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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, 2000.

[_] 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 000-27473

                         SPINNAKER EXPLORATION COMPANY
            (Exact name of registrant as specified in its charter)

              Delaware                                 76-0560101
   (State or other jurisdiction of        (I.R.S. Employer Identification No.)
   incorporation or organization)

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

<TABLE>
<CAPTION>
                                               Name of each exchange on
             Title of each class                   which registered
             -------------------               ------------------------
<S>                                            <C>
   Common stock, par value $0.01 per share     New York Stock Exchange
</TABLE>

   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 February 28, 2001 was approximately
$751,382,000.

   The number of shares outstanding of the registrant's Common Stock, par
value $0.01 per share, on February 28, 2001 was 26,735,846.

   Parts of the following document are incorporated by reference to Part III
of this Form 10-K Report: Definitive Proxy Statement for the registrant's 2001
Annual Meeting of Stockholders.

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                               TABLE OF CONTENTS

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                                                                          Page
                                                                          ----

                                     PART I

<S>                                                                       <C>
Item 1.    Business......................................................   1
Item 2.    Properties....................................................  20
Item 3.    Legal Proceedings.............................................  23
Item 4.    Submission of Matters to a Vote of Security Holders...........  23

                                    PART II

Item 5.    Market for Registrant's Common Equity and Related Stockholder
           Matters.......................................................  24
Item 6.    Selected Financial Data.......................................  25
Item 7.    Management's Discussion and Analysis of Financial Condition
           and Results of Operations.....................................  26
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk....  31
Item 8.    Financial Statements and Supplementary Data...................  32
Item 9.    Changes in and Disagreements with Accountants on Accounting
           and Financial Disclosure......................................  32

                                    PART III

Item 10.   Directors and Executive Officers of the Registrant............  33
Item 11.   Executive Compensation........................................  33
Item 12.   Security Ownership of Certain Beneficial Owners and
           Management....................................................  33
Item 13.   Certain Relationships and Related Transactions................  33

                                    PART IV

Item 14.   Exhibits, Financial Statement Schedules, and Reports on Form
           8-K...........................................................  33
Signatures...............................................................  34
</TABLE>

                                       i
<PAGE>

   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 18.

             Cautionary Statement About Forward-Looking Statements

   Some of the information in this Annual Report on Form 10-K, including
information incorporated by reference, contains forward-looking statements
within the meaning of Section 27A of the Securities Act of 1933 and Section
21E of the Securities and 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;
  . 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;
  . climactic 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 Form
10-K 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 assure you 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 1.
Business."

                                      ii
<PAGE>

                                    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, 2000, the Company had
license rights to approximately 9,500 blocks of mostly contiguous, recent
vintage 3-D seismic data in the Gulf of Mexico, including approximately 5,750
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, 2000, the Company
had 207 leasehold interests located in Texas state and federal waters covering
approximately 739,000 gross and 337,000 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, 2000, the Company participated in drilling 59 wells in the Gulf of Mexico,
with 37 of these wells being completed as discoveries. As of December 31,
2000, Ryder Scott Company, L.P. estimated the Company's net proved reserves at
approximately 182.7 Bcfe, 90 percent of which was natural gas, representing an
increase of approximately 75 percent over estimated net proved reserves of
104.5 Bcfe at December 31, 1999. Daily production has increased to
approximately 130,000 Mcfe at December 31, 2000 from daily production of
approximately 53,000 Mcfe at December 31, 1999. Within its current inventory
of 207 leasehold interests, the Company has identified approximately 90
exploratory prospects or leads. The Company expects to drill 36 of these
prospects during 2001. Based on 3-D seismic analysis on blocks where it
currently has no leasehold interest, the Company also has identified over 200
additional leads that may result in additional prospects. The capital
expenditure budget for 2001 includes approximately $260 million for
exploration, development, leasehold acquisitions and other capital
expenditures.

   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").
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
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 completed a
public offering of its 5,388,743 shares of Common Stock at $29.25 per share.
Spinnaker received no proceeds from this sale, and PGS' sale of its shares had
no effect on the Data Agreement.

