)

To calculate the potential effect of the derivative contracts on future revenues, we applied NYMEX natural gas forward prices as of September 30, 2004 to the quantity of our natural 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):


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:
Swap transactions	$	(1,561	)	$	(368	)	$	(2,765	)
Collar arrangements		(1,184	)		(734	)		(1,642	)
Oil:
Swap transactions		(2,156	)		(308	)		(4,523	)
Collar arrangements		(2,702	)		788			(7,536	)

Total	$	(7,603	)	$	(622	)	$	(16,466	)

The fair value of our commodity price risk management positions in fixed price swap contracts and collar arrangements using an average natural gas forward price of $9.14 and an average oil forward price of $48.78 as of November 3, 2004 was a net liability of approximately $11.8 million, not including October and November 2004 settlements that resulted in a net loss of $2.0 million. The following are our commodity price risk management positions in fixed price swap contracts and collar arrangements as of
November 3, 2004:

Natural Gas


	Fixed Price Swaps			Collars
	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
Fourth Quarter 2004	8,370	$	4.92	18,370	$	4.73	$	6.56
First Quarter 2005	20,000		7.76	—		—		—

Oil

	Fixed Price Swaps			Collars
	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
Fourth Quarter 2004	1,000	$	42.86	1,000	$	40.00	$	50.25
Calendar 2005	1,000		40.34	3,000		38.67		44.73

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 Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and 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 September 30, 2004. During the three months ended September 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.

PART II - OTHER INFORMATION

Item 6.

Exhibits and Reports on Form 8-K

(a)

Exhibits

See “Exhibit Index.”

(b)

Reports on Form 8-K

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

A Current Report on Form 8-K dated August 3, 2004 and furnished on August 10, 2004 announced the appointment of Walter R. Arnheim as a new Director pursuant to Item 9, “Regulation FD Disclosure.”

A Current Report on Form 8-K dated September 28, 2004 and furnished on September 28, 2004 provided an update on recent commodity risk management positions pursuant to Item 7.01, “Regulation FD Disclosure.”

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

Date: November 5, 2004	By:	/s/ ROBERT M. SNELL
		Robert M. Snell
		Vice President, Chief Financial
		Officer and Secretary



Date: November 5, 2004	By:	/s/ JEFFREY C. ZARUBA
		Jeffrey C. Zaruba
		Vice President, Treasurer and
		Assistant Secretary

EXHIBIT INDEX


Exhibit Number		Description

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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