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                      SECURITIES AND EXCHANGE COMMISSION
                            Washington, D.C. 20549

                               -----------------

                                   FORM 10-K

[X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
    Act of 1934 for the fiscal year ended December 31, 2001.

[_] 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     (I.R.S. Employer
           incorporation or organization)     Identification No.)

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

                                (713) 759-1770
             (Registrant's telephone number, including area code)

   Securities registered pursuant to Section 12(b) of the Securities Exchange
Act of 1934:

                                               Name of each exchange on
                 Title of each class               which registered
                 -------------------               ----------------
       Common Stock, par value $0.01 per share  New York Stock Exchange

   Securities registered pursuant to Section 12(g) of the Act: None

   Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X]  No [_]

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

   The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant on March 7, 2002 was approximately
$839,135,000.

   The number of shares outstanding of the registrant's Common Stock, par value
$0.01 per share, on March 7, 2002 was 27,375,118.

   Parts of the registrant's Definitive Proxy Statement for its 2002 Annual
Meeting of Stockholders are incorporated by reference to Part III of this
annual report on Form 10-K.

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                               TABLE OF CONTENTS

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                                              PART I
Item 1.  Business.............................................................................   1
Item 2.  Properties...........................................................................  14
Item 3.  Legal Proceedings....................................................................  17
Item 4.  Submission of Matters to a Vote of Security Holders..................................  17

                                              PART II
Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters................  18
Item 6.  Selected Financial Data..............................................................  19
Item 7.  Management's Discussion and Analysis of Financial Condition and Results of Operations  20
Item 7A. Quantitative and Qualitative Disclosures About Market Risk...........................  34
Item 8.  Financial Statements and Supplementary Data..........................................  35
Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.  36

                                             PART III
Item 10. Directors and Executive Officers of the Registrant...................................  36
Item 11. Executive Compensation...............................................................  36
Item 12. Security Ownership of Certain Beneficial Owners and Management.......................  36
Item 13. Certain Relationships and Related Transactions.......................................  36

                                              PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.....................  36

Signatures....................................................................................  37
</TABLE>

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   Spinnaker Exploration Company ("Spinnaker" or the "Company") has provided
definitions for some of the natural gas and oil industry terms used in this
report in the "Glossary of Natural Gas and Oil Terms" on page 12.

             Cautionary Statement About Forward-Looking Statements

   Some of the information in this annual report on Form 10-K 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
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;
  .  natural gas and oil reserves;
  .  timing and amount of future production of natural gas and oil;
  .  operating costs and other expenses;
  .  cash flow and anticipated liquidity;
  .  prospect development and property acquisitions; and
  .  marketing of natural gas and oil.

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

  .  the risks associated with exploration;
  .  the ability to find, acquire, market, develop and produce new properties;
  .  natural gas and oil price volatility;
  .  uncertainties in the estimation of proved reserves and in the projection
     of future rates of production and timing of development expenditures;
  .  operating hazards attendant to the natural gas and oil business;
  .  downhole drilling and completion risks that are generally not recoverable
     from third parties or insurance;
  .  potential mechanical failure or under-performance of significant wells;
  .  climatic conditions;
  .  availability and cost of material and equipment;
  .  delays in anticipated start-up dates;
  .  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 annual
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 under "Risk Factors" in "Item
7. Management's Discussion and Analysis of Financial Conditions and Results of
Operations."

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                                    PART I

Item 1.  Business

General

   Spinnaker Exploration Company is an independent energy company engaged in
the exploration, development and production of natural gas and oil in the U.S.
Gulf of Mexico ("Gulf of Mexico"). At December 31, 2001, the Company had
license rights to approximately 11,700 blocks of mostly contiguous, recent
vintage 3-D seismic data in the Gulf of Mexico, including approximately 5,700
blocks from its 3-D seismic data agreement ("Data Agreement") with Petroleum
Geo-Services ASA ("PGS"). This database covers an area of approximately 39
million acres, which the Company believes is one of the largest recent vintage
3-D seismic databases of any independent exploration and production company in
the Gulf of Mexico. The Company considers recent vintage 3-D seismic data to be
data that was generated since 1990. As of December 31, 2001, the Company had
284 leasehold interests located in Texas state and federal waters covering
approximately 1,127,000 gross and 629,000 net acres. The Company believes its
regional 3-D seismic approach allows it to create and maintain a large
inventory of high-quality prospects and provides the opportunity to enhance its
exploration success and efficiently deploy its capital resources. The Company
also believes its license rights to large quantities of high-quality seismic
data and its management and technical staff are important factors for its
current and future success.

   Spinnaker's Chief Executive Officer, PGS and Warburg, Pincus Ventures, L.P.
("Warburg") formed Spinnaker in December 1996. From inception through December
31, 2001, the Company participated in drilling 94 wells in the Gulf of Mexico,
with 56 of these wells being completed as discoveries. As of December 31, 2001,
Ryder Scott Company, L.P. estimated the Company's net proved reserves at
approximately 323.2 Bcfe, 54 percent of which was natural gas, representing an
increase of 77 percent over estimated net proved reserves of 182.7 Bcfe at
December 31, 2000. Average daily production in 2001 increased 76 percent to 145
MMcfe from 82 MMcfe in 2000. Within its current inventory of 284 leasehold
interests, the Company has identified 94 exploratory prospects or leads. The
Company expects to drill approximately 35 of these prospects during 2002. Based
on 3-D seismic analysis on blocks where it currently has no leasehold interest,
the Company also has identified over 200 leads that may result in additional
prospects. The capital expenditure budget for 2002 includes approximately $250
million for exploration, development, leasehold acquisitions and other capital
expenditures.

   During 2001, Spinnaker participated in a significant deep water oil
discovery on Green Canyon Blocks 338/339 ("Front Runner") with a 25 percent
non-operator working interest. The Company participated in five consecutive
successful wells and sidetracks in testing the reservoirs on these blocks. This
significant oil discovery has changed Spinnaker's reserve profile. Proved oil
and condensate reserves were 46 percent of total proved reserves at December
31, 2001 compared to 10 percent at December 31, 2000. Of the Company's total
proved reserves as of December 31, 2001, 73 percent were proved undeveloped
reserves. Front Runner represented more than 50 percent of total proved
undeveloped reserves. Spinnaker has incurred capital expenditures associated
with Front Runner of approximately $30 million through December 31, 2001 and
expects to incur an aggregate of approximately $110 million in future
development costs during 2002 and 2003. First production is anticipated during
2004.

   On September 28, 1999, the Company priced its initial public offering of
8,000,000 shares of common stock, par value $0.01 per share ("Common Stock"),
at $14.50 per share. After payment of underwriting discounts and commissions,
the Company received net proceeds of $108.7 million on October 4, 1999. With a
portion of the proceeds, the Company retired all then outstanding debt of $72.0
million. In connection with the initial public offering, the Company converted
all outstanding Series A Convertible Preferred Stock, par value $0.01 per share
("Preferred Stock"), into shares of Common Stock, and certain shareholders
reinvested preferred dividends payable of $16.3 million into shares of Common
Stock. On August 16, 2000, the Company completed a public offering of 5,600,000
shares of Common Stock at $26.25 per share. After payment of underwriting

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discounts and commissions, the Company received net proceeds of $138.9 million.
With a portion of the proceeds, the Company retired all then outstanding debt
of $17.0 million. On December 20, 2000, PGS sold its 5,388,743 shares of Common
Stock at $29.25 per share. PGS' sale of its shares of Common Stock had no
effect on the Data Agreement.

Business Strategy

   Spinnaker's goals are to expand its reserve base, cash flow and net income
and to generate an attractive return on capital. The Company emphasizes the
following elements in its strategy to achieve these goals:

  .  Focus on the Gulf of Mexico

  .  Maintain a large database of 3-D seismic data

  .  Employ a rigorous prospect selection process

  .  Emphasize technical expertise

  .  Sustain a balanced, diversified exploration effort

  .  Maintain a conservative balance sheet.

   Focus on the Gulf of Mexico.  Spinnaker has assembled a large 3-D seismic
database and focuses its exploration activities in the Gulf of Mexico because
it believes this area represents one of the most attractive exploration regions
in North America. The Gulf of Mexico has the following characteristics that
make it attractive to exploration and production companies:

  .  Prolific exploration and production history

  .  Access to acreage

  .  Existing oilfield service infrastructure

  .  Attractive taxation and royalty rates

  .  Relatively high-productivity wells

  .  Transportation infrastructure with geographic proximity to well-developed
     markets for natural gas and oil

  .  Geologic diversity that offers a variety of exploration opportunities.

   The Company also believes its geographic focus provides an excellent
opportunity to develop and maintain competitive advantages through the
combination of its 3-D seismic database and regional exploration and operating
expertise.

   Maintain a large database of 3-D seismic data.  Spinnaker believes its large
database of 3-D seismic data allows it to generate and maintain a large
inventory of high-quality exploratory prospects. The Company's 3-D seismic
database serves as the foundation for its exploration program. The Company will
continue to supplement this database with 3-D seismic data acquisitions from
various seismic data vendors.

   Employ a rigorous prospect selection process.  Spinnaker uses its large
inventory of contiguous areas of 3-D seismic data to select prospects by tying
regional 3-D seismic analysis to actual drilling results. Through this process,
the Company enhances its understanding of the geology before selecting
prospects and increases the probability of accurately identifying
hydrocarbon-bearing zones.

   Emphasize technical expertise.  Spinnaker's 15 explorationists have an
average of over 20 years experience in exploration in the Gulf of Mexico. In
its efforts to attract and retain explorationists, the Company offers an
entrepreneurial culture, an extensive 3-D seismic database, state-of-the-art
computer-aided exploration technology and other technical tools.

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   As Spinnaker has matured, it has retained larger working interests in
prospects located in water depths of less than 2,000 feet. The combination of
larger working interests and its technical expertise has allowed the Company to
act as the operator for an increasing number of these prospects, providing more
control of costs, the timing and amount of capital expenditures and the
selection of technology.

   Sustain a balanced, diversified exploration effort by maintaining a
conservative balance sheet.  Spinnaker believes that its exploration approach
results in portfolio balance and diversity among:

  .  shallow water, or water depths of less than 600 feet, and deep water
     prospects;

  .  shallow drilling depth prospects and deep drilling depth prospects; and

  .  lower-risk, lower-potential prospects and higher-risk, higher-potential
     prospects.

   The broad coverage of the Gulf of Mexico of the Company's 3-D seismic data
allows it to participate in a variety of geologically diverse exploration
opportunities and create a diversified prospect portfolio. The Company intends
to manage its exposure in deep water exploration activities by focusing on
prospects where commercial feasibility of the prospect can be evaluated with a
small number of wells and where it believes 3-D seismic analysis provides
attractive risk/reward benefits. The Company also strives to diversify its
exploration efforts by seeking to limit the budgeted amount of the leasehold
acquisition and drilling costs of the first exploratory well on any one
prospect to less than 10 percent of the annual capital budget.

   The Company believes that maintaining continuity in its exploration activity
during all phases of the commodity price cycles is an important element to
balance and diversification. By positioning the Company to have a continuous
exploration program, it can potentially take advantage of reduced competition
for prospects and lower drilling and other oilfield service costs during
periods of low natural gas and oil prices. Spinnaker's emphasis on maintaining
a lower debt-to-capitalization ratio than many of its peers has enhanced its
ability to pursue this strategy.

PGS Data Agreement

  Data Covered by the Data Agreement

   Subject to the exceptions discussed below, the Company is entitled to
receive and use all of PGS' standard and enhanced multi-client 3-D seismic data
covering the Gulf of Mexico including its bays, channels, tributaries,
estuaries and transition zones that PGS acquires or processes for itself prior
to March 31, 2002 or is in the process of acquiring or processing as of that
date.

   As part of its business activities, PGS acquires both proprietary and
multi-client marine seismic data. When PGS acquires proprietary data, it does
so on an exclusive contractual basis for its customers. In this case, PGS
simply provides acquisition services. When PGS acquires multi-client data,
however, it owns the data itself and transfers the possession and use of copies
of this data to the industry at large. The Company is entitled to receive only
multi-client data from PGS.

   Standard data is the basic 3-D, post-stack time-migrated seismic data, and
dragged array and vertical cable data provided as the standard product to PGS'
3-D seismic survey customers. Enhanced data is data created through additional
computer processing of PGS' standard data. Enhanced data includes processed
data referred to as pre-stack depth migrated data, 3-D amplitude versus offset
processing and refined pre-stack time-migrated data. The Company has license
rights to approximately 4,200 blocks of standard data and 1,500 blocks of
enhanced data under the Data Agreement.

   PGS markets Gulf of Mexico seismic data through seismic data marketing
vendors. The Company has entered into agreements with some of these marketing
vendors who modify, to some extent, the Company's rights under the Data
Agreement. Material modifications of the Company's rights resulting from these
agreements are noted below.

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  Rights to Use the Data

   The Company may use the data received under the Data Agreement as follows:

  .  for its internal needs, including using the data in connection with the
     drilling of wells or the acquiring of interests in natural gas or oil
     properties;

  .  to make maps and other work products from the data;

  .  to make the data and work product available to the Company's consultants
     and contractors for interpretation, analysis, evaluation, mapping and
     additional processing; provided that the data and work product, other than
     maps, may not be removed from its premises and must be held in confidence
     by those individuals; and

  .  to show data and work products to prospective and existing investors and
     participants in farm-outs and exploration or development groups for the
     sole purpose of evaluating their participation in such ventures; provided
     that the data and work product, other than maps, may not be removed from
     its premises and must be held in confidence by those individuals.

   The Data Agreement provides that the Company's rights to use data are
perpetual subject to the termination provisions discussed below. However, the
Company's related agreements with PGS' marketing vendors provide that its
rights terminate automatically after 25 years. The data the Company receives
under the Data Agreement remains the property of PGS subject to the rights
granted to the Company in the Data Agreement.

  Restrictions on Transfer and Assignment

   The Company has the limited right to transfer a copy of standard or enhanced
data to a qualified transferee. The Company may also assign its rights under
the Data Agreement, directly or by merger, to a successor to all or
substantially all of its business or assets or the business or assets of
Spinnaker Exploration Company, L.L.C., the Company's principal subsidiary, as
long as the successor is not a PGS competitor. A PGS competitor is a company
that provides 3-D marine seismic data in the Gulf of Mexico as a significant
part of its business or an affiliate of such company. If the successor to the
Company's business or assets is not a PGS major customer, then that successor
may in turn transfer the rights under the Data Agreement to a successor of all
of its business or assets as long as that successor is not a PGS competitor. A
PGS major customer is a customer that has purchased from PGS products and
services at least equal to 7.5 percent of PGS' prior twelve months gross
receipts for all seismic data sales and related services in the Gulf of Mexico
or an affiliate of that customer. No other transfers of rights under the Data
Agreement by the Company or its successors are permitted. In addition, one of
the Company's agreements with a PGS marketing vendor provides that it may not
assign its rights to PGS data marketed by that vendor without the consent of
that vendor.

  Termination Events

   PGS may terminate substantially all of the Company's rights under the Data
Agreement by giving Spinnaker notice after any of the following events:

  .  the Company transfers data or its rights under the Data Agreement in
     violation of the Data Agreement;

  .  a PGS competitor acquires control of the Company or its principal
     subsidiary;

  .  a PGS major customer acquires control of the Company or its principal
     subsidiary after another PGS major customer has previously acquired
     control of the Company or its principal subsidiary;

  .  the Company knowingly breaches one of the provisions of the Data Agreement
     relating to the use, transfer or disclosure of the data and the breach
     results in significant damages to PGS;

  .  the Company unknowingly breaches one of these provisions of the Data
     Agreement, the breach results in significant damages to PGS and the
     Company fails to diligently prevent a subsequent breach after it receives
     notice of the first breach;

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  .  the Company commits a material breach of one of the other provisions of
     the Data Agreement and fails to remedy the breach within 90 days after
     notice to the Company; or

  .  the Company commences a voluntary bankruptcy or similar proceeding or an
     involuntary bankruptcy or similar proceeding is commenced against the
     Company and remains un-dismissed for 30 days.

  Additional Services

   Under the Data Agreement, the Company has access to 3-D seismic data until
March 31, 2003 through the proprietary high technology data archival and
retrieval system of PGS Data Management Inc.

   The Company has agreed to purchase $2.0 million of seismic-related services
from PGS prior to December 31, 2002. Through December 31, 2001, the Company
paid PGS a total of approximately $1.3 million for these services. Spinnaker
expects to purchase additional seismic-related services for the remaining
commitment under the Data Agreement during 2002.

Use of Computer-Aided Exploration Technology

   Computer-aided exploration is the process of using a computer workstation
and common database to accumulate and analyze seismic, production and other
data regarding a geographic area. In general, computer-aided exploration
involves accumulating various 2-D and 3-D seismic data with respect to a
potential drilling location and correlating that data with historical well
control and production data from similar properties. The available data is then
analyzed using computer software and modeling techniques to project the likely
geologic setting of a potential drilling location and potential locations of
undiscovered natural gas and oil reserves. This process relies on a comparison
of actual data for the potential drilling location and historical data for the
density and sonic characteristics of different types of rock formations,
hydrocarbons and other subsurface minerals, resulting in a projected 3-D image
of the subsurface. This modeling is performed through the use of advanced
interactive computer workstations and various combinations of available
computer software developed solely for this application.

   The Company has invested extensively in the advanced computer hardware and
software necessary for 3-D seismic exploration. As of December 31, 2001, the
Company had 23 workstations in-house to analyze seismic data. The Company's
explorationists can access a diverse software tool kit including modeling,
mapping, well path description, time slice analysis, pre- and post-stack
seismic processing, synthetic generation, fluid replacement studies and seismic
attribute analyses. Additionally, the Company has invested in direct-link
telecommunications technology that provides disk-to-disk downloading of data
volumes directly from PGS that allows very rapid loading on the Company's
in-house storage. This capability has benefited the Company when new data sets
are made available only a short time prior to state and federal lease sales.

Marketing

   The Company sells its natural gas and oil production under fixed or floating
market price contracts. Revenues, profitability, cash flow and future growth
depend substantially on prevailing prices for natural gas and oil. The prices
received by the Company for its natural gas and oil production fluctuates
widely. For example, natural gas prices declined significantly in 2001 from
levels reached in the second half of 2000 and early 2001. Prices for natural
gas and oil also declined significantly in 1998 and, for an extended period of
time, remained substantially below prices obtained in previous years. Among the
factors that can cause this fluctuation are the level of consumer product
demand, weather conditions, domestic and foreign governmental regulations, the
price and availability of alternative fuels, political conditions and actual or
threatened acts of war, terrorism or hostilities in natural gas and oil
producing regions, the domestic and foreign supply of natural gas and oil, the
price of foreign imports and overall economic conditions.

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   Decreases in the prices of natural gas and oil could adversely affect the
carrying value of proved reserves and revenues, profitability and cash flow.
Although the Company is not currently experiencing any significant involuntary
curtailment of natural gas or oil production, market, economic and regulatory
factors may in the future materially affect its ability to sell natural gas or
oil production. For the year ended December 31, 2001, sales to Enron North
America Corp., Tejas Gas Marketing, LLC, Reliant Energy Services, Inc. and
Bridgeline Gas Marketing LLC accounted for approximately 32 percent, 23
percent, 21 percent and 17 percent, respectively, of the Company's natural gas
and oil revenues, excluding the effects of hedging activities. For the year
ended December 31, 2000, sales to Enron North America Corp., Coral Energy
Resources, L.P. and Reliant Energy Services, Inc. accounted for approximately
61 percent, 11 percent and 11 percent, respectively, of the Company's natural
gas and oil revenues, excluding the effects of hedging activities. For the year
ended December 31, 1999, sales to Columbia Energy Services and Cokinos Energy
Corporation were 68 percent and 32 percent, respectively, of the Company's
natural gas and oil revenues, excluding the effects of hedging activities.
Spinnaker no longer sells its natural gas and oil production to Enron North
America Corp. Spinnaker believes the loss of this customer has not materially
affected its ability to market its natural gas and oil production.

   Customers purchase all of the Company's natural gas production at current
market prices. The terms of the arrangements require the customers to pay the
Company within 60 days after delivery of the production. As a result, if the
customers were to default on their payment obligations to the Company,
near-term earnings and cash flows would be adversely affected. However, due to
the availability of other markets and pipeline connections, the Company does
not believe that the loss of these customers or any other customers would
adversely affect its ability to market production.

   Spinnaker enters into hedging arrangements from time to time to reduce its
exposure to fluctuations in natural gas and oil prices and to achieve more
predictable cash flow. However, these contracts also limit the benefits the
Company would realize if prices increase. These financial arrangements take the
form of swap contracts or costless collars and are placed with major trading
counterparties the Company believes represent minimum credit risks. Spinnaker
cannot provide assurance that these trading counterparties will not become
credit risks in the future. For further information concerning Spinnaker's
hedging transactions, see "Item 7A. Quantitative and Qualitative Disclosures
about Market Risk." Under its current hedging policy, the Company generally
does not hedge more than 66 2/3 percent of its estimated twelve-month
production quantities without the prior approval of the risk management
committee of the board of directors.

   The Company had in place both financial hedge and physical contracts with
Enron North America Corp., a subsidiary of Enron Corp., at the time it filed
for bankruptcy in December 2001. Spinnaker did not receive payment for fixed
price swap contracts totaling $2.1 million, intended to hedge December 2001
natural gas sales, and $1.4 million related to November 2001 natural gas
production sold to Enron entities. The Company recorded a net reserve of $3.1
million related to these receivables and has no other exposure to Enron Corp.
and its subsidiaries.

Competition

   The Company competes with major and independent natural gas and oil
companies for leasehold acquisitions. Spinnaker also competes for the equipment
and labor required to operate and develop these properties. Most of the
Company's competitors have substantially greater financial and other resources.
As a result, in the deep water where exploration is more expensive, competitors
may be better able to withstand sustained periods of unsuccessful drilling. In
addition, larger competitors may be able to absorb the burden of any changes in
federal, state and local laws and regulations more easily than Spinnaker can,
which would adversely affect its competitive position. These competitors may be
able to pay more for exploratory prospects and productive natural gas and oil
properties and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than the Company can. The Company's ability
to explore for natural gas and oil prospects and to acquire additional
properties in the future will depend upon its ability to conduct operations, to
evaluate and select suitable properties and to consummate transactions in this
highly competitive environment. In addition, most of the Company's competitors
have been operating in the Gulf of Mexico for a much longer time than the
Company has and have demonstrated the ability to operate through industry
cycles.

                                      6

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Regulation

  Federal Regulation of Sales and Transportation of Natural Gas

   Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of
1938, the Natural Gas Policy Act of 1978 and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission ("FERC"). In the past,
the federal government has regulated the prices at which natural gas could be
sold. Deregulation of natural gas sales by producers began with the enactment
of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural
Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of 1938
and Natural Gas Policy Act of 1978 price and non-price controls affecting
producer sales of natural gas effective January 1, 1993. Congress could,
however, re-enact price controls in the future.