                                       1
<PAGE>

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.

   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

  . Open 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, regional exploration and operating
expertise and joint venture relationships.

   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 believes the 3-D
seismic data received from PGS will continue to serve as the foundation for
its exploration program. The Company will continue to supplement that data
with 3-D seismic data acquisitions from other 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.

   As Spinnaker matures, it is moving towards retaining 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.

                                       2
<PAGE>

   Sustain a balanced, diversified exploration effort. 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, or drilling depths of less than 12,000 feet, and
    deep drilling depth prospects; and

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

   Spinnaker has used joint ventures to help diversify its exploration
activities. The Company's 3-D seismic data's broad coverage of the Gulf of
Mexico 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.

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. However, PGS is not obligated under the Data Agreement to acquire any
further data of any kind. While PGS is currently involved in acquiring 3-D
seismic data in the Gulf of Mexico, it could elect to cease 3-D seismic data
acquisition as a result of a change of control of PGS or changes in PGS'
competitive, financial or technological status. The Company is also entitled
to enhanced data processed by third parties if PGS retains a material royalty
or similar interest in that data.

   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, time-migrated seismic data, and dragged
array and vertical cable data as now 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 4,450 blocks of standard data and 1,300 blocks of
enhanced data under the Data Agreement.

   PGS also acquires an advanced form of 3-D marine seismic data, sometimes
referred to as multi-component data, that requires the simultaneous recording
of information with instruments located on the ocean floor and instruments
dragged behind a marine seismic vessel. The Company is entitled to select for
its use up to 60 blocks of multi-component data that PGS acquires, if any,
prior to March 31, 2002 or is in the process of acquiring as of that date. The
Company must select multi-component data in groups of blocks which are all
contiguous on at least one side and which include at least five blocks.

                                       3
<PAGE>

   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. If PGS enters into a marketing agreement with a
new party, then PGS has agreed to use good faith efforts to obtain the consent
of the new party to the Company's rights under the Data Agreement. If PGS does
not obtain the consent of this new party, however, then the Company may not be
entitled to the future data of PGS that is marketed by that party. A majority
of the data the Company has received is subject to agreements with marketing
vendors.

   On December 20, 2000, PGS completed a public offering of its 5,388,743
shares of Spinnaker Common Stock at $29.25 per share. This transaction had no
effect on the Data Agreement.

 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;

  . make maps and other work products from the data;

  . 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

  . 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. A qualified transferee is a party
with which the Company has entered into a joint venture or other contractual
arrangement with respect to the property relating to the copied data. A
qualified transferee must have substantial business interests other than this
joint venture or contractual relationship, must not have been formed to
acquire the copied data and must have executed a customary license agreement
with PGS or one of its vendors. A transfer of a copy of standard data together
with the related enhanced data covering one block counts as the transfer of
1.5 blocks. The Company may transfer copies only up to an aggregate of 568.6
blocks. The Company must transfer copies of data in groups of blocks that are
contiguous on at least one side and which include at least 20 blocks.

   The Company may 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

                                       4
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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;

  . 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.

 Non-Compete

   PGS has agreed that it will not disclose to any person data covering the
majority of the blocks in any survey in the Gulf of Mexico that is marketed by
PGS as a single survey in exchange for interests in any natural gas or oil
property or natural gas and oil company. This restriction terminates on March
31, 2002.

 Additional Services

   Under the Data Agreement, the Company has access to 3-D seismic data to
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. The Company paid to PGS approximately
$122,000, $318,000 and $449,000 in 1998, 1999 and 2000, respectively, for
seismic-related services. Through December 31, 2000, the Company has paid PGS
a total of approximately $948,000 for these services.

 Limitation of Liability

   The aggregate liability of PGS under the Data Agreement for all claims made
by the Company is limited to $45.0 million. The Company's liability for claims
made against it by PGS under the Data Agreement is not limited.

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-

                                       5
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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, 2000, the
Company had 18 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

   Most of the Company's natural gas and oil production is sold under price
sensitive or market price contracts. Revenues, profitability and future growth
depend substantially on prevailing prices for natural gas and oil. The price
received by the Company for its natural gas and oil production fluctuates
widely. For example, natural gas and oil prices 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.