   The Company's sales of natural gas are affected by the availability, terms
and cost of pipeline transportation. The price and terms for access to pipeline
transportation remain subject to extensive federal regulation. Commencing in
April 1992, the FERC issued Order No. 636 and a series of related orders that
required interstate pipelines to provide open-access transportation on a basis
that is equal for all natural gas suppliers. The FERC has stated that it
intends for Order No. 636 and its future restructuring activities to foster
increased competition within all phases of the natural gas industry. Although
Order No. 636 does not directly regulate the Company's production and marketing
activities, it does affect how buyers and sellers gain access to the necessary
transportation facilities and how the Company and its competitors sell natural
gas in the marketplace. The courts have largely affirmed the significant
features of Order No. 636 and the numerous related orders pertaining to
individual pipelines, although some appeals remain pending and the FERC
continues to review and modify its regulations regarding the transportation of
natural gas. For example, the FERC issued Order No. 637 and a series of related
orders which, among other things, (i) lift the cost-based cap on pipeline
transportation rates in the capacity release market until September 30, 2002,
for short-term releases of pipeline capacity of less than one year, (ii) permit
pipelines to charge different maximum cost-based rates for peak and off-peak
periods, (iii) encourage, but do not mandate, auctions for pipeline capacity,
(iv) require pipelines to implement imbalance management services, (v) restrict
the ability of pipelines to impose penalties for imbalances, overruns and
non-compliance with operational flow orders, and (vi) implement a number of new
pipeline reporting requirements. Order No. 637 and various related orders have
been challenged in federal court. The Company cannot predict whether the
federal courts will uphold Order No. 637 and the related orders or what further
action FERC may take on these matters. In addition, the FERC implemented new
regulations governing the procedure for obtaining authorization to construct
new pipeline facilities and has issued a policy statement, which it largely
affirmed in recent orders on rehearing, establishing a presumption in favor of
requiring owners of new pipeline facilities to charge rates based solely on the
costs associated with such new pipeline facilities. The Company cannot predict
what further action the FERC will take on these matters, nor can it accurately
predict whether the FERC's actions will achieve the goal of increasing
competition in markets in which natural gas is sold. However, the Company does
not believe that any action taken will affect it in a way that materially
differs from the way it affects other natural gas producers, gatherers and
marketers.

   The Outer Continental Shelf Lands Act ("OCSLA") requires that all pipelines
operating on or across the Outer Continental Shelf provide open-access,
non-discriminatory service. Although the FERC has opted not to impose the
regulations of Order No. 509, in which the FERC implemented the OCSLA, on
gatherers and other non-jurisdictional entities, the FERC has retained the
authority to exercise jurisdiction over those entities if necessary to permit
non-discriminatory access to service on the Outer Continental Shelf. The FERC
recently issued Order No. 639, requiring that virtually all non-proprietary
pipeline transporters of natural gas on the Outer Continental Shelf report
information on their affiliations, rates and conditions of service. Among the
FERC's stated purposes in issuing such rules was the desire to provide shippers
on the Outer Continental Shelf with greater assurance of open-access services
on pipelines located on the Outer Continental Shelf and non-discriminatory
rates and conditions of service on such pipelines. A federal district court
recently determined that FERC has exceeded its statutory authority in
promulgating Order Nos. 639 and 639-A, and the court permanently enjoined FERC
from enforcing the orders. FERC has indicated that it will appeal the district
court's decision.

                                      7

<PAGE>

   Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.

  Federal Leases

   A substantial portion of the Company's operations is located on federal
natural gas and oil leases, which are administered by the Minerals Management
Service ("MMS"). Such leases are issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the OCSLA that are subject to interpretation
and change by the MMS. For offshore operations, lessees must obtain MMS
approval for exploration plans and development and production plans prior to
the commencement of such operations. In addition to permits required from other
agencies such as the Coast Guard, the Army Corps of Engineers and the
Environmental Protection Agency, lessees must obtain a permit from the MMS
prior to the commencement of drilling. The MMS has promulgated regulations
requiring offshore production facilities located on the Outer Continental Shelf
to meet stringent engineering and construction specifications. The MMS also has
regulations restricting the flaring or venting of natural gas, and has proposed
to amend such regulations to prohibit the flaring of liquid hydrocarbons and
oil without prior authorization. Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore
and the installation and removal of all production facilities. To cover the
various obligations of lessees on the Outer Continental Shelf, the MMS
generally requires that lessees have substantial net worth or post bonds or
other acceptable assurances that such obligations will be met. The cost of
these bonds or other surety can be substantial, and there is no assurance that
bonds or other surety can be obtained in all cases. The Company is currently in
compliance with the bonding requirements of the MMS. Under some circumstances,
the MMS may require any of the Company's operations on federal leases to be
suspended or terminated. Any such suspension or termination could materially
adversely affect the Company's financial condition and results of operations.

   The MMS recently issued a final rule that amended its regulations governing
the calculation of royalties and the valuation of crude oil produced from
federal leases. This rule provides that the MMS will collect royalties based on
the market value of oil produced from federal leases. The lawfulness of the new
rule has been challenged in federal court. The Company cannot predict whether
this new rule will be upheld in federal court, nor can the Company predict
whether the MMS will take further action on this matter. The Company believes
this rule will not have a material impact on its financial condition, liquidity
or results of operations.

  State and Local Regulation of Drilling and Production

   The Company owns interests in properties located in the state waters of the
Gulf of Mexico offshore Texas and occasionally may conduct operations in the
state waters offshore Louisiana and Mississippi. These states regulate drilling
and operating activities by requiring, among other things, drilling permits and
bonds and reports concerning operations. The laws of these states also govern a
number of environmental and conservation matters, including the handling and
disposing of waste materials, unitization and pooling of natural gas and oil
properties and establishment of maximum rates of production from natural gas
and oil wells. Some states prorate production to the market demand for natural
gas and oil.

  Oil Price Controls and Transportation Rates

   Sales of crude oil, condensate and natural gas liquids by the Company are
not currently regulated and are made at market prices. The price the Company
receives from the sale of these products may be affected by the cost of
transporting the products to market. Effective as of January 1, 1995, the FERC
implemented regulations generally grandfathering all previously approved
interstate transportation rates and establishing an indexing system for those
rates by which adjustments are made annually based on the rate of inflation,
subject to certain conditions and limitations. These regulations have generally
been approved on judicial review. The FERC's

                                      8

<PAGE>

regulation of oil transportation rates may tend to increase the cost of
transporting oil and natural gas liquids by interstate pipeline, although the
annual adjustments may result in decreased rates in a given year. The Company
is unable at this time to predict the effects of these regulations, if any, on
the transportation costs associated with oil production from its properties.
However, the Company does not believe that these regulations affect it any
differently than other producers.

  Environmental Regulations

   The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise relating
to environmental protection. Public interest in the protection of the
environment has increased dramatically in recent years. Offshore drilling in
some areas has been opposed by environmental groups and, in some areas, has
been restricted. To the extent laws are enacted or other governmental action is
taken that prohibits or restricts offshore drilling or imposes environmental
protection requirements that result in increased costs to the natural gas and
oil industry in general and the offshore drilling industry in particular, the
Company's business and prospects could be adversely affected. In addition,
violation of such environmental laws and regulations can lead to the imposition
of administrative, civil or criminal penalties; remedial obligations; and
injunctive relief.

   The Oil Pollution Act of 1990 ("OPA") and regulations thereunder impose a
variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United
States waters. A "responsible party" includes the owner or operator of a
facility or vessel, or the lessee or permittee of the area in which an offshore
facility is located. The OPA assigns liability to each responsible party for
oil removal costs and a variety of public and private damages. While liability
limits apply in some circumstances, a party cannot take advantage of liability
limits if the spill was caused by gross negligence or willful misconduct or
resulted from violation of a federal safety, construction or operating
regulation. If the party fails to report a spill or to cooperate fully in the
cleanup, liability limits likewise do not apply. Even if applicable, the
liability limits for offshore facilities require the responsible party to pay
all removal costs, plus up to $75.0 million in other damages. Few defenses
exist to the liability imposed by the OPA.

   The OPA also requires a responsible party to submit proof of its financial
ability to cover environmental cleanup and restoration costs that could be
incurred in connection with an oil spill. As amended by the Coast Guard
Authorization Act of 1996, the OPA requires parties responsible for offshore
facilities to provide financial assurance in the amount of $35.0 million to
cover potential OPA liabilities. This amount can be increased up to $150.0
million if a study by the MMS indicates that an amount higher than $35.0
million should be required or if the volume of a worst-case scenario spill
could exceed certain regulatory thresholds. The Company is in compliance with
its financial assurance obligations.

   The OPA also imposes other requirements, such as the preparation of an oil
spill contingency plan. The Company has such a plan in place. The Company is
also regulated by the Clean Water Act and similar state laws. The Clean Water
Act prohibits any discharge into waters of the United States except in strict
conformance with permits issued by federal and state agencies. Failure to
comply with the ongoing requirements of these laws or inadequate cooperation
during a spill event may subject a responsible party to administrative, civil
or criminal enforcement actions.

   In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
Outer Continental Shelf. Specific design and operational standards may apply to
Outer Continental Shelf vessels, rigs, platforms, vehicles and structures.
Violations of lease conditions or regulations issued pursuant to the OCSLA can
result in substantial civil and criminal penalties, as well as potential court
injunctions curtailing operations and the cancellation of leases. Such
enforcement liabilities can result from either governmental or private
prosecution.

   The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, and analogous state laws impose
liability, without regard to fault or the legality of the

                                      9

<PAGE>

original conduct, on some classes of persons that are considered to have
contributed to the release of a "hazardous substance" into the environment.
These persons include the owner or operator of the disposal site or sites where
the release occurred and companies that disposed or arranged for the disposal
of the hazardous substances found at the site. Persons who are or were
responsible for releases of hazardous substances under the CERCLA may be
subject to joint and several liability for the costs of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources, and it is not uncommon for neighboring landowners
and other third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment.

   The Company's operations are also subject to regulation of air emissions
under the Clean Air Act, comparable state and local requirements and the OCSLA.
Future regulations under these laws could lead to the gradual imposition of new
air pollution control requirements on the Company's operations. Therefore, the
Company may incur capital expenditures over the next several years to upgrade
its air pollution control equipment. The Company does not believe that its
operations would be materially affected by any such requirements, nor does it
expect such requirements to be any more burdensome to it than to other
companies of its size involved in natural gas and oil exploration and
production activities.

   In addition, legislation has been proposed in Congress from time to time
that would reclassify some natural gas and oil exploration and production
wastes as "hazardous wastes," which would make the reclassified wastes subject
to much more stringent handling, disposal and clean-up requirements. If
Congress were to enact this legislation, it could increase the Company's
operating costs, as well as those of the natural gas and oil industry in
general.

   Management believes that the Company is in compliance with current
applicable environmental laws and regulations and that continued compliance
with existing requirements will not have a material adverse impact on its
results of operations.

Operating Hazards and Insurance

   The natural gas and oil business involves a variety of operating risks,
including fires, explosions, blow-outs and surface cratering, uncontrollable
flows of underground natural gas, oil and formation water, natural disasters,
pipe or cement failures, casing collapses, embedded oilfield drilling and
service tools, abnormally pressured formations and environmental hazards such
as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic
gases. If any of these events occur, the Company could incur substantial losses
as a result of injury or loss of life, severe damage to and destruction of
property, natural resources and equipment, pollution and other environmental
damage, clean-up responsibilities, regulatory investigation and penalties,
suspension of the Company's operations and repairs to resume operations. If the
Company experiences any of these problems, it could affect well bores,
platforms, gathering systems and processing facilities, which could adversely
affect its ability to conduct operations.

   As part of its strategy, the Company explores for natural gas and oil in the
deep waters of the Gulf of Mexico where operations are more difficult than in
shallower waters. The Company's deep water drilling and operations require the
application of recently developed technologies that involve a higher risk of
mechanical failure. Furthermore, the deep waters of the Gulf of Mexico lack the
physical and oilfield service infrastructure present in the shallower waters.
As a result, deep water operations may require a significant amount of time
between a discovery and the time that the Company can market the natural gas or
oil, increasing the risks involved with these operations.

   Offshore operations are also subject to a variety of operating risks
specific to the marine environment, such as capsizing, collisions and damage or
loss from hurricanes or other adverse weather conditions. These conditions can
cause substantial damage to facilities and interrupt production. As a result,
the Company could incur substantial liabilities that could reduce or eliminate
the funds available for exploration, development or leasehold acquisitions, or
result in loss of properties.


                                      10

<PAGE>

   In accordance with industry practice, the Company maintains insurance
against some, but not all, potential risks and losses. Management reviews
Spinnaker's coverage at least annually. For some risks, the Company may not
obtain insurance if it believes the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental risks
generally are not fully insurable. If a significant accident or other event
occurs and is not fully covered by insurance, it could adversely affect the
Company. Considering recent worldwide property and casualty events, the Company
anticipates increased costs to renew insurance in 2002.

Employees

   At December 31, 2001, the Company had 53 full-time employees. The Company
believes that it maintains excellent relationships with its employees. None of
the Company's employees is covered by a collective bargaining agreement. From
time to time, the Company uses the services of independent consultants and
contractors to perform various professional services, particularly in the areas
of construction, design, well-site surveillance, permitting and environmental
assessment. Independent contractors usually perform field and on-site
production operation services for the Company, including pumping, maintenance,
dispatching, inspection and testing.

                                      11

<PAGE>

                     GLOSSARY OF NATURAL GAS AND OIL TERMS

   The following is a description of the meanings of some of the natural gas
and oil industry terms used in this annual report.

   Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume, of crude oil
or other liquid hydrocarbons.

   Bcf.  Billion cubic feet of natural gas.

   Bcfe.  Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

   Block.  A block depicted on the Outer Continental Shelf Leasing and Official
Protraction Diagrams issued by the U.S. Minerals Management Service or a
similar depiction on official protraction or similar diagrams issued by a state
bordering on the Gulf of Mexico.

   Btu or British Thermal Unit.  The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.

   Completion.  The installation of permanent equipment for the production of
natural gas or oil, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.

   Condensate.  Liquid hydrocarbons associated with the production of a
primarily natural gas reserve.

   Developed acreage.  The number of acres that are allocated or assignable to
productive wells or wells capable of production.

   Development well.  A well drilled into a proved natural gas or oil reservoir
to the depth of a stratigraphic horizon known to be productive.

   Dry hole.  A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.

   Exploratory well.  A well drilled to find and produce natural gas or oil
reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of natural gas or oil in another reservoir or
to extend a known reservoir.

   Farm-in or farm-out.  An agreement under which the owner of a working
interest in a natural gas and oil lease assigns the working interest or a
portion of the working interest to another party who desires to drill on the
leased acreage. Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor usually retains a
royalty or reversionary interest in the lease. The interest received by an
assignee is a "farm-in" while the interest transferred by the assignor is a
"farm-out."

   Field.  An area consisting of either a single reservoir or multiple
reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.

   Gross acres or gross wells.  The total acres or wells, as the case may be,
in which a working interest is owned.

   Lead.  A specific geographic area which, based on supporting geological,
geophysical or other data, is deemed to have potential for the discovery of
commercial hydrocarbons.

   MBbls.  Thousand barrels of crude oil or other liquid hydrocarbons.

                                      12

<PAGE>

   Mcf.  Thousand cubic feet of natural gas.

   Mcfe.  Thousand cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

   MMBls.  Million barrels of crude oil or other liquid hydrocarbons.

   MMBtu.  Million British Thermal Units.

   MMcf.  Million cubic feet of natural gas.

   MMcfe.  Million cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

   Net acres or net wells.  The sum of the fractional working interest owned in
gross acres or wells, as the case may be.

   Productive well.  A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.

   Prospect.  A specific geographic area which, based on supporting geological,
geophysical or other data and also preliminary economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for the
discovery of commercial hydrocarbons.

   Proved developed non-producing reserves.  Proved developed reserves expected
to be recovered from zones behind casing in existing wells.

   Proved developed producing reserves.  Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.

   Proved developed reserves.  Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.

   Proved reserves.  The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.

   Proved undeveloped reserves.  Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.

   Reservoir.  A porous and permeable underground formation containing a
natural accumulation of producible natural gas and/or oil that is confined by
impermeable rock or water barriers and is separate from other reservoirs.

   Undeveloped acreage.  Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of natural gas and oil regardless of whether such acreage contains proved
reserves.

   Working interest.  The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and receive a
share of production.

                                      13

<PAGE>

Item 2.  Properties

   Since inception, the Company has concentrated on the exploration for natural
gas and oil in the Gulf of Mexico. As of December 31, 2001, proved reserves
associated with Spinnaker's discoveries were located on 30 different blocks,
including two properties in which the Company has only a royalty interest, with
production established from 19 blocks. Spinnaker operates 33 of its 56
discoveries, and the Company's working interests in these wells range from 12.5
percent to 100 percent. Five blocks account for approximately 73 percent of the
Company's total proved reserves.

   As of December 31, 2001, the Company had license rights to approximately
11,700 blocks of mostly contiguous, recent vintage 3-D seismic data in the Gulf
of Mexico, including approximately 5,700 blocks associated with the Data
Agreement. This database covers an area of approximately 39 million acres,
which the Company believes is one of the largest recent vintage 3-D seismic
databases of any independent exploration and production company in the Gulf of
Mexico. As of December 31, 2001, the Company had 284 leasehold interests
located in Texas state and federal waters covering approximately 1,127,000
gross and 629,000 net acres.

Natural Gas and Oil Reserves

   During 2001, Spinnaker participated in a significant deep water oil
discovery, Front Runner, with a 25 percent non-operator working interest. The
Company participated in five consecutive successful wells and sidetracks in
testing the reservoirs on these blocks. This significant oil discovery has
changed Spinnaker's reserve profile. Proved oil and condensate reserves were 46
percent of total proved reserves at December 31, 2001 compared to 10 percent at
December 31, 2000. Of the Company's total proved reserves as of December 31,
2001, 73 percent were proved undeveloped reserves. Front Runner represented
more than 50 percent of total proved undeveloped reserves.

   The following table presents estimated net proved natural gas and oil
reserves and the net present value of the reserves at December 31, 2001 based
on a reserve report generated by Ryder Scott Company, L.P. The present value of
future net cash flows (before income taxes) discounted at 10 percent and the
standardized measure of discounted future net cash flows shown in the table are
not intended to represent the current market value of the estimated natural gas
and oil reserves Spinnaker owns. For further information concerning the present
value of future net cash flows associated with these proved reserves, see Note
14 of the Notes to Consolidated Financial Statements.

   The present value of future net cash flows and the standardized measure of
discounted future net cash flows as of December 31, 2001 was determined by
using prices of $2.71 per Mcf of natural gas and $19.23 per barrel of oil,
representing the December 31, 2001 weighted average market prices for natural
gas and oil.

<TABLE>
<CAPTION>
                                                                    Proved Reserves
                                                             ------------------------------
                                                             Developed Undeveloped  Total
                                                             --------- ----------- --------
<S>                                                          <C>       <C>         <C>
Natural gas (MMcf)..........................................   82,221     93,760    175,981
Oil and condensate (MBbls)..................................      748     23,790     24,538
Total proved reserves (MMcfe)...............................   86,711    236,496    323,207
Present value of future net cash flows (before income taxes)
  discounted at 10 percent (in thousands)(1)................ $167,298   $247,841   $415,139
Standardized measure of discounted future net cash flows (in
  thousands)(1)............................................. $132,809   $196,747   $329,556
</TABLE>
--------
(1) Excludes pre-tax unrealized gains of $22.3 million for the effects of
    hedging activities using natural gas and oil prices in effect at December
    31, 2001.

   The process of estimating natural gas and oil reserves is complex. It
requires various assumptions, including natural gas and oil prices, drilling
and operating expenses, capital expenditures, taxes and availability of funds.

                                      14

<PAGE>

The Company must project production rates and timing of development
expenditures. The Company analyzes available geological, geophysical,
production and engineering data, and the extent, quality and reliability of
this data can vary. Therefore, estimates of natural gas and oil reserves are
inherently imprecise.

   Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves most likely will vary from estimates. Any
significant variance could materially affect the estimated quantities and net
present value of reserves. In addition, the Company may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing natural gas and oil prices and other factors, many of
which are beyond the Company's control. At December 31, 2001, approximately 87
percent of the Company's proved reserves were either undeveloped or
non-producing. 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.

   At December 31, 2001, approximately 73 percent of the Company's proved
reserves were undeveloped. Recovery of undeveloped reserves generally requires
significant capital expenditures and successful drilling operations. The
reserve data assumes that the Company will make these expenditures. Although
the Company estimates its reserves and the costs associated with developing
them in accordance with industry standards, the estimated costs may be
inaccurate, development may 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 is
the current market value of the Company's estimated natural gas and oil
reserves. In accordance with requirements of the Securities and Exchange
Commission ("Commission"), the Company bases 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 estimate.

Volumes, Prices and Operating Expenses

   The following table presents information regarding the production volumes
of, average sales prices received for and average production costs associated
with Spinnaker's sales of natural gas and oil for the periods indicated:

<TABLE>
<CAPTION>
                                                              For the Year Ended December 31,
                                                              ------------------------------
                                                                2001        2000      1999
                                                              --------    --------  --------
<S>                                                           <C>         <C>       <C>
Production:
   Natural gas (MMcf)........................................   51,234      28,845    11,962
   Oil and condensate (MBbls)................................      310         225       180
       Total (MMcfe).........................................   53,094      30,194    13,044
Average sales price per unit:
   Natural gas revenues from production (per Mcf)............ $   4.14    $   4.62  $   2.49
   Effects of hedging activities (per Mcf)...................    (0.18)      (0.59)     0.08
                                                              --------    --------  --------
       Average price (per Mcf)............................... $   3.96    $   4.03  $   2.57

   Oil and condensate revenues from production (per Bbl)..... $  24.90    $  30.14  $  20.33
   Effects of hedging activities (per Bbl)...................       --       (7.16)    (0.57)
                                                              --------    --------  --------
       Average price (per Bbl)............................... $  24.90    $  22.98  $  19.76

   Total revenues from production (per Mcfe)................. $   4.14    $   4.64  $   2.57
   Effects of hedging activities (per Mcfe)..................    (0.18)      (0.62)     0.06
                                                              --------    --------  --------
       Total average price (per Mcfe)........................ $   3.96    $   4.02  $   2.63
Expenses (per Mcfe):
   Lease operating expenses(1)............................... $   0.23    $   0.30  $   0.41
   Depreciation, depletion and amortization--natural gas and
     oil properties.......................................... $   1.60    $   1.57  $   1.59
</TABLE>
--------

                                      15

<PAGE>

--------
(1) The lease operating expense rate includes $0.04 per Mcfe associated with
    workovers in 2001, $0.03 per Mcfe associated with workovers in 2000 and
    $0.13 per Mcfe associated with workovers and well control activities in
    1999.

Development, Exploration and Acquisition Capital Expenditures

   The following table presents information regarding Spinnaker's net costs
incurred in acquisition, exploration and development activities. 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 and costs of completions, platforms,
facilities and pipelines.

<TABLE>
<CAPTION>
                                         For the Year Ended December 31,
                                         -------------------------------
                                            2001       2000      1999
                                          --------   --------   -------
        <S>                              <C>        <C>        <C>
        Acquisition costs:
           Unproved..................... $ 34,524   $ 21,421   $13,911
           Proved.......................       --         --        --
        Exploration costs...............  192,114    121,451    45,152
        Development costs...............   75,882     51,144    23,614
                                          --------   --------   -------
               Total costs incurred..... $302,520   $194,016   $82,677
                                          ========   ========   =======
</TABLE>

Drilling Activity

   The following table shows Spinnaker's drilling activity. In the table,
"gross" refers to the total wells in which the Company has a working interest
and "net" refers to gross wells multiplied by the Company's working interest in
such wells.

<TABLE>
<CAPTION>
                                 For the Year En--ded December 31,
                                 ---------------------------------
                                     2001        2000      1999
                                 ------------ ---------- ---------
                                 Gross   Net  Gross Net  Gross Net
                                 -----  ----  ----- ---- ----- ---
              <S>                <C>    <C>   <C>   <C>  <C>   <C>
              Exploratory Wells:
                 Productive.....  17     8.2   16   10.4   8   4.6
                 Nonproductive..  16     9.4   12    4.7   4   1.9
                                  --    ----   --   ----  --   ---
                     Total......  33    17.6   28   15.1  12   6.5
                                  ==    ====   ==   ====  ==   ===
              Development Wells:
                 Productive.....   2     0.5   --     --  --    --
                 Nonproductive..  --      --   --     --  --    --
                                  --    ----   --   ----  --   ---
                     Total......   2     0.5   --     --  --    --
                                  ==    ====   ==   ====  ==   ===
</TABLE>

   In 1999, the Company drilled an exploratory well that was preliminarily
determined to be unsuccessful and was temporarily abandoned. Upon reprocessing
of the seismic data, further analysis of the well and related sidetrack and
examination of proved category reserves, the Company determined that the
development would be commercial, and the well was reclassified as a discovery
in 2000.

                                      16

<PAGE>

   Since December 31, 2001 and through March 7, 2002, the Company has drilled
two gross (0.9 net) productive exploratory wells and one gross (0.2 net)
nonproductive exploratory well. As of March 7, 2002, the Company was drilling
five gross (2.5 net) exploratory wells and one gross (0.3 net) development well.

Productive Wells

   The following table sets forth the number of productive natural gas and oil
wells in which Spinnaker owned an interest as of December 31, 2001:

<TABLE>
<CAPTION>
                                           Total
                                         Productive
                                           Wells
                                         ----------
                                         Gross Net
                                         ----- ----
                             <S>         <C>   <C>
                             Natural gas  50   26.5
                             Oil........   6    1.6
                                          --   ----
                                Total...  56   28.1
                                          ==   ====
</TABLE>

   Productive wells consist of producing wells and wells capable of production,
including natural gas wells awaiting pipeline connections to commence
deliveries and oil wells awaiting connection to production facilities.

Acreage Data

   The following table presents information regarding developed and undeveloped
lease acreage. Developed acreage refers to acreage within producing units and
undeveloped acreage refers to acreage that has not been placed in producing
units. Spinnaker's developed and undeveloped lease acreage as of December 31,
2001 was as follows (in thousands):

<TABLE>
<CAPTION>
                                         Developed Undeveloped
                                          Acreage    Acreage     Total
                                         --------- ----------- ---------
                                         Gross Net Gross  Net  Gross Net
                                         ----- --- -----  ---  ----- ---
       <S>                               <C>   <C> <C>    <C>  <C>   <C>
       Federal Waters Offshore Louisiana   55  27    544  263    599 290
       Federal Waters Offshore Texas....   52  32    427  287    479 319
       Texas State Waters...............   14   5     35   15     49  20
                                          ---  --  -----  ---  ----- ---
          Total.........................  121  64  1,006  565  1,127 629
                                          ===  ==  =====  ===  ===== ===
</TABLE>

   The Company's lease agreements generally terminate if wells have not been
drilled on the acreage within a period of five years from the date of the lease
if located on the shelf in less than 200 meters of water or ten years if
located in deeper waters of the Gulf of Mexico.

Item 3.  Legal Proceedings

   From time to time, the Company may be a party to various legal proceedings.
The Company currently is not a party to any material litigation.

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

   The Company did not hold a meeting of stockholders or otherwise submit any
matter to a vote of stockholders in the fourth quarter of 2001.

                                      17

<PAGE>

                                    PART II

Item 5.  Market for Registrant's Common Equity and Related Stockholder Matters

   Spinnaker's Common Stock began trading on the New York Stock Exchange on
July 26, 2000 under the symbol "SKE." Prior to that date, Spinnaker's Common
Stock traded on The Nasdaq National Market under the symbol "SPNX." The
following table sets forth the range of high and low sales prices per share of
Common Stock for each calendar quarter.

<TABLE>
<CAPTION>
                                                       Sales Price
                                                      -------------
                                                       High   Low
                                                      ------ ------
            <S>                                       <C>    <C>

            2000:
               First Quarter......................... $25.00 $13.25
               Second Quarter........................ $30.50 $19.50
               Third Quarter......................... $42.25 $24.03
               Fourth Quarter........................ $44.00 $24.75

            2001:
               First Quarter......................... $44.50 $33.00
               Second Quarter........................ $48.00 $36.60
               Third Quarter......................... $43.96 $30.00
               Fourth Quarter........................ $45.55 $33.30
            2002:
               First Quarter (through March 7, 2002). $41.87 $34.45
</TABLE>

   On March 7, 2002, the closing sale price of Spinnaker's Common Stock, as
reported by the New York Stock Exchange, was $41.10 per share. On that date,
there were 40 holders of record.

   The Company has never declared or paid any dividends on its Common Stock.
The Company currently intends to retain future earnings, if any, for the
operation and development of its business and does not anticipate paying any
dividends on its Common Stock in the foreseeable future. In addition, the
Company's $200.0 million credit agreement ("Credit Facility") prohibits it from
paying cash dividends on its Common Stock. For a description of the covenants
and restrictive provisions in the Credit Facility, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources--Financing Activities" and Note 3 of the Notes to
Consolidated Financial Statements. Any future dividends may also be restricted
by any loan agreements the Company may enter into from time to time.

   At December 31, 2001, officers, directors and employees had been granted
options to purchase Common Stock under stock plans adopted in 1998, 1999, 2000
and 2001. The following table provides information related to the Company's
current equity compensation plans:

<TABLE>
<CAPTION>
                                                                                                Number of
                                                        Number of                          securities remaining
                                                    securities to be                          available for
                                                       issued upon      Weighted-average     future issuance
                                                       exercise of      exercise price of      under equity
                  Plan category                    outstanding options outstanding options  compensation plans
                  -------------                    ------------------- ------------------- --------------------
<S>                                                <C>                 <C>                 <C>
Equity compensation plans approved by security
  holders.........................................      3,628,795            $20.92              582,716
Equity compensation plans not approved by security
  holders.........................................        433,761            $31.83               65,829
                                                        ---------                                -------
   Total..........................................      4,062,556            $22.08              648,545
                                                        =========                                =======
</TABLE>

                                      18

<PAGE>

Item 6.  Selected Financial Data

   The following table sets forth some of the Company's historical consolidated
financial data. The following data should be read in conjunction with "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements and Notes thereto
included elsewhere herein. The selected consolidated financial data provided
below are not necessarily indicative of the future results of operations or
financial performance of the Company.

<TABLE>
<CAPTION>
                                                                                 Year Ended December 31,
                                                                     -----------------------------------------------
                                                                       2001      2000      1999      1998     1997
                                                                     --------  --------  --------  --------  -------
                                                                          (in thousands, except per share data)
<S>                                                                  <C>       <C>       <C>       <C>       <C>
Statement of Operations Data:
Revenues............................................................ $210,376  $121,383  $ 34,258  $  3,298  $   201
Expenses:
    Lease operating expenses........................................   12,132     9,009     5,411       474       72
    Depreciation, depletion and amortization--natural gas and oil
     properties.....................................................   85,059    47,451    20,788     2,738       68
    Depreciation and amortization--other............................      398       309       213       437      349
    Write-down of natural gas and oil properties(1).................       --        --        --     2,642       --
    General and administrative......................................    9,443     7,350     4,860     3,809    1,965
    Charges related to Enron bankruptcy(2)..........................    3,059        --        --        --       --
    Stock appreciation rights expense(3)............................       --        --     1,651        --       --
                                                                     --------  --------  --------  --------  -------
       Total expenses...............................................  110,091    64,119    32,923    10,100    2,454
                                                                     --------  --------  --------  --------  -------
Income (loss) from operations.......................................  100,285    57,264     1,335    (6,802)  (2,253)
Other income (expense):
    Interest income.................................................    3,574     2,908       528       221       91
    Interest expense................................................     (381)     (748)   (2,805)     (279)      --
                                                                     --------  --------  --------  --------  -------
       Total other income (expense).................................    3,193     2,160    (2,277)      (58)      91
                                                                     --------  --------  --------  --------  -------
Income (loss) before income taxes...................................  103,478    59,424      (942)   (6,860)  (2,162)
    Income tax provision............................................   37,252    20,858        --        --       --
                                                                     --------  --------  --------  --------  -------
Income (loss) before cumulative effect of change in accounting
 principle..........................................................   66,226    38,566      (942)   (6,860)  (2,162)
    Cumulative effect of change in accounting principle(4)..........       --        --      (395)       --       --
                                                                     --------  --------  --------  --------  -------
Net income (loss)...................................................   66,226    38,566    (1,337)   (6,860)  (2,162)
Accrual of dividends on preferred stock.............................       --        --    (7,911)   (7,094)  (1,326)
                                                                     --------  --------  --------  --------  -------
Net income (loss) available to common stockholders.................. $ 66,226  $ 38,566  $ (9,248) $(13,954) $(3,488)
                                                                     ========  ========  ========  ========  =======
Basic income (loss) per common share(5)(6):
    Income (loss) before cumulative effect of change in
     accounting principle........................................... $   2.45  $   1.70  $  (1.06) $  (3.44) $ (0.88)
    Cumulative effect of change in accounting principle(4)..........       --        --     (0.05)       --       --
                                                                     --------  --------  --------  --------  -------
Net income (loss) per common share.................................. $   2.45  $   1.70  $  (1.11) $  (3.44) $ (0.88)
                                                                     ========  ========  ========  ========  =======
Diluted income (loss) per common share(5)(6):
    Income (loss) before cumulative effect of change in
     accounting principle........................................... $   2.34  $   1.61  $  (1.06) $  (3.44) $ (0.88)
    Cumulative effect of change in accounting principle(4)..........       --        --     (0.05)       --       --
                                                                     --------  --------  --------  --------  -------
Net income (loss) per common share.................................. $   2.34  $   1.61  $  (1.11) $  (3.44) $ (0.88)
                                                                     ========  ========  ========  ========  =======
Weighted average number of common shares outstanding(5)(6):
    Basic...........................................................   27,079    22,679     8,355     4,059    3,960
                                                                     ========  ========  ========  ========  =======
    Diluted.........................................................   28,360    24,011     8,355     4,059    3,960
                                                                     ========  ========  ========  ========  =======
Summary Balance Sheet Data:
Working capital (deficit)........................................... $(20,654) $ 74,005  $ 19,675  $(30,641) $ 4,252
Property and equipment, net.........................................  522,573   304,381   157,397    95,607   15,452
Total assets........................................................  587,316   442,704   189,553   102,769   22,358
Short-term debt.....................................................       --        --        --    19,000       --
Accrued preferred dividends payable (6).............................       --        --        --     8,478    1,383
Total equity (6)....................................................  458,492   361,259   177,102    56,913   18,879
</TABLE>

                                      19

<PAGE>

--------
(1) At December 31, 1998, the Company recognized a non-cash write-down of
    natural gas and oil properties in the amount of approximately $2.6 million
    in connection with the ceiling limitation required by the full cost method
    of accounting for natural gas and oil properties. The write-down was
    primarily the result of the decline in natural gas prices experienced in
    1998 and through April 9, 1999. As permitted by applicable Commission
    rules, in calculating the amount of the write-down, the Company used post
    year-end natural gas and oil price increases of $0.26 per MMBtu of natural
    gas and $4.52 per barrel of oil from December 31, 1998 to April 9, 1999. If
    the Company had used only December 31, 1998 natural gas and oil prices, it
    would have recognized a total non-cash write-down of natural gas and oil
    properties of approximately $13.0 million.
(2) The Company had in place both financial hedge and physical contracts with
    Enron North America Corp. at the time it filed for bankruptcy in December
    2001. Spinnaker did not receive payment for fixed price swap contracts
    totaling $2.1 million, intended to hedge December 2001 natural gas sales,
    and $1.4 million related to November 2001 natural gas production sold to
    Enron entities. The Company recorded a net reserve of $3.1 million against
    these receivables and has no other exposure to Enron Corp. and its
    subsidiaries.
(3) Prior to July 1999, the stock option agreements of two of the Company's
    officers provided that they could elect to have Spinnaker deliver shares
    equal to the appreciation in the value of the stock over the option price
    in lieu of purchasing the amount of shares under option. Based on
    management's estimate of the share value of Spinnaker, the Company recorded
    compensation expense of approximately $1.7 million in 1999 related to the
    stock appreciation rights of the stock option agreements. In July 1999,
    these two officers agreed to eliminate the stock appreciation rights
    feature of their stock option agreements.
(4) The cumulative effect of change in accounting principle represents the
    adoption of Statement of Position 98-5 "Reporting on the Costs of Start-Up
    Activities."
(5) Spinnaker was originally formed as a limited liability company, and the
    Company issued common units and preferred units. In connection with its
    conversion to a corporation in January 1998, the Company exchanged Common
    Stock for all then outstanding common units and Preferred Stock for all
    then outstanding preferred units. The Company expresses all historical unit
    data in shares of Common Stock.
(6) In connection with the initial public offering, the Company issued
    8,000,000 shares of Common Stock, converted all then outstanding shares of
    Preferred Stock into 6,061,840 shares of Common Stock and issued 1,200,248
    shares of Common Stock to certain holders of the previously outstanding
    Preferred Stock in lieu of payment of accrued cash dividends. On August 16,
    2000, the Company completed a public offering of 5,600,000 shares of Common
    Stock.

Item 7.  Management's Discussion and Analysis of Financial Condition and
Results of Operations

Overview

   The Company experienced significant growth rates in both production and
reserves in 2001. Performance highlights in 2001 compared to 2000 included
record:

  .  Production of 53.1 Bcfe, up 76 percent.

  .  Proved reserves of 323.2 Bcfe, up 77 percent after production; reserve
     replacement was 365 percent of production.

  .  Revenues of $210.4 million, up 73 percent.

  .  Income from operations of $100.3 million, up 75 percent.

  .  Net income of $66.2 million, or $2.34 per diluted share, up 72 percent.

  .  Cash flows from operating activities, before working capital changes, of
     $189.2 million, up 76 percent.

   Spinnaker's results of operations and financial position were significantly
impacted by natural gas production and prices in 2001. Natural gas revenues
increased $79.0 million. Natural gas production volumes

                                      20

<PAGE>

increased 22.4 Bcf, contributing $123.9 million of the increase in natural gas
revenues, excluding the effects of hedging activities, offset in part by $44.9
million related to lower average natural gas prices in 2001 compared to 2000.
The Company had $14.1 million in cash and cash equivalents and no debt at
December 31, 2001.

   In addition, Spinnaker participated in a significant deep water oil
discovery in 2001 on Green Canyon Blocks 338/339 (Front Runner) with a 25
percent non-operator working interest. The Company participated in five
consecutive successful wells and sidetracks in testing the reservoirs on these
blocks. This significant oil discovery has changed Spinnaker's reserve profile.
Proved oil and condensate reserves were 46 percent of total proved reserves at
December 31, 2001 compared to 10 percent at December 31, 2000. Of the Company's
total proved reserves as of December 31, 2001, 73 percent were proved
undeveloped reserves. Front Runner represented more than 50 percent of total
proved undeveloped reserves.

Risk Factors

   In addition to the other information set forth elsewhere in this annual
report, the following factors should be carefully considered when evaluating
Spinnaker.

Exploration is a high-risk activity, and the 3-D seismic data and other
advanced technologies the Company uses cannot eliminate exploration risk and
require experienced technical personnel whom the Company may be unable to
attract or retain.

   The Company's future success will depend on the success of its exploratory
drilling program. Exploration activities involve numerous risks, including the
risk that no commercially productive natural gas or oil reservoirs will be
discovered. In addition, the Company often is uncertain as to the future cost
or timing of drilling, completing and producing wells. Furthermore, drilling
operations may be curtailed, delayed or canceled as a result of the additional
exploration time and expense associated with a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, adverse weather conditions, compliance with
governmental requirements and shortages or delays in the availability of
drilling rigs or equipment.

   Even when used and properly interpreted, 3-D seismic data and visualization
techniques only assist geoscientists in identifying subsurface structures and
hydrocarbon indicators. They do not allow the interpreter to know conclusively
if hydrocarbons are present or economically producible. The Company could incur
losses as a result of these expenditures. Poor results from exploration
activities could affect future cash flows and results of operations materially
and adversely.

   The Company's exploratory drilling success will depend, in part, on its
ability to attract and retain experienced explorationists and other
professional personnel. Competition for explorationists and engineers with
experience in the Gulf of Mexico is extremely intense. If the Company cannot
retain its current personnel or attract additional experienced personnel, its
ability to compete in the Gulf of Mexico could be adversely affected.

Spinnaker's 2001 deep water oil discovery, Front Runner, will require
significant financial resources and presents numerous uncertainties.

   Spinnaker's 2001 deep water oil discovery on Green Canyon Blocks 338/339,
Front Runner, in which the Company has a 25% non-operator working interest, has
required and will continue to require significant financial resources over the
next two years. The Company incurred $30 million in capital expenditures for
Front Runner in 2001 and expects to incur an aggregate of $110 million in
future development costs during 2002 and 2003. Also, Front Runner accounted for
more than 50 percent of proved undeveloped reserves at December 31, 2001.

                                      21

<PAGE>

   Another oil and gas company operates Front Runner. As a result, the Company
has a limited ability to exercise influence over operations and costs for this
property. The Company has limited experience with large deep water and deep
drilling depth discoveries similar to Front Runner as most of its prior
discoveries have occurred in shallower waters and at shallower drilling depths.
Front Runner is located in approximately 3,500 feet of water and the most
recent well was drilled to a total depth in excess of 21,700 feet. Although the
Company expects to incur approximately $140 million to develop this discovery,
its size and scope are much larger than the Company's prior discoveries and the
Company may encounter difficulties and delays that could cause actual
expenditures to far exceed anticipated amounts. Even if production ultimately
commences for this discovery, it may produce substantially less oil and natural
gas than currently projected. The Company does not expect this discovery to
commence production prior to 2004, but it must commit substantial resources in
advance of the expected production date and cannot predict the price of oil if
and when production commences. These uncertainties and other risks described in
this "Risk Factors" section and elsewhere in this annual report make it
difficult to predict whether Front Runner can be successfully or economically
developed. If Front Runner cannot be successfully and economically developed,
the Company's future business, financial condition and operating results will
be materially and adversely affected.

The natural gas and oil business involves many operating risks that can cause
substantial losses.

   The natural gas and oil business involves a variety of operating risks,
including fires, explosions, blow-outs and surface cratering, uncontrollable
flows of underground natural gas, oil and formation water, natural disasters,
pipe or cement failures, casing collapses, embedded oilfield drilling and
service tools, abnormally pressured formations and environmental hazards such
as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic
gases. If any of these events occur, the Company could incur substantial losses
as a result of injury or loss of life, severe damage to and destruction of
property, natural resources and equipment, pollution and other environmental
damage, clean-up responsibilities, regulatory investigation and penalties,
suspension of the Company's operations and repairs to resume operations. If the
Company experiences any of these problems, it could affect well bores,
platforms, gathering systems and processing facilities, which could adversely
affect its ability to conduct operations.

   Offshore operations are also subject to a variety of operating risks
specific to the marine environment, such as capsizing, collisions and damage or
loss from hurricanes or other adverse weather conditions. These conditions can
cause substantial damage to facilities and interrupt production. As a result,
the Company could incur substantial liabilities that could reduce or eliminate
the funds available for exploration, development or leasehold acquisitions, or
result in loss of equipment and properties.

   For some risks, the Company may not obtain insurance if it believes the cost
of available insurance is excessive relative to the risks presented. In
addition, pollution and environmental risks generally are not fully insurable.
If a significant accident or other event occurs and is not fully covered by
insurance, it could adversely affect the Company's operations.

Exploration for natural gas and oil at deeper drilling depths and in the deep
waters of the Gulf of Mexico involves greater operational and financial risks
than exploration at shallower depths and in shallower waters. These risks could
result in substantial losses.

   As part of its strategy, the Company explores for natural gas and oil at
deeper drilling depths and in the deep waters of the Gulf of Mexico, where
operations are more difficult and costly than at shallower depths and in
shallower waters. Deep depth and deep water drilling and operations require the
application of recently developed technologies that involve a higher risk of
mechanical failure. The Company has experienced and will continue to experience
significantly higher drilling costs for its deep depth and deep water
prospects. Furthermore, the deep waters of the Gulf of Mexico lack the physical
and oilfield service infrastructure present in the shallower waters. As a
result, deep water operations may require a significant amount of time between
a discovery and the time that the Company can market the natural gas or oil,
increasing both the financial and operational risk involved with these
operations.

                                      22

<PAGE>

The Company is vulnerable to operational, regulatory and other risks associated
with the Gulf of Mexico because it currently explores and produces exclusively
in that area.

   The Company's operations and revenues are impacted acutely by conditions in
the Gulf of Mexico because it currently explores and produces exclusively in
that area. This concentration of activity makes the Company more vulnerable
than many of its competitors to the risks associated with the Gulf of Mexico,
including delays and increased costs relating to adverse weather conditions,
drilling rig and other oilfield services and compliance with environmental and
other laws and regulations.

   During the second half of 2000 and early 2001, higher prices for natural gas
and oil led to greater demand for drilling rig and other oilfield services. As
a result, the Company experienced increased costs and reduced availability of
these services.

A significant part of the value of the Company's production and reserves is
concentrated in a small number of offshore properties. Because of this
concentration, any production problems or inaccuracies in reserve estimates
related to those properties are more likely to adversely impact the Company's
business.

   During 2001, over 71 percent of the Company's production came from three of
its properties in the Gulf of Mexico. If mechanical problems, storms or other
events curtailed a substantial portion of this production, the Company's cash
flow would be adversely affected. In addition, at December 31, 2001, the
Company's proved reserves were located on 30 different blocks in the Gulf of
Mexico, with approximately 73 percent of the proved reserves attributable to
five of these properties. One property, Front Runner, accounted for more than
50 percent of total proved undeveloped reserves. If the actual reserves
associated with any one of these five properties are substantially less than
the estimated reserves, the Company's results of operations and financial
condition could be adversely affected.

The Company's right to receive data under the Data Agreement will be
substantially restricted after March 31, 2002. In addition, if PGS terminates
the Data Agreement, the Company's ability to find additional reserves could be
impaired.

   The Company's success depends heavily on its access to 3-D seismic data, and
one of its primary sources for 3-D seismic data is the Data Agreement. The
Company is only entitled to receive and use 3-D seismic data that PGS acquires
and processes prior to March 31, 2002 or that PGS is in the process of
acquiring or processing as of that date. In addition, if PGS terminates the
Data Agreement, the Company would lose access to a portion of its 3-D seismic
data which loss could have an adverse effect on its ability to find additional
reserves. PGS may terminate the Data Agreement on several grounds, including if
a PGS competitor acquires control of Spinnaker or if the Company breaches the
Data Agreement subject to specified exceptions. See "Item 1. Business--PGS Data
Agreement--Termination Events" for a description of these exceptions.

Competitors may use superior technology which the Company may be unable to
afford or which would require costly investment in order to compete.

   The industry is subject to rapid and significant advancements in technology,
including the introduction of new products and services using new technologies.
As competitors use or develop new technologies, the Company may be placed at a
competitive disadvantage, and competitive pressures may force it to implement
new technologies at a substantial cost. In addition, competitors may have
greater financial, technical and personnel resources that allow them to enjoy
technological advantages and may in the future allow them to implement new
technologies before the Company can. The Company cannot be certain that it will
be able to implement technologies on a timely basis or at a cost that is
acceptable to it. One or more of the technologies that the

                                      23

<PAGE>

Company currently uses or that it may implement in the future may become
obsolete, and it may be adversely affected. For example, marine seismic
acquisition technology has been characterized by rapid technological
advancements in recent years and further significant technological developments
could substantially impair the 3-D seismic data's value.

Reserve estimates depend on many assumptions that may turn out to be
inaccurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and net present value of the
Company's reserves.

   The process of estimating natural gas and oil reserves is complex. It
requires interpretations of available technical data and various assumptions,
including assumptions relating to economic factors. Any significant
inaccuracies in these interpretations or assumptions could materially affect
the estimated quantities and net present value of reserves. See "Item 2.
Properties--Natural Gas and Oil Reserves."

   In order to prepare these estimates, the Company must project production
rates and timing of development expenditures. The Company must 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 natural gas and oil prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Therefore, estimates of natural gas and oil reserves are inherently imprecise.

   Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves most likely will vary from the Company's
estimates. Any significant variance could materially affect the estimated
quantities and net present value of reserves. In addition, the Company may
adjust estimates of proved reserves to reflect production history, results of
exploration and development, prevailing natural gas and oil prices and other
factors, many of which are beyond the Company's control. At December 31, 2001,
approximately 87 percent of the Company's proved reserves were either proved
undeveloped or proved non-producing. Moreover, some of the producing wells
included in the reserve report had produced for a relatively short period of
time as of December 31, 2001. 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.

   It should not be assumed that the present value of future net cash flows
from the Company's proved reserves is the current market value of its estimated
natural gas and oil reserves. In accordance with Commission requirements, the
Company bases the estimated discounted future net cash flows from its 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 net present value
estimate.

The failure to replace reserves would adversely affect production and cash
flows.

   The Company's future natural gas and oil production depends on its success
in finding or acquiring additional reserves. If the Company fails to replace
reserves, its level of production and cash flows would be adversely impacted.
In general, production from natural gas and oil properties declines as reserves
are depleted, with the rate of decline depending on reservoir characteristics.
The Company's total proved reserves decline as reserves are produced unless it
conducts other successful exploration and development activities or acquires
properties containing proved reserves, or both. The Company's ability to make
the necessary capital investment to maintain or expand its asset base of
natural gas and oil reserves would be impaired to the extent cash flow from
operations is reduced and external sources of capital become limited or
unavailable. The Company may not be successful in exploring for, developing or
acquiring additional reserves. If the Company is not successful, its future
production and revenues will be adversely affected.

Relatively short production periods for Gulf of Mexico properties subject the
Company to higher reserve replacement needs, require significant capital
expenditures to replace production and may impair its ability to reduce
production during periods of low natural gas and oil prices.

   Production of reserves from reservoirs in the Gulf of Mexico generally
declines more rapidly than from reservoirs in many other producing regions of
the world. This results in recovery of a relatively higher percentage

                                      24

<PAGE>

of reserves from properties in the Gulf of Mexico during the initial few years
of production. As a result, reserve replacement needs from new prospects are
greater and require the Company to incur significant capital expenditures to
replace production. The rapid production declines of certain producing wells,
combined with pipeline-mandated curtailments of certain facilities, shut-ins
related to facility upgrades and less than anticipated results from workovers,
resulted in lower production in the fourth quarter of 2001 compared to the
prior quarter. The Company expects a further decline in production during the
first quarter of 2002.

   Also, revenues and return on capital will depend significantly on prices
prevailing during these relatively short production periods. The Company's
potential need to generate revenues to fund ongoing capital commitments or
reduce indebtedness may limit its ability to slow or shut-in production from
producing wells during periods of low prices for natural gas and oil.

Natural gas and oil prices fluctuate widely, and low prices could have a
material adverse impact on the Company's business and financial results.

   The Company's revenues, profitability and future growth depend substantially
on prevailing prices for natural gas and oil. Prices also affect the amount of
cash flow available for capital expenditures and the Company's ability to
borrow and raise additional capital. The amount the Company can borrow under
the Credit Facility is subject to periodic re-determination based in part on
changing expectations of future prices. Lower prices may also reduce the amount
of natural gas and oil that the Company can economically produce.

   Prices for natural gas and oil fluctuate widely. For example, natural gas
prices declined significantly in 2001 from levels reached in the second half of
2000 and early 2001. Prices for natural gas and oil also declined significantly
in 1998 and, for an extended period of time, remained substantially below
prices obtained in previous years. Among the factors that can cause this
fluctuation are the level of consumer product demand, weather conditions,
domestic and foreign governmental regulations, the price and availability of
alternative fuels, political conditions in natural gas and oil producing
regions, the domestic and foreign supply of natural gas and oil, the price of
foreign imports and overall economic conditions. If natural gas and oil prices
decline, even if for only a short period of time, it is possible that
write-downs of natural gas and oil properties could occur in the future.

Hedging production has limited and may continue to limit potential gains from
increases in commodity prices or result in losses.

   The Company enters into hedging arrangements from time to time to reduce its
exposure to fluctuations in natural gas and oil prices and to achieve more
predictable cash flow. These financial arrangements take the form of swap
contracts or costless collars and are placed with major trading counterparties
the Company believes represent minimum credit risks. The Company had in place
both financial hedge and physical contracts with Enron North America Corp. at
the time it filed for bankruptcy in December 2001. Spinnaker did not receive
payment as required under these contracts. The Company cannot provide assurance
that other trading counterparties will not become credit risks in the future.
Hedging arrangements expose the Company to risks in some circumstances,
including situations when the other party to the hedging contract defaults on
its contract obligations or there is a change in the expected differential
between the underlying price in the hedging agreement and actual prices
received. These hedging arrangements have limited and may continue to limit the
benefit the Company could receive from increases in the prices for natural gas
and oil. The Company cannot provide assurance that the hedging transactions it
has entered into, or will enter into, will adequately protect it from
fluctuations in natural gas and oil prices. The Company may choose not to
engage in hedging transactions in the future. As a result, the Company may be
adversely affected during periods of declining natural gas and oil prices.

The Company's success depends on its Chief Executive Officer and other key
personnel, the loss of whom could disrupt business operations.

   The Company depends to a large extent on the efforts and continued
employment of the Company's President and Chief Executive Officer, Roger L.
Jarvis, and other key personnel. If Mr. Jarvis or these other key

                                      25

<PAGE>

personnel resign or become unable to continue in their present role and if they
are not adequately replaced, the Company's business operations could be
adversely affected.

The Company is subject to complex laws and regulations, including environmental
regulations, that can adversely affect the cost, manner or feasibility of doing
business.

   Exploration for and development, production and sale of natural gas and oil
in the U.S. and especially in the Gulf of Mexico are subject to extensive
federal, state and local laws and regulations, including environmental laws and
regulations. The Company may be required to make large expenditures to comply
with environmental and other governmental regulations. Matters subject to
regulation include discharge permits for drilling operations, drilling bonds,
reports concerning operations and taxation.

   Under these laws and regulations, the Company could be liable for personal
injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. The Company
does not believe that full insurance coverage for all potential environmental
damages is available at a reasonable cost. Failure to comply with these laws
and regulations also may result in the suspension or termination of its
operations and subject the Company to administrative, civil and criminal
penalties. Moreover, these laws and regulations could change in ways that
substantially increase costs. For example, Congress or the MMS could decide to
limit exploratory drilling or natural gas production in additional areas of the
Gulf of Mexico. Accordingly, any of these liabilities, penalties, suspensions,
terminations or regulatory changes could materially and adversely affect the
Company's financial condition and results of operations.

Competition in the industry is intense, and the Company is smaller and has a
more limited operating history than most of its competitors in the Gulf of
Mexico.

   The Company competes with major and independent natural gas and oil
companies for property acquisitions. It also competes for the equipment and
labor required to operate and develop properties. Most of the competitors have
substantially greater financial and other resources than the Company. As a
result, in the deep water where exploration is more expensive, competitors may
be better able to withstand sustained periods of unsuccessful drilling. In
addition, larger competitors may be able to absorb the burden of any changes in
federal, state and local laws and regulations more easily than the Company can,
which would adversely affect its competitive position. These competitors may be
able to pay more for exploratory prospects and productive natural gas and oil
properties and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than the Company can. The Company's ability
to explore for natural gas and oil prospects and to acquire additional
properties in the future will depend on its ability to conduct operations, to
evaluate and select suitable properties and to consummate transactions in this
highly competitive environment. In addition, most of the competitors have been
operating in the Gulf of Mexico for a much longer time than the Company has and
have demonstrated the ability to operate through industry cycles.

The Company cannot control the activities on properties it does not operate.

   Other companies operate some of the properties in which the Company has an
interest. As a result, the Company has a limited ability to exercise influence
over operations for these properties or their associated costs. The Company's
dependence on the operator and other working interest owners for these projects
and its limited ability to influence operations and associated costs could
materially adversely affect the realization of its targeted returns on capital
in drilling or acquisition activities. The success and timing of drilling and
development activities on properties operated by others therefore depend upon a
number of factors that are outside of the Company's control, including timing
and amount of capital expenditures, the operator's expertise and financial
resources, approval of other participants in drilling wells and selection of
technology.

The Company may have difficulty financing its planned growth.

   The Company has experienced and expects to continue to experience
substantial capital expenditure and working capital needs, particularly as a
result of its drilling program. In the future, the Company expects it will

                                      26

<PAGE>

require additional financing, in addition to cash generated from its
operations, to fund its planned growth. The Company cannot be certain that
additional financing will be available on acceptable terms or at all. In the
event additional capital resources are unavailable, the Company may curtail its
drilling, development and other activities or be forced to sell some of its
assets on an untimely or unfavorable basis.

Because the Company has a limited operating history and has incurred losses
from operations in the past, future operating results are difficult to
forecast. The Company's failure to sustain profitability in the future could
adversely affect the market price of Spinnaker's Common Stock.

   The Company was formed in December 1996 and, as a result, has a limited
operating history. The Company's limited operating history and the
unpredictable results of its exploration and development strategy make it
difficult to forecast operating results. In considering whether to invest in
Spinnaker's Common Stock, the limited historical financial and operating
information available on which to base an evaluation of the Company's
performance should be considered. In addition, because the Company has a
limited operating history and fewer financial resources than many companies in
the industry, it may be at a disadvantage in bidding for exploratory prospects
and in developing natural gas and oil properties. For a description of the
competition the Company faces in its business, see "Item 1.
Business--Competition."

   The Company incurred net losses of $1.3 million, $6.9 million, $2.2 million
and $0.3 million in 1999, 1998, 1997 and 1996, respectively. The Company's
development of and participation in a larger number of prospects has required
and will continue to require substantial capital expenditures. The Company
cannot provide assurance that it will sustain profitability or positive cash
flows from operating activities in the future. The Company's failure to sustain
profitability in the future could adversely affect the market price of
Spinnaker's Common Stock.

Warburg owns a significant amount of Common Stock, giving it influence in
corporate transactions and other matters, and the interests of Warburg could
differ from those of other stockholders.

   At December 31, 2001, Warburg owned approximately 25 percent of the
outstanding shares of Common Stock. As a result, Warburg is in a position to
significantly influence the outcome of matters requiring a stockholder vote,
including the election of directors, the adoption of an amendment to the
certificate of incorporation or bylaws and the approval of mergers and other
significant corporate transactions. Its influence over Spinnaker may delay or
prevent a change of control of the Company and may adversely affect the voting
and other rights of other stockholders.

   Furthermore, conflicts of interest could arise in the future between the
Company and Warburg concerning, among other things, potential competitive
business activities or business opportunities. Warburg is not restricted from
competitive natural gas and oil exploration and production activities or
investments. Warburg currently has significant equity interests in other public
and private natural gas and oil companies. The interests of Warburg could
differ from those of other stockholders.

A portion of the Company's outstanding shares owned by Warburg or other
significant stockholders may be sold into the market in the near future. This
could cause the market price of the Common Stock to drop significantly, even if
the Company's business is doing well.

   The market price of the Common Stock could drop due to sales of a large
number of shares of Common Stock in the market or the perception that such
sales could occur. This could make it more difficult to raise funds through any
future offering of Common Stock.

The certificate of incorporation and bylaws contain provisions that could
discourage an acquisition or change of control of the Company.

   The certificate of incorporation authorizes the board of directors to issue
Preferred Stock without stockholder approval. If the board of directors elects
to issue Preferred Stock, it could be more difficult for a third

                                      27

<PAGE>

party to acquire control of the Company, even if that change of control might
be beneficial to stockholders. In addition, provisions of the certificate of
incorporation and bylaws, such as no stockholder action by written consent and
limitations on stockholder proposals at meetings of stockholders, could also
make it more difficult for a third party to acquire control of the Company.

Terrorist attacks on natural gas and oil production facilities, transportation
systems and storage facilities could have a material adverse impact on the
Company's business.

   Natural gas and oil production facilities, transportation systems and
storage facilities could be targets of terrorist attacks. These attacks could
have a material adverse impact if certain natural gas and oil infrastructure
integral to the Company's operations were destroyed or damaged.

Critical Accounting Policies

   The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at 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 depreciation, depletion and amortization ("DD&A")
of proved natural gas and oil properties. Natural gas and oil 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. The Company's critical accounting policies are
as follows:

  Natural Gas and Oil Properties

   The Company uses the full cost method of accounting for its investment in
natural gas and oil properties. Under this method, all acquisition, exploration
and development costs, including certain related employee costs, incurred for
the purpose of exploring for natural gas and oil are capitalized. Such amounts
include the cost of drilling and equipping productive wells, dry hole costs,
lease acquisition costs, delay rentals and costs related to such activities.
Exclusive of field-level costs, Spinnaker capitalized $5.1 million, $3.8
million and $2.5 million of general and administrative costs in 2001, 2000 and
1999, respectively. These capitalized costs are directly related to exploration
activities and include salaries, employee benefits, costs of consulting
services and other related expenses. Costs associated with production and
general corporate activities are expensed in the period incurred. Interest
costs related to unproved properties and properties under development are also
capitalized to natural gas and oil properties. Spinnaker capitalized interest
of $0, $17,000 and $966,000 in 2001, 2000 and 1999, respectively. Sales of
natural gas and oil 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 reserves of natural gas and oil.

   The Company computes the provision for DD&A of natural gas and oil
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 dismantlement, restoration and abandonment costs, net of estimated salvage
values. 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
applicable 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.
The Company has excluded from amortization a portion of the estimated future
expenditures associated with common development costs on its deep water
discovery at Front Runner based on existing proved reserves to total proved
reserves expected to be established upon completion of the deep water project.

                                      28

<PAGE>

   Capitalized costs of natural gas and oil properties, net of accumulated DD&A
and related deferred taxes, are limited to the estimated future net cash flows
from proved natural gas and oil reserves, including the effects of hedging
activities, discounted at 10 percent, plus the lower of cost or fair value of
unproved properties, as adjusted for related income tax effects (the full cost
ceiling). If capitalized costs exceed the full cost ceiling, the excess is
charged to write-down of natural gas and oil properties in the quarter in which
the excess occurs. Given the volatility of natural gas and oil prices, it is
reasonably possible that the Company's estimate of discounted future net cash
flows from proved natural gas and oil reserves will change in the near term. If
natural gas and oil prices decline, even if for only a short period of time, or
if the Company has downward revisions to its estimated proved reserves, it is
possible that write-downs of natural gas and oil properties could occur in the
future.

   The costs associated with unevaluated leasehold acreage, unamortized seismic
data, wells currently drilling and capitalized interest are not initially
included in the amortization base. Leasehold costs 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. Leasehold
costs are transferred to the amortization base if a reduction in value has
occurred. Of the $102.9 million of net unproved property costs at December 31,
2001 excluded from the amortizable base, net costs of $19.7 million, $42.5
million and $12.3 million were incurred in 2001, 2000 and 1999, respectively,
and $28.4 million was incurred prior to 1999. The majority of the costs will be
evaluated over the next four years.

   In June 2001, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for
Asset Retirement Obligations." SFAS No. 143 requires that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred with the associated asset retirement costs being
capitalized as a part of the carrying amount of the long-lived asset. SFAS No.
143 also includes disclosure requirements that provide a description of asset
retirement obligations and reconciliation of changes in the components of those
obligations. The Company currently records its plugging and abandonment costs,
net of salvage value, with respect to its natural gas and oil properties as
additional DD&A expense using the units-of-production method. This statement
will require the Company to recognize a liability for the fair value of its
plugging and abandonment liability, excluding salvage value, with the
associated costs as part of its natural gas and oil property balance. The
Company is evaluating the future financial effects of adopting SFAS No. 143 and
expects to adopt the standard effective January 1, 2003.

  Commodity Price Risk Management Activities

   On January 1, 2001, the Company adopted SFAS No. 133, as amended,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
established accounting and reporting standards requiring that all derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in a
derivative's fair value be realized currently in earnings unless specific hedge
accounting criteria are met. Accounting for qualifying hedges allows derivative
gains and losses to offset related results on the hedged item in the statement
of operations and requires a company to formally document, designate and assess
the effectiveness of transactions that qualify for hedge accounting.

  Stock Options

   In October 1995, the FASB issued SFAS No. 123, "Accounting for Stock-Based
Compensation." SFAS No. 123 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 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. See Note 6 of the
Notes to Consolidated Financial Statements.

                                      29

<PAGE>

Related Parties

   The Company paid $17.4 million in 2001 to affiliates of Baker Hughes
Incorporated ("Baker Hughes"), an oilfield services company. Mr. Michael E.
Wiley, a director of Spinnaker, serves as Chairman of the Board, Chief
Executive Officer and President of Baker Hughes. The Company paid $83,000 and
$528,000 in 2001 and 2000, respectively, to Cooper Cameron Corporation ("Cooper
Cameron"), an oilfield services company. Mr. Sheldon R. Erikson, a director of
Spinnaker, serves as Chairman of the Board, Chief Executive Officer and
President of Cooper Cameron. The Company purchases oilfield goods, equipment
and services from Baker Hughes, Cooper Cameron and other companies in the
ordinary course of business. Spinnaker believes that these transactions are at
arms-length and the charges and fees that it pays 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.

Results of Operations

   The following table sets forth certain operating information with respect to
the natural gas and oil operations of the Company:

<TABLE>
<CAPTION>
                                                                  For the Year Ended December 31,
                                                                  ------------------------------
                                                                    2001         2000      1999
                                                                  --------     --------  -------
<S>                                                               <C>          <C>       <C>
Production:
   Natural gas (MMcf)............................................   51,234       28,845   11,962
   Oil and condensate (MBbls)....................................      310          225      180
       Total (MMcfe).............................................   53,094       30,194   13,044
Revenues (in thousands):
   Natural gas................................................... $212,238     $133,264  $29,839
   Oil and condensate............................................    7,718        6,775    3,668
   Net hedging income (loss).....................................   (9,580)     (18,656)     751
                                                                  --------     --------  -------
       Total..................................................... $210,376     $121,383  $34,258
Average sales price per unit:
   Natural gas revenues from production (per Mcf)................ $   4.14     $   4.62  $  2.49
   Effects of hedging activities (per Mcf).......................    (0.18)       (0.59)    0.08
                                                                  --------     --------  -------
       Average price (per Mcf)................................... $   3.96     $   4.03  $  2.57

   Oil and condensate revenues from production (per Bbl)......... $  24.90     $  30.14  $ 20.33
   Effects of hedging activities (per Bbl).......................       --        (7.16)   (0.57)
                                                                  --------     --------  -------
       Average price (per Bbl)................................... $  24.90     $  22.98  $ 19.76

   Total revenues from production (per Mcfe)..................... $   4.14     $   4.64  $  2.57
   Effects of hedging activities (per Mcfe)......................    (0.18)       (0.62)    0.06
                                                                  --------     --------  -------
       Total average price (per Mcfe)............................ $   3.96     $   4.02  $  2.63
Expenses (per Mcfe):
   Lease operating expenses...................................... $   0.23     $   0.30  $  0.41
   Depreciation, depletion and amortization--natural gas and oil
     properties.................................................. $   1.60     $   1.57  $  1.59
Income from operations (in thousands)............................ $100,285     $ 57,264  $ 1,335
</TABLE>

  Year Ended December 31, 2001 as Compared to the Year Ended December 31, 2000

   Revenues increased $89.0 million in 2001 compared to 2000. Excluding the
effects of hedging activities, natural gas revenues increased $79.0 million and
oil and condensate revenues increased $0.9 million. Losses resulting from
hedging activities decreased by $9.1 million in 2001 compared to 2000, thereby
improving revenues.

                                      30

<PAGE>

   Production increased approximately 22.9 Bcfe in 2001 compared to 2000.
Average daily production in 2001 was 145 MMcfe compared to 82 MMcfe in 2000.
Natural gas production volumes increased 22.4 Bcf, contributing $123.9 million
of the increase in natural gas revenues, excluding the effects of hedging
activities, offset in part by $44.9 million related to lower average natural
gas prices in 2001 compared to 2000. Oil and condensate production volumes
increased 85 MBbls, contributing $2.8 million of the increase in oil and
condensate revenues, offset in part by $1.9 million related to decreases in
average oil and condensate prices. The rapid production declines of certain
producing wells, combined with pipeline-mandated curtailments of certain
facilities, shut-ins related to facility upgrades and less than anticipated
results from workovers, resulted in lower production in the fourth quarter of
2001 compared to the prior quarter. The Company expects a further decline in
production during the first quarter of 2002.

   Lease operating expenses increased $3.1 million in 2001 compared to 2000. Of
the total increase in lease operating expenses, $1.0 million was primarily
related to workover activities in 2001 and $0.4 million was attributable to
wells on new blocks that commenced production subsequent to December 31, 2000.
The lease operating expense rate decreased 23 percent to $0.23 per Mcfe in 2001
compared to 2000 primarily due to increased production coupled with continued
efficiencies gained in core operating areas, including the High Island 202 area.

   DD&A increased $37.7 million in 2001 compared to 2000. The change in DD&A
was attributable to an increase in production of 22.9 Bcfe and a slightly
higher DD&A rate, which impacted DD&A by $36.0 million and $1.7 million,
respectively.

   General and administrative expenses increased $2.1 million in 2001 compared
to 2000. The increase in general and administrative expenses was primarily due
to higher employment-related costs resulting from the Company's recent growth.

   The Company had in place both financial hedge and physical contracts with
Enron North America Corp. at the time it filed for bankruptcy in December 2001.
Spinnaker did not receive payment for fixed price swap contracts totaling $2.1
million, intended to hedge December 2001 natural gas sales, and $1.4 million
related to November 2001 natural gas production sold to Enron entities. The
Company recorded a net reserve of $3.1 million related to these receivables and
has no other exposure to Enron Corp. and its subsidiaries.

   Interest income increased $0.7 million in 2001 compared to 2000 primarily
due to investment income associated with proceeds from the Company's public
offering of Common Stock completed on August 16, 2000. Interest expense
decreased $0.4 million in 2001 compared to 2000. The Company had no outstanding
borrowings in 2001 compared to 2000.

   Income tax provision increased $16.4 million in 2001 compared to 2000 and
primarily relates to deferred income taxes accrued at a 36 percent effective
tax rate in 2001 and a 35 percent effective tax rate in 2000.

   The Company recognized net income of $66.2 million, or $2.45 per basic share
and $2.34 per diluted share, in 2001 compared to net income of $38.6 million,
or $1.70 per basic share and $1.61 per diluted share, in 2000.

  Year Ended December 31, 2000 as Compared to the Year Ended December 31, 1999

   Revenues, including the effects of hedging activities, increased $87.1
million in 2000 compared to 1999. Excluding the effects of hedging activities,
natural gas revenues increased $103.4 million and oil and condensate revenues
increased $3.1 million in 2000 compared to 1999. Net natural gas and oil
hedging losses increased $19.4 million in 2000 compared to 1999.

   Production increased approximately 17.2 Bcfe in 2000 compared to 1999.
Average daily production in 2000 was 82 MMcfe compared to 36 MMcfe in 1999.
Natural gas production volumes increased 16.9 Bcf, primarily due to wells on 11
new blocks which commenced production in 2000, contributing $93.5 million of
the increase in natural gas revenues, excluding the effects of hedging
activities. Average natural gas prices increased, contributing $9.9 million of
the increase in natural gas revenues. Oil and condensate production volumes

                                      31

<PAGE>

increased approximately 45 MBbls, primarily due to wells on 11 new blocks which
commenced production in 2000, contributing $2.4 million of the increase in oil
and condensate revenues, excluding the effects of hedging activities. Average
oil and condensate prices increased, contributing $0.7 million of the increase
in oil and condensate revenues.

   Lease operating expenses increased $3.6 million in 2000 compared to 1999. Of
the total increase in lease operating expenses, $4.1 million was attributable
to wells on 11 new blocks which commenced production in 2000, offset in part by
$0.5 million, primarily related to major workover activities in 1999. Lease
operating expenses per Mcfe in 1999 included approximately $0.13 per Mcfe
associated with workovers on two wells and well control activities on another
well. Lease operating expenses per Mcfe in 2000 included approximately $0.03
per Mcfe associated with workovers on four wells.

   DD&A increased $26.8 million in 2000 compared to 1999. The increase in DD&A
was primarily attributable to the 17.2 Bcfe increase in production volumes in
2000. The DD&A rate in 2000 decreased slightly from the DD&A rate in 1999.

   General and administrative expenses increased $2.5 million in 2000 compared
to 1999. The increase in general and administrative expenses was primarily due
to employment-related costs associated with personnel additions during 1999 and
2000.

   Interest income increased $2.4 million in 2000 compared to 1999 primarily
due to investment income associated with proceeds from the Company's public
offering of Common Stock completed on August 16, 2000. Interest expense, net of
capitalized interest, decreased $2.1 million in 2000 compared to 1999. The
Company had substantially less outstanding borrowings in 2000 compared to 1999.
At December 31, 2000, the Company had no outstanding borrowings.

   An income tax provision of $20.9 million was recorded in 2000 based on the
Company's transition to profitability in 2000. No income tax benefit was
recorded in 1999 due to the uncertainty of future realization as the Company
had not established a history of operating income.

   The Company recognized net income of $38.6 million, or $1.70 per basic share
and $1.61 per diluted share, in 2000 compared to a net loss of $1.3 million in
1999. After dividends of $7.9 million on Preferred Stock that is no longer
outstanding, the Company recognized a net loss available to common stockholders
of $9.2 million, or a loss of $1.11 per basic and diluted share, in 1999.

Liquidity and Capital Resources

   The Company has experienced and expects to continue to experience
substantial capital requirements, primarily due to its active exploration and
development programs in the Gulf of Mexico. Capital expenditures in 2001, 2000
and 1999 were $288.8 million, $163.7 million and $85.1 million, respectively.
Spinnaker has capital expenditure plans for 2002 totaling approximately $250
million. During 2001, Spinnaker participated in a significant deep water oil
discovery, Front Runner, with a 25 percent non-operator working interest. The
Company participated in five consecutive successful wells and sidetracks in
testing the reservoirs on these blocks. Spinnaker has incurred capital
expenditures associated with Front Runner of approximately $30 million through
December 31, 2001 and expects to incur an aggregate of approximately $110
million in future development costs during 2002 and 2003. The 2002 capital
expenditure plans include approximately $40 million related to the Front Runner
production facilities. The Company is considering various financing
alternatives for the cost of these facilities, including a lease.

   Natural gas and oil prices have a significant impact on the Company's cash
flows available for capital expenditures and its ability to borrow and raise
additional capital. The amount the Company can borrow under its Credit Facility
is subject to periodic re-determination based in part on changing expectations
of future prices.

                                      32

<PAGE>

Lower prices may also reduce the amount of natural gas and oil that the Company
can economically produce. Additionally, the rapid production declines of
certain producing wells, combined with pipeline-mandated curtailments of
certain facilities, shut-ins related to facility upgrades and less than
anticipated results from workovers, resulted in lower production in the fourth
quarter of 2001 compared to the prior quarter. The Company expects a further
decline in production during the first quarter of 2002.

   While the Company believes that working capital, cash flows from operations
and available borrowings under its Credit Facility will be sufficient to meet
its capital requirements in the next twelve months, additional debt or equity
financing may be required in the future to fund its growth and exploration and
development programs. In the event additional capital resources are
unavailable, the Company may curtail its drilling, development and other
activities or be forced to sell some of its assets on an untimely or
unfavorable basis.

   Spinnaker has an effective shelf registration statement relating to the
potential public offer and sale by the Company or certain affiliates of up to
$300.0 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 the Company will or could sell any such securities.

   Cash and cash equivalents decreased $49.8 million to $14.1 million at
December 31, 2001 from $63.9 million at December 31, 2000. The decrease in cash
and cash equivalents resulted from $266.4 million used in investing activities,
offset in part by $209.4 million provided by operating activities and $7.2
million provided by financing activities.

  Operating Activities

   Net cash provided by operating activities in 2001 increased 155 percent to
$209.4 million from $82.0 million in 2000, primarily as a result of higher
natural gas production. Cash flow from operations depends on the Company's
ability to increase production through its exploration and development programs
and the prices of natural gas and oil. The Company has made significant
investments to expand its operations in the Gulf of Mexico. These investments
have resulted in an increase in the Company's average daily production.

   The Company sells its natural gas and oil production under fixed or floating
market price contracts. Spinnaker enters into hedging arrangements from time to
time to reduce its exposure to fluctuations in natural gas and oil prices and
achieve more predictable cash flow. However, these contracts also limit the
benefits the Company would realize if prices increase. See "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk."

   The Company's cash flow from operations also depends on its ability to
manage working capital, including accounts receivable, accounts payable and
accrued liabilities. The decrease in accounts receivable of $21.5 million was
primarily due to a decrease in accrued natural gas and oil sales of $21.6
million as a result of substantially lower natural gas prices in December 2001
compared to December 2000, partially offset by a net increase in all other
receivables of $0.1 million. The increase in accounts payable and accrued
liabilities of $18.8 million was primarily due to costs associated with
increased drilling and development activities at the end of 2001 compared to
the end of 2000, including non-cash activity of $14.8 million for property
related payables and $7.2 million related to the tax effect of the fair market
value of current derivatives.

  Investing Activities

   Net cash used in investing activities in 2001 increased 48 percent to $266.4
million from $180.2 million in 2000, primarily due to higher capital
expenditures. Natural gas and oil capital expenditures in 2001 were $287.2
million compared to $161.8 million in 2000. The Company also purchased
short-term investments of $29.6 million and sold short-term investments of
$52.0 million.

                                      33

<PAGE>

   The Company drilled 35 wells in 2001, 19 of which were successful. In 2000,
the Company drilled 28 wells, 16 of which were successful. Since inception and
through December 31, 2001, the Company has drilled 94 wells, 56 of which were
successful, representing a success rate of approximately 60 percent.

   The Company has capital expenditure plans for 2002 totaling approximately
$250 million, primarily for costs related to exploration and development
programs. The 2002 budget includes development costs that are contingent on the
success of exploratory drilling. The Company does not anticipate any
significant abandonment or dismantlement costs in 2002. Actual levels of
capital expenditures may vary due to many factors, including drilling results,
natural gas and oil 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.

  Financing Activities

   Net cash provided by financing activities in 2001 decreased 95 percent to
$7.2 million from $141.6 million in 2000, primarily due to proceeds from a
Common Stock offering in 2000 of $138.9 million. The net cash provided by
financing activities in 2001 related to stock option exercises.

   On December 28, 2001, the Company completed an unsecured $200.0 million
Credit Facility with a group of seven banks. The three-year facility has an
initial borrowing base of $125.0 million that is re-determined on April 30 and
September 30 each year. The banks and Spinnaker also have the option to request
one additional re-determination each year. The Company has the option to elect
to use a base interest rate as described below or the LIBOR rate plus, for each
such rate, a spread based on the percent of the borrowing base used at that
time. The base interest rate under the Credit Facility is a fluctuating rate of
interest equal to the higher of either the Toronto-Dominion Bank's base rate
for dollar advances made in the United States or the Federal Funds Rate plus
0.5 percent per annum. The Credit Facility contains covenants and restrictive
provisions. At December 31, 2001, the Company was in compliance with the
covenants and had no outstanding borrowings under the Credit Facility. As of
March 7, 2002, the Company had outstanding borrowings of $21.0 million under
the Credit Facility. For a description of the covenants and restrictive
provisions in the Credit Facility, see Note 3 of the Notes to Consolidated
Financial Statements.

  Contractual Obligations

   The Company leases administrative offices, office equipment and oil and gas
equipment under non-cancelable operating leases. In addition, the Company has
agreed to purchase $2.0 million of seismic-related services from PGS prior to
December 31, 2002. Through December 31, 2001, the Company paid PGS a total of
approximately $1.3 million for these services. The Company had no debt or
capital leases outstanding as of December 31, 2001. The Company has incurred
obligations in the ordinary course of business under purchase and service
agreements which are not included in the table below. Obligations under
operating leases and the Data Agreement as of December 31, 2001 are as follows:

<TABLE>
<CAPTION>
                                                 Payments Due by Period
                                         --------------------------------------
                                                Less than  1-3    4-5    After
                                         Total   1 Year   Years  Years  5 Years
                                         ------ --------- ------ ------ -------
<S>                                      <C>    <C>       <C>    <C>    <C>
Operating leases........................ $6,914  $1,222   $3,858 $1,834   $--
Unconditional Data Agreement obligations    655     655       --     --    --
                                         ------  ------   ------ ------   ---
   Total................................ $7,569  $1,877   $3,858 $1,834   $--
                                         ======  ======   ====== ======   ===
</TABLE>

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

  Interest Rate Risk

   The Company is exposed to changes in interest rates. Changes in interest
rates affect the interest earned on cash, cash equivalents and short-term
investments and the interest rate paid on borrowings under the Credit

                                      34

<PAGE>

Facility. The Company does not currently use interest rate derivative
instruments to manage exposure to interest rate changes, but may do so in the
future.

  Commodity Price Risk

   The Company's revenues, profitability and future growth depend substantially
on prevailing prices for natural gas and oil. Prices also affect the amount of
cash flow available for capital expenditures and the Company's ability to
borrow and raise additional capital. Lower prices may also reduce the amount of
natural gas and oil that the Company can economically produce. The Company
sells its natural gas and oil production under fixed or floating market price
contracts. Spinnaker enters into hedging arrangements from time to time to
reduce its exposure to fluctuations in natural gas and oil prices and to
achieve more predictable cash flow. However, these contracts also limit the
benefits the Company would realize if prices increase. These financial
arrangements take the form of swap contracts or costless collars and are placed
with major trading counterparties the Company believes represent minimum credit
risks. Spinnaker cannot provide assurance that these trading counterparties
will not become credit risks in the future. The Company had in place both
financial hedge and physical contracts with Enron North America Corp. at the
time it filed for bankruptcy in December 2001. Spinnaker did not receive
payment as required under these contracts. Under its current hedging practice,
the Company generally does not hedge more than 66 2/3 percent of its estimated
twelve-month production quantities without the prior approval of the risk
management committee of the board of directors.

   The Company enters into New York Mercantile Exchange ("NYMEX") related swap
contracts and collar arrangements from time to time. The Company's swap
contracts 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 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. Some of the master
agreements require the Company to make margin payments to counterparties when
net exposure exceeds a certain threshold. As of March 7, 2002, Spinnaker's
commodity price risk management positions in fixed price natural gas swap
contracts were as follows:

<TABLE>
<CAPTION>
                                         Average Weighted
                                          Daily   Average
                                         Volume  Price Per
                           Period        (MMBtu)   MMBtu
                           ------        ------- ---------
                     <S>                 <C>     <C>
                     First Quarter 2002. 100,000   $3.23
                     Second Quarter 2002  93,407    3.20
                     Third Quarter 2002.  80,000    3.37
                     Fourth Quarter 2002  76,685    3.58
                     Full Year 2003.....  25,000    3.27
</TABLE>

   Based upon the Company's assessment of its derivative contracts at December
31, 2001, it reported (i) a net current asset of $20.6 million and non-current
asset of $1.7 million and (ii) accumulated other comprehensive income of $14.5
million, net of income taxes of $7.8 million. The Company recognized no
ineffective component of the derivatives in earnings in 2001. In connection
with monthly settlements, the Company recognized net hedging losses in revenues
of $9.6 million and $18.7 million in 2001 and 2000, respectively. Based on
future natural gas prices as of December 31, 2001, the Company would reclassify
$20.6 million from accumulated other comprehensive income to earnings within
the next 12 months. The amounts ultimately reclassified into earnings will vary
due to changes in the fair value of the open derivative contracts prior to
settlement.

Item 8.  Financial Statements and Supplementary Data

   The consolidated financial statements and supplementary data of the Company
appear on pages 38 through 61 hereof and are incorporated by reference into
this Item 8. Selected quarterly financial data is set forth in Note 13 of the
Notes to Consolidated Financial Statements, which is incorporated herein by
reference.

                                      35

<PAGE>

Item 9.  Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure

   There have been no changes in or disagreements with the Company's
accountants regarding accounting principles or practices or financial statement
disclosures.

                                   PART III

   The Company's Definitive Proxy Statement for its 2002 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this annual report
on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide
the information required under Part III (Items 10, 11, 12 and 13).

                                    PART IV

Item 14.  Exhibits, Financial Statement Schedules, and Reports on Form 8-K

   (a) Financial Statements

      (1) and (2) Financial Statements and Schedules

          See "Index to Consolidated Financial Statements" on page 38.

      (3) Exhibits

          See "Exhibit Index" on page 62.

   The management contracts and compensatory plans or arrangements required to
be filed as exhibits to this report are as follows:

<TABLE>
<CAPTION>
Exhibit
Number                                             Description
-------                                            -----------
<C>     <S>

 10.2   --Amended and Restated 1998 Spinnaker Stock Option Plan (incorporated by reference to Exhibit
          10.2 to Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))

 10.6   --Employment Agreement between Spinnaker and Roger L. Jarvis dated December 20, 1996, as
          amended (incorporated by reference to Exhibit 10.6 to Spinnaker's Registration Statement on
          Form S-1 (Commission File No. 333-83093))

 10.7   --Employment Agreement between Spinnaker and William D. Hubbard dated February 24, 1997, as
          amended (incorporated by reference to Exhibit 10.8 to Spinnaker's Registration Statement on
          Form S-1 (Commission File No. 333-83093))

 10.8   --Employment Agreement between Spinnaker and Kelly M. Barnes dated February 24, 1997, as
          amended (incorporated by reference to Exhibit 10.9 to Spinnaker's Registration Statement on
          Form S-1 (Commission File No. 333-83093))

 10.9   --1999 Spinnaker Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to Spinnaker's
          Registration Statement on Form S-1 (Commission File No. 333-83093))

 10.10  --1999 Spinnaker Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.11 to
          Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))

 10.12  --Adjunct Stock Option Plan (incorporated by reference to Exhibit 4.3 to Spinnaker's Registration
          Statement on Form S-8 (Commission File No. 333-36592))

 10.13  --Spinnaker Exploration Company 2000 Stock Option Plan (incorporated by reference to Exhibit
          10.13 to Spinnaker's Annual Report on Form 10-K for the year ended December 31, 2000)

 10.14  --Spinnaker Exploration Company 2001 Stock Incentive Plan, as amended (incorporated by
          reference to Exhibit 10.2 to Spinnaker's Registration Statement on Form S-8 (Commission File
          No. 333-61888))
</TABLE>

   (b) Reports on Form 8-K

      The Company filed a Form 8-K dated January 22, 2002 that summarized its
   commodity price risk management positions for 2002 and 2003.

                                      36

<PAGE>

                                  SIGNATURES

   Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.

March 8, 2002
                                          SPINNAKER EXPLORATION COMPANY

                                                  /s/  ROGER L. JARVIS
                                          By: _________________________________
                                                     Roger L. Jarvis
                                          Chairman, President, Chief Executive
                                                   Officer and Director

   Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant in the capacities and on the dates indicated.

          Signature                       Title                 Date
          ---------                       -----                 ----

    /s/  ROGER L. JARVIS      Chairman, President, Chief    March 8, 2002
-----------------------------   Executive Officer and
       Roger L. Jarvis          Director

    /s/  ROBERT M. SNELL      Vice President, Chief         March 8, 2002
-----------------------------   Financial Officer and
       Robert M. Snell          Secretary (Principal
                                Financial Officer)

   /s/  JEFFREY C. ZARUBA     Vice President, Treasurer and March 8, 2002
-----------------------------   Assistant Secretary
      Jeffrey C. Zaruba         (Principal Accounting
                                Officer)

   /s/  SHELDON R. ERIKSON    Director                      March 8, 2002
-----------------------------
     Sheldon R. Erikson

   /s/  JEFFREY A. HARRIS     Director                      March 8, 2002
-----------------------------
      Jeffrey A. Harris

   /s/  MICHAEL E. MCMAHON    Director                      March 8, 2002
-----------------------------
     Michael E. McMahon

   /s/  MICHAEL G. MORRIS     Director                      March 8, 2002
-----------------------------
      Michael G. Morris

    /s/  HOWARD H. NEWMAN     Director                      March 8, 2002
-----------------------------
      Howard H. Newman

    /s/  MICHAEL E. WILEY     Director                      March 8, 2002
-----------------------------
      Michael E. Wiley

                                      37

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                  INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                                                        Page
                                                                                                        ----
<S>                                                                                                     <C>
Report of Independent Public Accountants...............................................................  39
Consolidated Balance Sheets as of December 31, 2001 and 2000...........................................  40
Consolidated Statements of Operations for each of the three years in the period ended December 31, 2001  41
Consolidated Statements of Equity for each of the three years in the period ended December 31, 2001....  42
Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2001  43
Notes to Consolidated Financial Statements.............................................................  44
Schedule II--Valuation and Qualifying Accounts and Reserves............................................  64
</TABLE>

   With the exception of Schedule II--Valuation and Qualifying Accounts and
Reserves, all other schedules for which provision is made in the applicable
rules and regulations of the Securities and Exchange Commission have been
omitted as the schedules are not required under the related instructions, are
not applicable or the information required thereby is set forth in the
Consolidated Financial Statements or the Notes thereto.

                                      38

<PAGE>

                   REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors and Stockholders of
Spinnaker Exploration Company:

   We have audited the accompanying consolidated balance sheets of Spinnaker
Exploration Company (a Delaware corporation) and subsidiaries, as of December
31, 2001 and 2000, and the related consolidated statements of operations,
equity and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.

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

   In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Spinnaker
Exploration Company and subsidiaries as of December 31, 2001 and 2000, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

   As explained in Note 1 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for its
derivative instruments.

   Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The financial statement schedule listed
in the index to financial statements is presented for purposes of complying
with the Securities and Exchange Commission's rules and is not part of the
basic financial statements. This schedule has been subjected to the auditing
procedures applied in the audits of the basic financial statements and, in our
opinion, fairly states in all material respects the financial data required to
be set forth therein in relation to the basic financial statements taken as a
whole.

                                          ARTHUR ANDERSEN LLP

Houston, Texas
February 15, 2002

                                      39

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                          CONSOLIDATED BALANCE SHEETS

                (In thousands, except share and per share data)

<TABLE>
<CAPTION>
                                                                                      As of December 31,
                                                                                     -------------------
                                                                                       2001       2000
                                      ASSETS                                         ---------  --------
<S>                                                                                  <C>        <C>
CURRENT ASSETS:
   Cash and cash equivalents........................................................ $  14,061  $ 63,910
   Short-term investments...........................................................        --    22,387
   Accounts receivable, net of allowance for doubtful accounts of $3,059 and $0 at
     December 31, 2001 and 2000, respectively.......................................    24,129    45,594
   Hedging assets...................................................................    20,593        --
   Other............................................................................     3,664     6,402
                                                                                     ---------  --------
       Total current assets.........................................................    62,447   138,293
PROPERTY AND EQUIPMENT:
   Oil and gas, on the basis of full-cost accounting:
     Proved properties..............................................................   575,806   293,002
     Unproved properties and properties under development, not being amortized......   102,881    83,165
   Other............................................................................     7,245     5,642
                                                                                     ---------  --------
                                                                                       685,932   381,809
   Less--Accumulated depreciation, depletion and amortization.......................  (163,359)  (77,428)
                                                                                     ---------  --------
       Total property and equipment.................................................   522,573   304,381
OTHER ASSETS........................................................................     2,296        30
                                                                                     ---------  --------
       Total assets................................................................. $ 587,316  $442,704
                                                                                     =========  ========

                              LIABILITIES AND EQUITY
CURRENT LIABILITIES:
   Accounts payable................................................................. $  32,383  $ 28,616
   Accrued liabilities and other....................................................    50,718    35,672
                                                                                     ---------  --------
       Total current liabilities....................................................    83,101    64,288
DEFERRED INCOME TAXES...............................................................    45,723    17,157
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY:
   Preferred stock, $0.01 par value; 10,000,000 shares authorized; no shares issued
     and outstanding at December 31, 2001 and 2000, respectively....................        --        --
   Common stock, $0.01 par value; 50,000,000 shares authorized; 27,308,912 shares
     issued and 27,293,264 shares outstanding at December 31, 2001 and 26,494,593
     shares issued and 26,476,817 shares outstanding at December 31, 2000...........       273       265
   Additional paid-in capital.......................................................   365,993   349,506
   Retained earnings................................................................    77,758    11,532
   Less: Treasury stock, at cost, 15,648 and 17,776 shares at December 31, 2001 and
     2000, respectively.............................................................       (39)      (44)
   Accumulated other comprehensive income...........................................    14,507        --
                                                                                     ---------  --------
       Total equity.................................................................   458,492   361,259
                                                                                     ---------  --------
       Total liabilities and equity................................................. $ 587,316  $442,704
                                                                                     =========  ========
</TABLE>

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

                                      40

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                     CONSOLIDATED STATEMENTS OF OPERATIONS

                     (In thousands, except per share data)

<TABLE>
<CAPTION>
                                                                             For the Year Ended December 31,
                                                                             ------------------------------
                                                                               2001         2000      1999
                                                                             --------     --------  -------
<S>                                                                          <C>          <C>       <C>
REVENUES.................................................................... $210,376     $121,383  $34,258
EXPENSES:
   Lease operating expenses.................................................   12,132        9,009    5,411
   Depreciation, depletion and amortization--natural gas and oil properties.   85,059       47,451   20,788
   Depreciation and amortization--other.....................................      398          309      213
   General and administrative...............................................    9,443        7,350    4,860
   Charges related to Enron bankruptcy......................................    3,059           --       --
   Stock appreciation rights expense........................................       --           --    1,651
                                                                             --------     --------  -------
       Total expenses.......................................................  110,091       64,119   32,923
                                                                             --------     --------  -------
INCOME FROM OPERATIONS......................................................  100,285       57,264    1,335
OTHER INCOME (EXPENSE):
   Interest income..........................................................    3,574        2,908      528
   Interest expense, net....................................................     (381)        (748)  (2,805)
                                                                             --------     --------  -------
       Total other income (expense).........................................    3,193        2,160   (2,277)
                                                                             --------     --------  -------
INCOME (LOSS) BEFORE INCOME TAXES...........................................  103,478       59,424     (942)
   Income tax provision.....................................................   37,252       20,858       --
                                                                             --------     --------  -------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN
  ACCOUNTING PRINCIPLE......................................................   66,226       38,566     (942)
   Cumulative effect of change in accounting principle (Note 1).............       --           --     (395)
                                                                             --------     --------  -------
NET INCOME (LOSS)...........................................................   66,226       38,566   (1,337)
ACCRUAL OF DIVIDENDS ON PREFERRED STOCK.....................................       --           --   (7,911)
                                                                             --------     --------  -------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS.......................... $ 66,226     $ 38,566  $(9,248)
                                                                             ========     ========  =======
BASIC INCOME (LOSS) PER COMMON SHARE:
   Income (loss) before cumulative effect of change in accounting principle. $   2.45     $   1.70  $ (1.06)
   Cumulative effect of change in accounting principle......................       --           --    (0.05)
                                                                             --------     --------  -------
NET INCOME (LOSS) PER COMMON SHARE.......................................... $   2.45     $   1.70  $ (1.11)
                                                                             ========     ========  =======
DILUTED INCOME (LOSS) PER COMMON SHARE:
   Income (loss) before cumulative effect of change in accounting principle. $   2.34     $   1.61  $ (1.06)
   Cumulative effect of change in accounting principle......................       --           --    (0.05)
                                                                             --------     --------  -------
NET INCOME (LOSS) PER COMMON SHARE.......................................... $   2.34     $   1.61  $ (1.11)
                                                                             ========     ========  =======
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
  OUTSTANDING:
   Basic....................................................................   27,079       22,679    8,355
                                                                             ========     ========  =======
   Diluted..................................................................   28,360       24,011    8,355
                                                                             ========     ========  =======
</TABLE>

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

                                      41

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                       CONSOLIDATED STATEMENTS OF EQUITY

          (In thousands, except shares and dividends per share data)

<TABLE>
<CAPTION>
                                                                                  Retained             Accumulated
                                 Shares Issued         Par Value     Additional   Earnings                Other
                             ---------------------- ----------------  Paid-In   (Accumulated Treasury Comprehensive  Total
                             Pref-erred-   Common   Preferred Common  Capital     Deficit)    Stock      Income      Equity
                             ----------- ---------- --------- ------ ---------- ------------ -------- ------------- --------
<S>                          <C>         <C>        <C>       <C>    <C>        <C>          <C>      <C>           <C>
Balance, December 31, 1998..  3,030,920   4,082,200   $ 30     $ 20   $ 74,649    $(17,786)   $  --     $     --    $ 56,913
  Net loss..................         --          --     --       --         --      (1,337)      --           --      (1,337)

  Comprehensive loss........

  Common stock split........         --          --     --       20        (20)         --       --           --          --
  Common stock issuance.....         --   9,076,096     --       91    111,260          --       --           --     111,351
  Exercise of stock options.         --       5,808     --       --         29          --       --           --          29
  Preferred stock dividends
   ($3.00 per share)........         --          --     --       --         --      (7,911)      --           --      (7,911)
  Conversion of preferred
   stock to common stock.... (3,030,920)  6,061,840    (30)      61        (31)         --       --           --          --
  Reinvestment of
   preferred stock
   dividends into
   common stock.............         --   1,200,248     --       12     16,299          --       --           --      16,311
  Stock compensation
   costs....................         --          --     --       --        150          --       --           --         150
  Stock appreciation rights
   termination..............         --          --     --       --      1,651          --       --           --       1,651
  Treasury stock............         --          --     --       --         --          --      (55)          --         (55)
                             ----------  ----------   ----     ----   --------    --------    -----     --------    --------
Balance, December 31, 1999..         --  20,426,192     --      204    203,987     (27,034)     (55)          --     177,102
  Net income................         --          --     --       --         --      38,566       --           --      38,566

  Comprehensive income......

  Common stock issuance.....         --   5,600,000     --       56    138,342          --       --           --     138,398
  Exercise of stock options.         --     462,478     --        5      3,195          --       11           --       3,211
  Employer contributions
   to 401(k) Plan...........         --       5,923     --       --        148          --       --           --         148
  Stock compensation
   costs....................         --          --     --       --        158          --       --           --         158
  Tax benefit associated
   with exercise of non-
   qualified stock options..         --          --     --       --      3,676          --       --           --       3,676
                             ----------  ----------   ----     ----   --------    --------    -----     --------    --------
Balance, December 31, 2000..         --  26,494,593     --      265    349,506      11,532      (44)          --     361,259
  Net income................         --          --     --       --         --      66,226       --           --      66,226
  Other comprehensive
   income, net of tax:
   Cumulative effect of
    accounting change
    for derivative
    financial
    instruments.............         --          --     --       --         --          --       --      (27,126)    (27,126)
   Net change in fair
    value of derivative
    financial
    instruments.............         --          --     --       --         --          --       --       35,502      35,502
   Financial derivative
    settlements
    reclassed to income.....         --          --     --       --         --          --       --        6,131       6,131

  Comprehensive income......

  Exercise of stock options.         --     808,863     --        8      7,142          --        5           --       7,155
  Employer contributions
   to 401(k) Plan...........         --       5,456     --       --        216          --       --           --         216
  Stock compensation costs..         --          --     --       --        114          --       --           --         114
  Tax benefit associated
   with exercise of non-
   qualified stock options..         --          --     --       --      9,015          --       --           --       9,015
                             ----------  ----------   ----     ----   --------    --------    -----     --------    --------
Balance, December 31, 2001..         --  27,308,912   $ --     $273   $365,993    $ 77,758    $ (39)    $ 14,507    $458,492
                             ==========  ==========   ====     ====   ========    ========    =====     ========    ========
</TABLE>
<TABLE>
<CAPTION>


                             Comprehensive
                             Income (Loss)
                             -------------
<S>                          <C>
Balance, December 31, 1998..
  Net loss..................   $ (1,337)
                               --------
  Comprehensive loss........   $ (1,337)
                               ========
  Common stock split........
  Common stock issuance.....
  Exercise of stock options.
  Preferred stock dividends
   ($3.00 per share)........
  Conversion of preferred
   stock to common stock....
  Reinvestment of
   preferred stock
   dividends into
   common stock.............
  Stock compensation
   costs....................
  Stock appreciation rights
   termination..............
  Treasury stock............

Balance, December 31, 1999..
  Net income................   $ 38,566
                               --------
  Comprehensive income......   $ 38,566
                               ========
  Common stock issuance.....
  Exercise of stock options.
  Employer contributions
   to 401(k) Plan...........
  Stock compensation
   costs....................
  Tax benefit associated
   with exercise of non-
   qualified stock options..

Balance, December 31, 2000..
  Net income................   $ 66,226
  Other comprehensive
   income, net of tax:
   Cumulative effect of
    accounting change
    for derivative
    financial
    instruments.............    (27,126)
   Net change in fair
    value of derivative
    financial
    instruments.............     35,502
   Financial derivative
    settlements
    reclassed to income.....      6,131
                               --------
  Comprehensive income......   $ 80,733
                               ========
  Exercise of stock options.
  Employer contributions
   to 401(k) Plan...........
  Stock compensation costs..
  Tax benefit associated
   with exercise of non-
   qualified stock options..

Balance, December 31, 2001..

</TABLE>

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

                                      42

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

                                (In thousands)

<TABLE>
<CAPTION>
                                                                          For the Year Ended December 31,
                                                                          ------------------------------
                                                                            2001       2000       1999
                                                                          ---------  ---------  --------
<S>                                                                       <C>        <C>        <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
 Net income (loss)....................................................... $  66,226  $  38,566  $ (1,337)
 Adjustments to reconcile net income (loss) to net cash provided by (used
   in) operating activities:
   Depreciation, depletion and amortization..............................    85,457     47,760    21,001
   Deferred income tax expense...........................................    36,977     20,833        --
   Other.................................................................       549        306        --
   Stock appreciation rights expense.....................................        --         --     1,651
   Cumulative effect of change in accounting principle...................        --         --       395
   Change in components of working capital:
     Accounts receivable.................................................    21,465    (34,799)   (6,974)
     Accounts payable and accrued liabilities............................    (3,216)    14,861      (636)
     Other current assets and other......................................     1,979     (5,523)      805
                                                                          ---------  ---------  --------
       Net cash provided by operating activities.........................   209,437     82,004    14,905

CASH FLOWS FROM INVESTING ACTIVITIES:
 Oil and gas properties..................................................  (302,046)  (198,787)  (78,894)
 Change in property related payables.....................................    14,821     36,976    (5,291)
 Proceeds from sale of natural gas and oil assets........................        --      5,971        --
 Purchases of other property and equipment...............................    (1,603)    (1,928)     (916)
 Purchases of short-term investments.....................................   (29,627)   (22,387)       --
 Sales of short-term investments.........................................    52,014         --        --
                                                                          ---------  ---------  --------
       Net cash used in investing activities.............................  (266,441)  (180,155)  (85,101)

CASH FLOWS FROM FINANCING ACTIVITIES:
 Proceeds from borrowings................................................        --     17,000    53,000
 Payments on borrowings..................................................        --    (17,000)  (72,000)
 Proceeds from issuance of common stock..................................        --    138,936   108,720
 Common stock issuance costs.............................................        --       (538)   (1,109)
 Proceeds from exercise of stock options.................................     7,155      3,211        29
 Preferred stock dividends...............................................        --         --       (78)
 Acquisition of treasury stock...........................................        --         --       (55)
                                                                          ---------  ---------  --------
       Net cash provided by financing activities.........................     7,155    141,609    88,507
                                                                          ---------  ---------  --------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.....................   (49,849)    43,458    18,311
CASH AND CASH EQUIVALENTS, beginning of year.............................    63,910     20,452     2,141
                                                                          ---------  ---------  --------
CASH AND CASH EQUIVALENTS, end of year................................... $  14,061  $  63,910  $ 20,452
                                                                          =========  =========  ========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
 Cash paid for interest, net of amounts capitalized...................... $     190  $     380  $  2,591
 Cash paid for income taxes, net.........................................       275         25        --
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING
  ACTIVITIES:
 Reinvestment of preferred dividends payable into common stock........... $      --  $      --  $ 16,311
 Issuance of common stock for amended seismic data rights................        --         --     2,900
</TABLE>

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

                                      43

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  Organization and Summary of Significant Accounting Policies:

   Spinnaker Exploration Company ("Spinnaker" or the "Company") was formed in
1996 and engages in the exploration, development and production of natural gas
and oil properties in the U.S. Gulf of Mexico.

   On September 28, 1999, the Company priced its initial public offering of
8,000,000 shares of common stock, par value $0.01 per share ("Common Stock"),
and commenced trading the following day. After payment of underwriting
discounts and commissions, the Company received net proceeds of $108.7 million
on October 4, 1999. With a portion of the proceeds, the Company retired all
outstanding debt of $72.0 million. In connection with the initial public
offering, the Company converted all outstanding Series A Convertible Preferred
Stock, par value $0.01 per share ("Preferred Stock"), into shares of Common
Stock, and certain shareholders reinvested preferred dividends payable of $16.3
million into shares of Common Stock.

   A summary of significant accounting policies followed in the preparation of
the accompanying consolidated financial statements is set forth below:

  General

   The accompanying consolidated financial statements of the Company have been
prepared in accordance with accounting principles generally accepted in the
United States and pursuant to the rules and regulations of the Securities and
Exchange Commission (the "Commission").

  Principles of Consolidation

   The accompanying consolidated financial statements include the activities
and accounts of the Company and its subsidiaries, all of which are wholly
owned. All significant intercompany transactions and balances are eliminated in
consolidation.

  Use of Estimates

   The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at 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 depreciation, depletion and amortization ("DD&A")
of proved natural gas and oil properties. Natural gas and oil 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.

  Cash Equivalents

   The Company considers all highly liquid investments with a maturity of three
months or less when purchased to be cash equivalents.

  Short-Term Investments

   Short-term investments include highly liquid investments in commercial paper
with maturities greater than three months when purchased.

  Other Current Assets

   Other current assets include unamortized debt financing costs of $328,000
and $114,000 at December 31, 2001 and 2000, respectively. Other non-current
assets include unamortized debt financing costs of $554,000 at

                                      44

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

December 31, 2001. These costs are amortized to interest expense over the
three-year term of the related credit facility. Amortization of these and other
debt financing costs included in interest expense was $219,000, $354,000 and
$576,000 for the years ended December 31, 2001, 2000 and 1999, respectively.
See Note 3.

  Natural Gas and Oil Properties

   The Company uses the full cost method of accounting for its investment in
natural gas and oil properties. Under this method, all acquisition, exploration
and development costs, including certain related employee costs, incurred for
the purpose of exploring for natural gas and oil are capitalized. Such amounts
include the cost of drilling and equipping productive wells, dry hole costs,
lease acquisition costs, delay rentals and costs related to such activities.
Exclusive of field-level costs, Spinnaker capitalized $5.1 million, $3.8
million and $2.5 million of general and administrative costs in 2001, 2000 and
1999, respectively. These capitalized costs are directly related to exploration
activities and include salaries, employee benefits, costs of consulting
services and other related expenses. Costs associated with production and
general corporate activities are expensed in the period incurred. Interest
costs related to unproved properties and properties under development are also
capitalized to natural gas and oil properties. Spinnaker capitalized interest
of $0, $17,000 and $966,000 in 2001, 2000 and 1999, respectively. Sales of
natural gas and oil 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 reserves of natural gas and oil.

   The Company computes the provision for DD&A of natural gas and oil
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 dismantlement, restoration and abandonment costs, net of estimated salvage
values. 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
applicable 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.
The Company has excluded from amortization a portion of the estimated future
expenditures associated with common development costs on one of its deep water
discoveries based on existing proved reserves to total proved reserves expected
to be established upon completion of the deep water project.

   Capitalized costs of natural gas and oil properties, net of accumulated DD&A
and related deferred taxes, are limited to the estimated future net cash flows
from proved natural gas and oil reserves, including the effects of hedging
activities, discounted at 10 percent, plus the lower of cost or fair value of
unproved properties, as adjusted for related income tax effects (the full cost
ceiling). If capitalized costs exceed the full cost ceiling, the excess is
charged to write-down of natural gas and oil properties in the quarter in which
the excess occurs. Given the volatility of natural gas and oil prices, it is
reasonably possible that the Company's estimate of discounted future net cash
flows from proved natural gas and oil reserves will change in the near term. If
natural gas and oil prices decline, even if for only a short period of time, or
if the Company has downward revisions to its estimated proved reserves, it is
possible that write-downs of natural gas and oil properties could occur in the
future.

   The costs associated with unevaluated leasehold acreage, unamortized seismic
data, wells currently drilling and capitalized interest are not initially
included in the amortization base. Leasehold costs are either transferred to
the amortization base with the costs of drilling the related well or are
assessed quarterly for possible

                                      45

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

impairment or reduction in value. Leasehold costs are transferred to the
amortization base if a reduction in value has occurred. Of the $102.9 million
of net unproved property costs at December 31, 2001 excluded from the
amortizable base, net costs of $19.7 million, $42.5 million and $12.3 million
were incurred in 2001, 2000 and 1999, respectively, and $28.4 million was
incurred prior to 1999. The majority of the costs will be evaluated over the
next four years.

   Substantially all the Company's exploration activities are conducted jointly
with others and, accordingly, the natural gas and oil property balances reflect
only its proportionate interest in such activities.

  Other Property and Equipment

   Other property and equipment consists of computer hardware and software,
office furniture and leasehold improvements. The Company is depreciating these
assets using the straight-line method based upon estimated useful lives ranging
from three to five years.

  Organization Costs

   In April 1998, the American Institute of Certified Public Accountants issued
Statement of Position 98-5 ("SOP 98-5"), "Reporting on the Costs of Start-Up
Activities," which requires that costs for start-up activities and organization
costs be expensed as incurred and not capitalized as had previously been
allowed. SOP 98-5 was effective for financial statements for fiscal years
beginning after 1998. The Company adopted this policy in the first quarter of
1999 and recorded a charge related to this accounting change of $395,000 in
conjunction with the write-off of previously capitalized organization costs.

  Revenue Recognition Policy

   The Company records as revenue only that portion of production sold and
delivered and allocable to its ownership interest in the related property.
Imbalances arise when a purchaser takes delivery of more or less volume from a
property than the Company's actual interest in the production from that
property. Such imbalances are reduced either by subsequent recoupment of
over-and-under deliveries or by cash settlement, as required by applicable
contracts. Under-imbalances included in accounts receivable were $706,000 and
$458,000 at December 31, 2001 and 2000, respectively. Over-imbalances included
in accrued liabilities were $650,000 and $720,000 at December 31, 2001 and
2000, respectively.

  Income Taxes

   Under Statement of Financial Accounting Standards ("SFAS") No. 109,
"Accounting for Income Taxes," deferred income taxes are recognized at each
year-end for the future tax consequences of differences between the tax bases
of assets and liabilities and their financial reporting amounts based on
enacted tax laws and statutory tax rates applicable to the periods in which the
differences are expected to affect taxable income. Valuation allowances are
established when necessary to reduce deferred tax assets to the amount expected
to be realized.

  Stock Options

   In October 1995, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123
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

                                      46

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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 at the
date of the grant over the amount an employee must pay to acquire the Common
Stock. See Note 6.

  Stock Split

   On September 1, 1999, the Company declared a two-for-one stock split on the
Common Stock (the "Stock Split"). All references to the number of common shares
and per share amounts elsewhere in the Consolidated Financial Statements and
Notes thereto have been restated as appropriate to reflect the effect of the
Stock Split for all periods presented.

  New Accounting Pronouncements

   On January 1, 2001, the Company adopted SFAS No. 133, as amended,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
established accounting and reporting standards requiring that all derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in a
derivative's fair value be realized currently in earnings unless specific hedge
accounting criteria are met. Accounting for qualifying hedges allows derivative
gains and losses to offset related results on the hedged item in the statement
of operations and requires a company to formally document, designate and assess
the effectiveness of transactions that qualify for hedge accounting. Upon
adoption of SFAS No. 133 on January 1, 2001, the Company designated its open
derivative contracts as cash flow hedges and recorded (i) a net current
liability of $41.7 million, representing the fair market value of all
derivatives on that date and (ii) a reduction of equity through accumulated
other comprehensive income of $27.1 million, representing the fair market value
of the derivatives as of January 1, 2001, net of income taxes of $14.6 million.

   In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." SFAS No. 143 requires that the fair value of a liability for an
asset retirement obligation be recognized in the period in which it is incurred
with the associated asset retirement costs being capitalized as a part of the
carrying amount of the long-lived asset. SFAS No. 143 also includes disclosure
requirements that provide a description of asset retirement obligations and
reconciliation of changes in the components of those obligations. The Company
currently records its plugging and abandonment costs, net of salvage value,
with respect to its natural gas and oil properties as additional DD&A expense
using the units-of-production method. This statement will require the Company
to recognize a liability for the fair value of its plugging and abandonment
liability, excluding salvage value, with the associated costs as part of its
natural gas and oil property balance. The Company is evaluating the future
financial effects of adopting SFAS No. 143 and expects to adopt the standard
effective January 1, 2003.

  Financial Instruments and Price Risk Management Activities

   At December 31, 2001, the Company's 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. The
Company enters into hedging arrangements from time to time to reduce its
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 costless collars and are placed with major trading counterparties
the Company believes represent minimum credit risks. Under its current hedging
practice, the Company generally does not hedge more than 66 2/3 percent of its
estimated twelve-month production quantities without the prior approval of the
risk management committee of the board of directors.

                                      47

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


  Concentration of Credit Risk

   Financial instruments that potentially subject the Company to concentration
of credit risk consist principally of cash equivalents and trade accounts
receivable. Management believes that the credit risk posed by this
concentration is offset by the creditworthiness of the Company's customer base.

   Derivative contracts also subject the Company to concentration of credit
risk. Management believes that the credit risk posed by this concentration is
mitigated by its hedging policy. The hedging policy requires that (i) at no
time will any hedging agreement of any nature have a counterparty with a
minimum long-term senior unsecured indebtedness rating less than "BBB+" by
Standard & Poors Corporation or "Baa1" by Moody's Investors Services, Inc. at
the time that such counterparty entered into the relevant transaction under
such hedging agreement and (ii) at no time will exposure to any single
counterparty exceed 25 percent of the estimated twelve-month production volumes
from total proved reserves.

   The Company had in place both financial hedge and physical contracts with
Enron North America Corp. at the time it filed for bankruptcy in December 2001.
Spinnaker did not receive payment for fixed price swap contracts totaling $2.1
million, intended to hedge December 2001 natural gas sales, and $1.4 million
related to November 2001 natural gas production sold to Enron entities. The
Company recorded a net reserve of $3.1 million related to these receivables and
has no other exposure to Enron Corp. and its subsidiaries.

  Risk Factors

   The Company's revenues, profitability, cash flow and future growth rates are
substantially dependent upon the price of and demand for natural gas and oil.
Prices for natural gas and oil are subject to wide fluctuations in response to
relatively minor changes in the supply of and demand for natural gas and oil,
market uncertainty and a variety of additional factors that are beyond the
control of the Company. The Company is also dependent upon the continued
success of its exploratory drilling program. Other factors that could affect
revenues, profitability, cash flow and future growth rates include the inherent
uncertainties in reserve estimates, the concentration of production and
reserves in a small number of offshore properties, relatively short production
periods for Gulf of Mexico properties, hedging production and the ability to
replace reserves and finance growth.

2.  Accounts Receivable and Accrued Liabilities:

   Supplemental disclosures related to accounts receivable and accrued
liabilities and other are as follows (in thousands):

<TABLE>
<CAPTION>
                                                              December 31,
                                                            ----------------
                                                             2001     2000
                                                            -------  -------
   <S>                                                      <C>      <C>
   Natural gas and oil sales............................... $10,679  $32,328
   Hedging receivable......................................   2,093       --
   Joint interest billings.................................   8,735   10,466
   Insurance claims receivable.............................   4,593    1,581
   Other receivables.......................................   1,088    1,219
   Allowance for doubtful accounts.........................  (3,059)      --
                                                            -------  -------
      Total accounts receivable............................ $24,129  $45,594
                                                            =======  =======

   Accrued liabilities..................................... $43,510  $35,672
   Deferred income taxes associated with hedging activities   7,208       --
                                                            -------  -------
      Total accrued liabilities and other.................. $50,718  $35,672
                                                            =======  =======
</TABLE>

                                      48

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


3.  Debt:

   In September 1998, the Company entered into an $85.0 million credit
agreement ("Credit Agreement") with certain financial institutions. The Credit
Agreement was secured by the Company's interests in natural gas and oil
properties and by certain guarantees of Petroleum Geo-Services ASA ("PGS") and
Warburg, Pincus Ventures L.P. ("Warburg"). With proceeds from the initial
public offering, the Company paid the outstanding borrowings of $72.0 million
as of October 4, 1999. Interest expense related to the Credit Agreement was
$2.4 million for the year ended December 31, 1999, excluding amounts related to
the stock issuances for guarantees. In consideration for providing guarantees
under the Credit Agreement, PGS and Warburg were entitled to receive Common
Stock. Such stock issuances were accounted for in interest expense at the fair
value of the guarantees provided and amounted to $840,000 in 1999. The overall
weighted average interest rate for borrowings outstanding under the Credit
Agreement was 5.71 percent in 1999. The Credit Agreement was scheduled to
mature on December 31, 1999; however, the Company amended and restated the
original Credit Agreement in October 1999.

   In October 1999, the Company, Bank of Montreal and Credit Suisse First
Boston entered into the $25.0 million Amended and Restated 364-Day Credit
Agreement ("First Amended Credit Agreement"). The weighted average interest
rate for borrowings outstanding under the First Amended Credit Agreement was
8.72 percent in 2000. The First Amended Credit Agreement was amended on July
20, 2000. The Second Amended and Restated Credit Agreement provided a $75.0
million credit facility ("Second Amended Credit Agreement") with an initial
borrowing base of $40.0 million and an original term of 364 days. The borrowing
base as of December 31, 2000 was $30.0 million. The Second Amended Credit
Agreement was renewed for an additional 364-day term on July 18, 2001 before
being terminated on December 28, 2001.

   On December 28, 2001, the Company replaced the Second Amended Credit
Agreement with an unsecured $200.0 million credit facility ("Credit Facility")
with a group of seven banks. The three-year facility has an initial borrowing
base of $125.0 million that is re-determined on April 30 and September 30 each
year. The banks and Spinnaker also have the option to request one additional
re-determination each year. The Company has the option to elect to use a base
interest rate as described below or the LIBOR rate plus, for each such rate, a
spread based on the percent of the borrowing base used at that time. The base
interest rate under the Credit Facility is a fluctuating rate of interest equal
to the higher of either the Toronto-Dominion Bank's base rate for dollar
advances made in the United States or the Federal Funds Rate plus 0.5 percent
per annum. The Credit Facility contains covenants and restrictive provisions,
including the following limitations, subject to some exceptions, where the
Company:

  .  may not incur any other indebtedness from borrowings, except for
     indebtedness arising under hedging agreements, indebtedness incurred in
     the ordinary course of business not to exceed $1.0 million, unsecured
     vendor indebtedness of the Company related to purchases of 2-D and 3-D
     seismic data made in the ordinary course of business in an amount not to
     exceed $25.0 million, other unsecured indebtedness in an amount not to
     exceed $10.0 million in the aggregate;

  .  may not incur any liens upon properties or assets other than permitted
     liens securing indebtedness of up to $1.0 million, liens on the 2-D and
     3-D seismic data securing the indebtedness permitted to acquire such data,
     pledges or deposits to secure hedging agreements up to $15.0 million,
     liens on property required as a condition to enter into a synthetic lease
     transaction in the ordinary course of business and other liens in the
     ordinary course of business;

  .  may not dispose of any assets or properties except obsolete equipment,
     inventory sold in the ordinary course of business, reserves in non-proved
     categories, a second license in certain seismic data, or interests in
     natural gas and oil properties included in the borrowing base in an
     aggregate amount not to exceed $25.0 million in any fiscal year;

                                      49

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


  .  may not make or pay any dividend, distribution or payment in respect of
     capital stock nor purchase, redeem, acquire, retire or permit any
     reduction or retirement of capital stock in excess of $10.0 million in any
     fiscal year;

  .  must maintain the ratio of consolidated current assets to consolidated
     current liabilities as of the end of each fiscal quarter so that it is not
     less than 1.00 to 1.00. For purposes of the calculation, availability
     under the Credit Facility is included as current assets, any payments of
     principal owing under the Credit Facility required to be repaid within one
     year from the time of the calculation are excluded from current
     liabilities and mark-to-market hedging exposure is excluded from both
     current assets and current liabilities;

  .  must maintain a tangible net worth so that it is not less than the sum of
     80 percent of the tangible net worth as of September 30, 2001, plus 50
     percent of the adjusted consolidated net income for each fiscal quarter
     since the closing of the Credit Facility, plus 75 percent of the proceeds
     from the sale of any security, including without limitation, common
     equity, preferred equity or other equity interests or equity securities
     including warrants, options and the like issued after the closing of the
     Credit Facility; and

  .  may not enter into any hedging agreement unless the percent of volumes to
     be hedged to estimated production volumes for such month from total
     internally-projected proved reserves does not exceed: 100 percent for the
     period one to three months from and after the hedging agreement
     transaction date, 66 2/3 percent for the period four to 18 months from and
     after the hedging agreement transaction date and 33 1/3 percent for the
     period 19 to 36 months from and after the hedging agreement transaction
     date. Additionally, at no time will any hedging agreement of any nature
     have a counterparty with a minimum long-term senior unsecured indebtedness
     rating less than "BBB+" by Standard & Poors Corporation or "Baa1" by
     Moody's Investors Services, Inc. at the time that such counterparty
     entered into the relevant transaction under such hedging agreement and at
     no time will exposure to any single counterparty exceed 25 percent of the
     estimated twelve-month production volumes from total proved reserves.

   At December 31, 2001, the Company was in compliance with the covenants and
had no outstanding borrowings under the Credit Facility. As of March 7, 2002,
the Company had outstanding borrowings of $21.0 million under the Credit
Facility.

4.  Seismic Data Agreement:

   The Company and PGS entered into a seismic data agreement ("Data Agreement")
dated December 20, 1996, whereby PGS agreed to transfer to Spinnaker certain
rights to 3-D seismic data in consideration of Spinnaker equity. The Company
accounted for the contribution of the Data Agreement at PGS' cost, which was
immaterial.

   The Company has agreed to purchase $2.0 million of seismic related services
from PGS prior to December 31, 2002. The Company paid to PGS approximately
$397,000, $449,000 and $318,000 in 2001, 2000 and 1999, respectively, for
seismic-related services. Through December 31, 2001, the Company has paid PGS a
total of approximately $1.3 million for seismic-related services. The Company
expects to purchase additional seismic-related services for the remaining
commitment under the Data Agreement during 2002.

   The Data Agreement was amended effective June 30, 1999. The amended Data
Agreement modified the amount, type and geographic coverage of the data and
related information made available to Spinnaker. In exchange for the amended
rights under the Data Agreement, Spinnaker issued to PGS an additional
1,000,000 shares of Common Stock. This transaction was accounted for at PGS'
cost of $2.9 million, pursuant to Staff Accounting Bulletin No. 48.

                                      50

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


5.  Equity:

   Prior to Spinnaker's initial public offering in September 1999, the Company
sold Preferred Stock to various investors. On September 28, 1999, the Company
priced its initial public offering of 8,000,000 shares of Common Stock and
commenced trading the following day. In connection with the initial public
offering, the Company converted all outstanding Preferred Stock into 6,061,840
shares of Common Stock, and certain shareholders reinvested preferred dividends
payable of $16.3 million into 1,200,248 shares of Common Stock. On August 16,
2000, the Company completed a public offering of 5,600,000 shares of Common
Stock at $26.25 per share. After payment of underwriting discounts and
commissions, the Company received net proceeds of $138.9 million. On December
20, 2000, PGS sold its 5,388,743 shares of Common Stock at $29.25 per share.
Spinnaker received no proceeds from this sale.

   On August 31, 1999, the Company approved a two-for-one stock split on the
Common Stock effective September 1, 1999. One additional share was issued for
each share of Common Stock. Par value remained unchanged at $0.01 per share. In
connection with the Stock Split, the Company amended the certificate of
incorporation to increase the authorized number of shares of Common Stock to
50,000,000 shares.

   Spinnaker has an effective shelf registration statement relating to the
potential public offer and sale by the Company or certain affiliates of up to
$300.0 million of any combination of debt securities, preferred stock, common
stock, warrants, stock purchase contracts and trust preferred securities from
time to time. The registration statement does not provide assurance that the
Company will or could sell any such securities.

6.  Stock Plans:

   At December 31, 2001, officers, directors and employees had been granted
options to purchase Common Stock under stock plans adopted in 1998, 1999, 2000
and 2001. The exercise price of each option equals the market price of
Spinnaker's Common Stock on the date of grant. Stock option grants generally
vest ratably over four years, with 20 percent vesting on the date of grant and
20 percent vesting in each of the succeeding four years, and expire after ten
years. In the event of certain significant changes in control of the Company,
all options then outstanding generally will become immediately exercisable in
full.

   In January 1998, the stockholders approved the 1998 Stock Option Plan ("1998
Plan"). The 1998 Plan was amended and restated in September 1999 and authorized
the issuance of 2,673,242 shares of Common Stock. In September 1999, the
stockholders approved the 1999 Stock Incentive Plan ("1999 Plan"). The number
of shares of Common Stock that may be issued under the 1999 Plan may not exceed
1,300,000 shares. The maximum number of shares of Common Stock that may be
subject to awards granted under the 1999 Plan to any one individual during any
calendar year may not exceed 300,000. In connection with the 1999 Plan, the
stockholders approved the Adjunct Stock Option Plan ("Adjunct Plan"). The
number of shares of Common Stock that may be issued under the Adjunct Plan may
not exceed 21,920. In November 2000, the board of directors adopted the 2000
Stock Option Plan ("2000 Plan"). Stockholder approval was not required for the
2000 Plan. The number of shares of Common Stock that may be issued under the
2000 Plan may not exceed 500,000 shares. In May 2001, the stockholders approved
the 2001 Stock Incentive Plan ("2001 Plan"). The number of shares of Common
Stock that may be issued under the 2001 Plan may not exceed 1,500,000 shares.

   The Company applies APB Opinion No. 25 and related interpretations in
accounting for its employee stock-based compensation. In accordance with APB
Opinion No. 25, compensation expense related to stock-based compensation
included in general and administrative expense was approximately $114,000,
$158,000 and $150,000 in 2001, 2000 and 1999, 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

                                      51

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

consistent with the method of SFAS No. 123, "Accounting for Stock-Based
Compensation," the Company's pro forma net income (loss) available to common
stockholders and pro forma net income (loss) per common share would have been
as follows (in thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                             For the Year Ended December 31,
                                                             ------------------------------
                                                               2001       2000       1999
                                                              -------    -------   --------
<S>                                                          <C>        <C>       <C>
Pro forma net income (loss) available to common stockholders $57,379    $35,543   $(10,950)
                                                              =======    =======   ========
Pro forma net income (loss) per common share:
   Basic.................................................... $  2.12    $  1.57   $  (1.31)
                                                              =======    =======   ========
   Diluted.................................................. $  2.02    $  1.48   $  (1.31)
                                                              =======    =======   ========
</TABLE>

   For purposes of the SFAS No. 123 disclosure, the fair value of each option
grant is estimated on the date of grant using the Black-Scholes option-pricing
model with assumptions for grants in 2001, 2000 and 1999 as follows:

<TABLE>
<CAPTION>
                                           For the Year Ended December 31,
                                         -----------------------------------
                                            2001        2000        1999
                                         ----------- ----------- -----------
    <S>                                  <C>         <C>         <C>
    Risk-free interest rate............. 4.85%-5.57% 5.14%-6.82% 4.67%-6.08%
    Volatility factor...................    43.0%       42.5%       54.8%
    Dividend yield......................     0%          0%          0%
    Expected life of the options (years)      4           4          4.5
</TABLE>

   Presented below is a summary of stock option activity.

<TABLE>
<CAPTION>
                                               2001                 2000                 1999
                                       -------------------- -------------------- --------------------
                                                   Weighted             Weighted             Weighted
                                         Shares    Average    Shares    Average    Shares    Average
                                         Under     Exercise   Under     Exercise   Under     Exercise
                                         Option     Price     Option     Price     Option     Price
                                       ----------  -------- ----------  -------- ----------  --------
<S>                                    <C>         <C>      <C>         <C>      <C>         <C>
Outstanding, beginning of year........  3,718,886   $13.80   3,382,974   $10.56   2,526,880   $ 9.11
   Granted............................  1,242,800    37.90     802,470    23.45     866,574    14.74
   Exercised..........................   (810,991)    8.82    (466,558)    6.88      (5,872)    4.97
   Forfeited..........................    (88,139)   17.57          --       --      (4,608)    9.29
                                       ----------           ----------           ----------
Outstanding, end of year..............  4,062,556    22.08   3,718,886    13.80   3,382,974    10.56
                                       ==========           ==========           ==========
Exercisable, end of year..............  2,273,548    16.16   2,364,270    11.38   1,919,019     9.62
                                       ==========           ==========           ==========
Available for grant, end of year......    648,545              303,206              605,676
                                       ==========           ==========           ==========
Weighted average fair value of options
  granted during the year............. $    23.76           $    15.17           $     6.78
                                       ==========           ==========           ==========
</TABLE>

   The Company transferred treasury shares to certain employees in connection
with their exercises of 2,128 and 4,080 options in 2001 and 2000, respectively.
Options to purchase 640 shares of Common Stock forfeited during 1999 are not
available for future grants.

                                      52

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   At December 31, 2001, the following options were outstanding and exercisable
and had the indicated weighted average remaining contractual lives:

<TABLE>
<CAPTION>
                          Outstanding         Exercisable
                      ------------------- -------------------
                                Weighted            Weighted    Weighted
                                 Average             Average    Average
         Range of               Exercise            Exercise   Remaining
      Exercise Prices Number of Price Per Number of Price Per Contractual
         Per Share     Options    Share    Options    Share   Life (Years)
         ---------    --------- --------- --------- --------- ------------
      <S>             <C>       <C>       <C>       <C>       <C>
        $2.50-$5.00     626,824  $ 4.94     602,272  $ 4.95       5.2
       $14.50-$16.13  1,785,312   15.37   1,256,598   15.39       6.7
       $22.25-$31.69    367,420   27.79     134,838   27.61       9.0
       $37.55-$41.73  1,283,000   38.17     279,840   38.21       9.2
                      ---------           ---------
                      4,062,556           2,273,548
                      =========           =========
</TABLE>

   Prior to July 1999, the stock option agreements of two of the Company's
officers provided that they could elect to have the Company deliver shares
equal to the appreciation in the value of the stock over the option price in
lieu of purchasing the amount of shares under option. Based on management's
estimate of the share value of the Company, compensation expense of
approximately $1.7 million was recorded in 1999 related to the stock
appreciation rights of the stock option agreements. In July 1999, these two
officers agreed to eliminate the stock appreciation rights feature of their
stock option agreements.

7.  Earnings Per Share:

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

<TABLE>
<CAPTION>
                                                                           For the Year Ended December 31,
                                                                           ------------------------------
                                                                              2001       2000      1999
                                                                            -------     -------   -------
<S>                                                                        <C>         <C>       <C>
Numerator:
   Net income (loss) available to common stockholders..................... $66,226     $38,566   $(9,248)
                                                                            =======     =======   =======
Denominator:
   Basic weighted average number of shares................................  27,079      22,679     8,355
                                                                            =======     =======   =======
   Dilutive securities:
       Stock options......................................................   1,281       1,332        --
                                                                            -------     -------   -------
   Diluted adjusted weighted average number of shares and assumed
     conversions..........................................................  28,360      24,011     8,355
                                                                            =======     =======   =======
Net income (loss) per common share:
   Basic:
       Income (loss) before cumulative effect of change in accounting
         principle........................................................ $  2.45     $  1.70   $ (1.06)
       Cumulative effect of change in accounting principle................      --          --     (0.05)
                                                                            -------     -------   -------
   Net income (loss) per common share..................................... $  2.45     $  1.70   $ (1.11)
                                                                            =======     =======   =======
   Diluted:
       Income (loss) before cumulative effect of change in accounting
         principle........................................................ $  2.34     $  1.61   $ (1.06)
       Cumulative effect of change in accounting principle................      --          --     (0.05)
                                                                            -------     -------   -------
   Net income (loss) per common share..................................... $  2.34     $  1.61   $ (1.11)
                                                                            =======     =======   =======
</TABLE>

                                      53

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   For purposes of the diluted earnings per share calculations in 2001 and
2000, certain stock options that could potentially dilute earnings per share
are excluded as they were anti-dilutive. In addition, the Preferred Stock and
stock options are considered anti-dilutive in 1999 and not considered in the
calculations.

8.  Major Customers:

   The Company had natural gas and oil sales to four customers accounting for
approximately 32 percent, 23 percent, 21 percent and 17 percent, respectively,
of total natural gas and oil revenues, excluding the effects of hedging
activities, for the year ended December 31, 2001. The Company had natural gas
and oil sales to three customers accounting for approximately 61 percent, 11
percent and 11 percent, respectively, of total natural gas and oil revenues,
excluding the effects of hedging activities, for the year ended December 31,
2000. The Company had natural gas and oil sales to two customers accounting for
68 percent and 32 percent, respectively, of total natural gas and oil revenues,
excluding the effects of hedging activities, for the year ended December 31,
1999. One of the customers in 2001 and 2000 was Enron North America Corp.
Spinnaker no longer sells its natural gas and oil production to this customer.

9.  Related-Party Transactions:

   The Company paid PGS approximately $397,000, $449,000 and $318,000 in 2001,
2000 and 1999, respectively, for seismic-related services.

   The Company paid $17.4 million in 2001 to affiliates of Baker Hughes
Incorporated ("Baker Hughes"), an oilfield services company. Mr. Michael E.
Wiley, a director of Spinnaker, serves as Chairman of the Board, Chief
Executive Officer and President of Baker Hughes. The Company paid $83,000 and
$528,000 in 2001 and 2000, respectively, to Cooper Cameron Corporation ("Cooper
Cameron"), an oilfield services company. Mr. Sheldon R. Erikson, a director of
Spinnaker, serves as Chairman of the Board, Chief Executive Officer and
President of Cooper Cameron. The Company purchases oilfield goods, equipment
and services from Baker Hughes, Cooper Cameron and other companies in the
ordinary course of business. Spinnaker believes that these transactions are at
arms-length and the charges and fees that it pays 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.

   The Data Agreement was amended effective June 30, 1999. In exchange for the
amended rights under the Data Agreement, Spinnaker issued 1,000,000 shares of
Common Stock to PGS. See Note 4.

   From September 30, 1998 through October 4, 1999, PGS and Warburg provided
certain guarantees for the Credit Agreement totaling $75.0 million. See Note 3.

10.  Income Taxes:

   As of December 31, 2001, the Company had approximately $162.2 million of net
operating loss carryforwards, of which $23.0 million, $30.2 million, $39.5
million and $69.5 million expire in 2018, 2019, 2020 and 2021, respectively.

                                      54

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The significant items giving rise to the deferred income tax assets and
liabilities are as follows (in thousands):

<TABLE>
<CAPTION>
                                                           As of December 31,
                                                           ------------------
                                                             2001      2000
                                                           --------  -------
   <S>                                                     <C>       <C>
   Deferred income tax liabilities:
      Basis differences in natural gas and oil properties. $104,141  $50,925
      Hedging activities..................................    7,812       --
                                                           --------  -------
          Total deferred income tax liabilities...........  111,953   50,925
   Deferred income tax assets:
      Net operating losses................................ $ 58,400  $32,836
      Other...............................................      622      932
                                                           --------  -------
          Total deferred income tax assets................   59,022   33,768
                                                           --------  -------
   Net deferred income tax liabilities.................... $ 52,931  $17,157
                                                           ========  =======
</TABLE>

   Tax benefits of $9.0 million and $3.7 million associated with the exercise
of non-qualified stock options during the years ended December 31, 2001 and
2000 are reflected as a component of equity. The deferred income tax liability
includes $7.8 million related to the tax effect of the fair market value of
derivatives at December 31, 2001 as required by SFAS No. 133, as amended.

   Significant components of the provision for income taxes are as follows (in
thousands):

<TABLE>
<CAPTION>
                                         For the Year Ended
                                            December 31,
                                        --------------------
                                         2001    2000   1999
                                        ------- ------- ----
                    <S>                 <C>     <C>     <C>
                    Current............ $   275 $    25 $--
                    Deferred...........  36,977  20,833  --
                                        ------- ------- ---
                       Total provision. $37,252 $20,858 $--
                                        ======= ======= ===
</TABLE>

   The differences between the provision for income taxes and the amount that
would be determined by applying the statutory federal income tax rate of 35
percent to the income (loss) before income taxes are as follows (in thousands):

<TABLE>
<CAPTION>
                                                          For the Year Ended
                                                             December 31,
                                                        ----------------------
                                                         2001    2000    1999
                                                        ------- -------  -----
<S>                                                     <C>     <C>      <C>
Federal income tax expense (benefit) at statutory rates $36,217 $20,798  $(468)
Non-deductible expenses and other......................   1,035     659    601
Valuation allowance....................................      --    (599)  (133)
                                                        ------- -------  -----
   Total provision..................................... $37,252 $20,858  $  --
                                                        ======= =======  =====
</TABLE>

   No net income tax benefit was recognized in 1999 due to the uncertainty of
future realization as the Company had not established a history of net
operating income.

11.  Commitments and Contingencies:

   The Company is, from time to time, party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position, results of
operations or cash flows of the Company.

                                      55

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


  Data Agreement

   The Company has agreed to purchase $2.0 million of seismic-related services
from PGS prior to December 31, 2002. Through December 31, 2001, the Company
paid PGS a total of approximately $1.3 million for these services.

  Employment Contracts

   The Company has employment contracts with certain of its executive officers.
These contracts provide for annual base salaries, bonus compensation, various
benefits and the continuation of salary and benefits for the respective terms
of the agreements in the event of termination of employment for various
reasons, and whether by the Company or the employee. These agreements are
subject to automatic annual extensions unless terminated.

  Employee 401(k) Retirement Plan

   In July 1998, the Company instituted a 401(k) retirement and profit sharing
plan ("401(k) Plan") for its employees. The 401(k) Plan provides that all
qualified employees may defer the maximum income allowed under current tax law.
The 401(k) Plan covers all employees at least 21 years of age who have
completed at least six months of service subsequent to employment.

   Effective January 1, 2000, the Company began matching employee contributions
to the 401(k) Plan. The Company matches 100 percent of each participant's
contributions up to six percent of the participant's annual base salary. In
connection with the employer match, the Company issued 5,456 shares of Common
Stock valued at $216,000 in 2001 and 5,923 shares of Common Stock valued at
$148,000 in 2000.

  Leases

   The Company leases administrative offices under non-cancelable operating
leases expiring in 2007. Certain of the lease agreements require that the
Company pay for utilities, maintenance and other operational expenses of the
building. Additionally, the leases contain escalation clauses. The Company also
leases office equipment and oil and gas equipment under non-cancelable
operating leases. Rental expense was $700,000, $476,000 and $319,000 in 2001,
2000 and 1999, respectively. Minimum future obligations under non-cancelable
operating leases at December 31, 2001 for the following five years are $1.2
million, $1.3 million, $1.3 million, $1.3 million and $1.8 million,
respectively.

  Summary of Contractual Obligations

   The Company had no debt or capital leases outstanding as of December 31,
2001. The Company has incurred obligations in the ordinary course of business
under purchase and service agreements which are not included in the table
below. Obligations under operating leases and the Data Agreement as of December
31, 2001 are as follows:

<TABLE>
<CAPTION>
                                                 Payments Due by Period
                                         --------------------------------------
                                                Less than  1-3    4-5    After
                                         Total   1 Year   Years  Years  5 Years
                                         ------ --------- ------ ------ -------
<S>                                      <C>    <C>       <C>    <C>    <C>
Operating leases........................ $6,914  $1,222   $3,858 $1,834   $--
Unconditional Data Agreement obligations    655     655       --     --    --
                                         ------  ------   ------ ------   ---
   Total................................ $7,569  $1,877   $3,858 $1,834   $--
                                         ======  ======   ====== ======   ===
</TABLE>

                                      56

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


12.  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 Company's swap
contracts 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 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. Some of the master
agreements require the Company to make margin payments to counterparties when
net exposure exceeds a certain threshold. As of March 7, 2002, Spinnaker's
commodity price risk management positions in fixed price natural gas swap
contracts were as follows:

<TABLE>
<CAPTION>
                                         Average Weighted
                                          Daily   Average
                                         Volume  Price Per
                           Period        (MMBtu)   MMBtu
                           ------        ------- ---------
                     <S>                 <C>     <C>
                     First Quarter 2002. 100,000   $3.23
                     Second Quarter 2002  93,407    3.20
                     Third Quarter 2002.  80,000    3.37
                     Fourth Quarter 2002  76,685    3.58
                     Full Year 2003.....  25,000    3.27
</TABLE>

   Based upon the Company's assessment of its derivative contracts at December
31, 2001, it reported (i) a net current asset of $20.6 million and a noncurrent
asset of $1.7 million and (ii) accumulated other comprehensive income of $14.5
million, net of income taxes of $7.8 million. The Company recognized no
ineffective component of the derivatives in earnings in 2001. In connection
with monthly settlements, the Company recognized net hedging losses of $9.6
million in revenues in 2001. Based on future natural gas prices as of December
31, 2001, the Company would reclassify $20.6 million from accumulated other
comprehensive income to earnings within the next 12 months. The amounts
ultimately reclassified into earnings will vary due to changes in the fair
value of the open derivative contracts prior to settlement.

13.  Quarterly Financial Data (Unaudited):

   Quarterly operating results for the years ended December 31, 2001 and 2000
are summarized as follows (in thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                 (Unaudited)
                                            For the Quarter Ended
                                ---------------------------------------------
                                March 31, June 30, September 30, December 31,
                                --------- -------- ------------- ------------
   <S>                          <C>       <C>      <C>           <C>
   2001:
   Revenues....................  $67,453  $59,500     $44,818      $38,605
   Income from operations......   42,792   32,886      16,150        8,457
   Net income..................   28,148   21,781      10,803        5,494
   Net income per common share:
      Basic....................  $  1.05  $  0.80     $  0.40      $  0.20
      Diluted..................  $  1.00  $  0.77     $  0.38      $  0.19
   2000:
   Revenues....................  $13,867  $19,145     $29,755      $58,616
   Income from operations......    2,926    5,323      13,356       35,659
   Net income..................    3,086    5,239       8,229       22,012
   Net income per common share:
      Basic....................  $  0.15  $  0.26     $  0.35      $  0.84
      Diluted..................  $  0.15  $  0.24     $  0.33      $  0.79
</TABLE>

                                      57

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The Company had in place both financial hedge and physical contracts with
Enron North America Corp. at the time it filed for bankruptcy in December 2001.
Spinnaker did not receive payment for fixed price swap contracts intended to
hedge December 2001 natural gas sales and November 2001 natural gas production
sold to Enron entities. The Company recorded a net reserve of $3.1 million in
the fourth quarter of 2001 related to these receivables and has no other
exposure to Enron Corp. and its subsidiaries.

14. Supplementary Financial Information on Natural Gas and Oil Exploration,
    Development and Production Activities (Unaudited):

   The following tables set forth certain historical costs and operating
information related to the Company's natural gas and oil producing activities.

  Capitalized Costs and Costs Incurred

   Capitalized costs and costs incurred related to natural gas and oil
producing activities are summarized below (in thousands):

<TABLE>
<CAPTION>
                                                         As of December 31,
                                                        -------------------
                                                          2001       2000
                                                        ---------  --------
   <S>                                                  <C>        <C>
   Capitalized costs:
      Proved properties................................ $ 575,806  $293,002
      Unproved properties not being amortized..........   102,881    83,165
                                                        ---------  --------
          Total........................................   678,687   376,167
   Accumulated depreciation, depletion and amortization  (158,746)  (73,687)
                                                        ---------  --------
          Net capitalized costs........................ $ 519,941  $302,480
                                                        =========  ========
</TABLE>

   Depreciation, depletion and amortization per Mcfe was $1.60, $1.57 and $1.59
in 2001, 2000 and 1999, respectively.

  Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and
  Development Activities

   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 and costs of
completions, platforms, facilities and pipelines. Costs incurred in oil and
natural gas property acquisition, exploration and development activities are as
follows (in thousands):

<TABLE>
<CAPTION>
                                                 For the Year Ended December 31,
                                                 -------------------------------
                                                    2001       2000      1999
                                                  --------   --------   -------
                <S>                              <C>        <C>        <C>
                Acquisition costs:
                   Unproved..................... $ 34,524   $ 21,421   $13,911
                   Proved.......................       --         --        --
                Exploration costs...............  192,114    121,451    45,152
                Development costs...............   75,882     51,144    23,614
                                                  --------   --------   -------
                       Total costs incurred..... $302,520   $194,016   $82,677
                                                  ========   ========   =======
</TABLE>

                                      58

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


  Estimates of Proved Natural Gas and Oil Reserves

   Proved natural gas and oil reserve quantities and the related discounted
future net cash flows before income taxes are based on estimates prepared by
Ryder Scott Company, L.P., independent petroleum consultants. Such estimates
have been prepared in accordance with guidelines established by the Commission.

   Proved reserves are estimated quantities of natural gas and oil which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.

   The Company's net ownership in estimated quantities of proved natural gas
and oil reserves and changes in net proved reserves, all of which are located
in the Gulf of Mexico, are as follows:

<TABLE>
<CAPTION>
                                                Natural   Oil and   Natural Gas
                                                  Gas    Condensate Equivalents
                                                (MMcf)    (MBbls)     (MMcfe)
                                                -------  ---------- -----------
<S>                                             <C>      <C>        <C>
Proved reserves as of December 31, 1998........  50,946       470      53,766
   Extensions, discoveries and other additions.  43,270     2,039      55,505
   Revisions of previous estimates.............   7,776        83       8,274
   Production.................................. (11,962)     (180)    (13,044)
                                                -------    ------     -------
Proved reserves as of December 31, 1999........  90,030     2,412     104,501
   Extensions, discoveries and other additions.  97,665     1,027     103,829
   Revisions of previous estimates.............   5,248      (116)      4,552
   Production.................................. (28,845)     (225)    (30,194)
                                                -------    ------     -------
Proved reserves as of December 31, 2000........ 164,098     3,098     182,688
   Extensions, discoveries and other additions.  74,531    18,921     188,057
   Revisions of previous estimates............. (11,414)    2,829       5,556
   Production.................................. (51,234)     (310)    (53,094)
                                                -------    ------     -------
Proved reserves as of December 31, 2001(1)..... 175,981    24,538     323,207
                                                =======    ======     =======
Proved developed reserves:
   December 31, 1998...........................  30,806       318      32,715
                                                =======    ======     =======
   December 31, 1999...........................  50,756       384      53,062
                                                =======    ======     =======
   December 31, 2000........................... 112,315     1,042     118,568
                                                =======    ======     =======
   December 31, 2001(1)........................  82,221       748      86,711
                                                =======    ======     =======
</TABLE>
--------
(1) During 2001, Spinnaker participated in a significant deep water oil
    discovery on Green Canyon Blocks 338/339 ("Front Runner") with a 25 percent
    non-operator working interest. The Company participated in five consecutive
    successful wells and sidetracks in testing the reservoirs on these blocks.
    This significant oil discovery has changed Spinnaker's reserve profile.
    Proved oil and condensate reserves were 46 percent of total proved reserves
    at December 31, 2001 compared to 10 percent at December 31, 2000. Of the
    Company's total proved reserves as of December 31, 2001, 73 percent were
    proved undeveloped reserves. Front Runner represented more than 50 percent
    of total proved undeveloped reserves.

  Standardized Measure of Discounted Future Net Cash Flows

   The standardized measure of discounted future net cash flows from production
of proved reserves was developed as follows:

  .  Estimates are made of quantities of proved reserves and the future periods
     during which they are expected to be produced based on year-end economic
     conditions.

                                      59

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


  .  The estimated future gross revenues of proved reserves are priced on the
     basis of year-end market prices.

  .  The future gross revenue streams are reduced by estimated future costs to
     develop and to produce the proved reserves, as well as certain abandonment
     costs based on year-end cost estimates and the estimated effect of future
     income taxes.

  .  Future income taxes are computed by applying the statutory tax rate to
     future net cash flows reduced by the tax basis of the properties, the
     estimated permanent differences applicable to future natural gas and oil
     producing activities and tax carryforwards.

   The standardized measure of discounted future net cash flows is not intended
to present the fair market value of the Company's natural gas and oil reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes
in prices and costs, an allowance for return on investment and the risks
inherent in reserve estimates. Given the volatility of natural gas and oil
prices, it is reasonably possible that the Company's estimate of discounted
future net cash flows from proved natural gas and oil reserves will change in
the near term. If natural gas and oil prices decline, even if for only a short
period of time, or if the Company has significant downward revisions to its
estimated proved reserves, it is possible that write-downs of natural gas and
oil properties could occur in the future. The standardized measure of
discounted future net cash flows relating to proved natural gas and oil
reserves is as follows (in thousands):

<TABLE>
<CAPTION>
                                                         For the Year Ended December 31,
                                                         -------------------------------
                                                           2001        2000       1999
                                                         ---------  ----------  --------
<S>                                                      <C>        <C>         <C>
Future cash inflows(1).................................. $ 944,861  $1,730,754  $275,539
Future operating expenses...............................  (164,105)    (60,259)  (36,396)
Future development costs................................  (191,711)    (68,929)  (48,717)
                                                         ---------  ----------  --------
Future net cash flows before income taxes...............   589,045   1,601,566   190,426
Future income taxes(2)..................................  (120,489)   (516,488)       --
                                                         ---------  ----------  --------
Future net cash flows...................................   468,556   1,085,078   190,426
10 percent annual discount..............................  (139,000)   (185,941)  (38,862)
                                                         ---------  ----------  --------
Standardized measure of discounted future net cash flows $ 329,556  $  899,137  $151,564
                                                         =========  ==========  ========
</TABLE>
--------
(1) Weighted average market prices for natural gas and oil used to calculate
    future cash inflows were $2.71, $9.99 and $2.37 per Mcf of natural gas and
    $19.23, $30.41 and $25.70 per barrel of oil in 2001, 2000 and 1999,
    respectively.
(2) Net operating loss carryforwards and basis in natural gas and oil
    properties eliminated the need for future income taxes in 1999.

                                      60

<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   The primary sources of change in the standardized measure of discounted
future net cash flows are as follows (in thousands):

<TABLE>
<CAPTION>
                                                                     For the Year Ended December 31,
                                                                     ------------------------------
                                                                       2001       2000       1999
                                                                     ---------  ---------  --------
<S>                                                                  <C>        <C>        <C>
Standardized measure, beginning of year............................. $ 899,137  $ 151,564  $ 52,109
   Extensions and discoveries, net of related costs.................   198,709    719,694    75,572
   Sales of natural gas and oil produced, net of production costs...  (207,824)  (131,030)  (28,097)
   Net changes in prices and production costs.......................  (958,755)   486,496    22,869
   Change in future development costs...............................   (18,959)    (3,501)   (1,957)
   Development costs incurred during the period that reduced future
     development costs..............................................    47,463     37,851    14,494
   Revisions of quantity estimates..................................     6,092     34,749    13,624
   Accretion of discount............................................   132,067     15,156     5,211
   Net change in income taxes.......................................   335,952   (421,535)       --
   Change in production rates and other.............................  (104,326)     9,693    (2,261)
                                                                     ---------  ---------  --------
Standardized measure, end of year................................... $ 329,556  $ 899,137  $151,564
                                                                     =========  =========  ========
</TABLE>

                                      61

<PAGE>

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
Exhibit
Number                                              Description
------                                              -----------
<C>     <S>
 3.1    --Certificate of Incorporation of Spinnaker, as amended (incorporated by reference to Exhibit 3.1 to
        Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
 3.2    --Restated Bylaws of Spinnaker (incorporated by reference to Exhibit 3.2 to Spinnaker's Registration
        Statement on Form S-1 (Commission File No. 333-83093))
 4.1    --Specimen Common Stock certificate (incorporated by reference to Exhibit 4.1 to Spinnaker's
        Registration Statement on Form S-3 (Commission File No. 333-72238))
10.1    --Second Amended and Restated Data Contribution Agreement between Petroleum Geo-Services
        ASA, Seismic Energy Holdings, Inc., Spinnaker Exploration Company, L.L.C. and Spinnaker dated
        June 30, 1999 (incorporated by reference to Exhibit 10.1 to Spinnaker's Registration Statement on
        Form S-1 (Commission File No. 333-83093))
10.2    --Amended and Restated 1998 Spinnaker Stock Option Plan (incorporated by reference to Exhibit 10.2
        to Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
10.3    --Amended and Restated Stockholders Agreement by and among Spinnaker, Warburg, Pincus
        Ventures, Petroleum Geo-Services, Roger L. Jarvis, James M. Alexander, William D. Hubbard,
        Kelly M. Barnes and certain other stockholders of Spinnaker (including the Registration Rights
        Agreement as Exhibit A to the Stockholders Agreement) (incorporated by reference to Exhibit 10.3
        to Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
10.3.1  --First Amendment to the Amended and Restated Stockholders Agreement by and among Spinnaker,
        Warburg, Pincus Ventures, Petroleum Geo-Services, Roger L. Jarvis, James M. Alexander, William
        D. Hubbard, Kelly M. Barnes and certain other stockholders of Spinnaker (incorporated by reference
        to Exhibit 10.3.1 to Spinnaker's Quarterly Report on Form 10-Q for the quarter ended June 30, 2000)
10.4    --Second Amended and Restated Credit Agreement for a $75.0 million credit facility among
        Spinnaker, Credit Suisse First Boston and TD Securities (USA) Inc. dated July 20, 2000
        (incorporated by reference to Exhibit 10.4 to Spinnaker's Quarterly Report on Form 10-Q for the
        quarter ended June 30, 2000)
10.4.1  --First Amendment to Second Amended and Restated Credit Agreement dated as of September 30,
        2000 (incorporated by reference to Exhibit 10.4.1 to Spinnaker's Quarterly Report on Form 10-Q for
        the quarter ended September 30, 2000)
10.4.2  --Second Amendment to Second Amended and Restated Credit Agreement dated as of July 18, 2001
        (incorporated by reference to Exhibit 10.4.2 to Spinnaker's Quarterly Report on Form 10-Q for the
        quarter ended June 30, 2001)
10.5*   --Credit Agreement for a $200 million credit facility dated as of December 28, 2001.
10.6    --Employment Agreement between Spinnaker and Roger L. Jarvis dated December 20, 1996, as
        amended (incorporated by reference to Exhibit 10.6 to Spinnaker's Registration Statement on Form
        S-1 (Commission File No. 333-83093))
10.7    --Employment Agreement between Spinnaker and William D. Hubbard dated February 24, 1997, as
        amended (incorporated by reference to Exhibit 10.8 to Spinnaker's Registration Statement on Form
        S-1 (Commission File No. 333-83093))
10.8    --Employment Agreement between Spinnaker and Kelly M. Barnes dated February 24, 1997, as
        amended (incorporated by reference to Exhibit 10.9 to Spinnaker's Registration Statement on Form
        S-1 (Commission File No. 333-83093))
10.9    --1999 Spinnaker Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to Spinnaker's
        Registration Statement on Form S-1 (Commission File No. 333-83093))
</TABLE>

                                      62

<PAGE>

<TABLE>
<CAPTION>
Exhibit
Number                                             Description
------                                             -----------
<C>     <S>
 10.10  --1999 Spinnaker Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.11 to
        Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
 10.11  --Form of Indemnification Agreement (incorporated by reference to Exhibit 10.12 to Spinnaker's
        Registration Statement on Form S-1 (Commission File No. 333-83093))
 10.12  --Adjunct Stock Option Plan (incorporated by reference to Exhibit 4.3 to Spinnaker's Registration
        Statement on Form S-8 (Commission File No. 333-36592))
 10.13  --Spinnaker Exploration Company 2000 Stock Option Plan (incorporated by reference to Exhibit 10.13
        to Spinnaker's Annual Report on Form 10-K for the year ended December 31, 2000)
 10.14  --Spinnaker Exploration Company 2001 Stock Incentive Plan, as amended (incorporated by
        reference to Exhibit 10.2 to Spinnaker's Registration Statement on Form S-8 (Commission File
        No. 333-61888))
 12.1*  --Calculation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred
        Dividends
 21.1   --Subsidiaries of Spinnaker Exploration Company (incorporated by reference to Exhibit 21.1 to
        Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
 23.1*  --Consent of Arthur Andersen LLP
 23.2*  --Consent of Ryder Scott Company, L.P.
</TABLE>
--------
* Filed herewith.

                                      63

<PAGE>

                                                                    Schedule II

                         SPINNAKER EXPLORATION COMPANY

                VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

             For the Years Ended December 31, 2001, 2000 and 1999
                                (In thousands)

<TABLE>
<CAPTION>
                                     Balance at  Charged to             Balance
                                     Beginning     Costs     Deductions at End
                                      of Year   and Expenses and Other  of Year
                                     ---------- ------------ ---------- -------
 <S>                                 <C>        <C>          <C>        <C>
 Year ended December 31, 2001:
    Allowance for doubtful accounts.    $--        $3,059       $--     $3,059
 Year ended December 31, 2000:
    Allowance for doubtful accounts.     --            --        --         --
 Year ended December 31, 1999:
    Allowance for doubtful accounts.     --            --        --         --
</TABLE>

                                      64