   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, 1998, sales to Cokinos Energy
Corporation ("Cokinos") were 100 percent of the Company's natural gas and oil
revenues. For the year ended December 31, 1999, sales to Columbia Energy
Services and Cokinos were 68 percent and 32 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.

   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.

   To reduce exposure to fluctuations in the prices of natural gas and oil,
the Company enters into hedging arrangements with respect to a portion of its
expected production. Hedging arrangements expose the Company to risks in some
circumstances, including when production is less than expected, when the other
party to the hedging contract defaults on its contract obligations or when
there is a change in the expected differential between the underlying price in
the hedging agreement and the actual prices received. In addition, these
hedging

                                       6
<PAGE>

arrangements have limited and may continue to limit the benefit the Company
would receive from increases in the prices for natural gas and oil. For
further information concerning Spinnaker's hedging transactions, see "Item 7A.
Quantitative and Qualitative Disclosures about Market Risk."

Competition

   The Company competes with major and independent natural gas and oil
companies for property acquisitions. The Company 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
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 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.

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 which 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 recently issued
Orders No. 637, 637-A and 637-B 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. These orders
also require the FERC Staff to analyze whether the FERC should implement
additional fundamental policy changes, including, among other things, whether
to pursue performance-based ratemaking or other non-cost based ratemaking
techniques and whether the FERC should mandate greater standardization in
terms and

                                       7
<PAGE>

conditions of service across the interstate pipeline grid. 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.

   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 which 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.

                                       8
<PAGE>

 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 Louisiana and occasionally may conduct
operations in the state waters offshore 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 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.

   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. On August 11, 1998, the MMS adopted a rule
implementing these OPA financial responsibility requirements. The Company is
in compliance with this rule.

                                       9
<PAGE>

   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 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, imposes liability, without
regard to fault or the legality of the 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. Initiatives to further regulate the disposal of natural gas and oil
wastes are also pending in some states, and these various initiatives could
have a similar impact on the Company.

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

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

                                      10
<PAGE>

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 of the Gulf of Mexico. 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 risk involved with these
operations.

   Offshore operations are also subject to a variety of operating risks
peculiar 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.

   In accordance with industry practice, the Company maintains insurance
against some, but not all, potential risks and losses. The Company has not
carried business interruption insurance in the past. 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.

Employees

   At December 31, 2000, the Company had 46 full-time employees. The Company
believes that its relationships with the employees are satisfactory. 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.

Risk Factors

   In addition to the other information set forth elsewhere in this Form 10-K,
you should carefully consider the following factors when evaluating Spinnaker.

Because the Company has a limited operating history and has incurred losses
from operations and net losses in recent years, 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, you should consider the limited historical financial
and operating information available on which to base your evaluation of the
Company's performance. 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."

                                      11
<PAGE>

   The Company incurred net losses of $0.3 million in 1996, $2.2 million in
1997, $6.9 million in 1998 and $1.3 million in 1999. The Company's development
of and participation in an increasingly larger number of prospects has
required and will continue to require substantial capital expenditures. The
Company cannot assure you 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.

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.

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

   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. 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. In addition, 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.

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

   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 its 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
and oil prices declined significantly in 1998 and, for an extended period of
time, remained substantially below prices obtained in previous years.

                                      12
<PAGE>

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.

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, 2000,
approximately 68 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, 2000. 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.

   You should not assume 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 Securities and Exchange
Commission ("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.

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 2000, over 63 percent of the Company's production came from four 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, 2000, the
Company's proved reserves were located on 24 different properties in the Gulf
of Mexico, with approximately 56 percent of the proved reserves attributable
to four of these properties. If the actual reserves associated with any one of
these four properties are less than the estimated reserves, the Company's
results of operations and financial condition could be adversely affected.

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

                                      13
<PAGE>

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.

   Recently, higher prices for natural gas and oil have led to greater demand
for drilling rig and other oilfield services. As a result, the Company has
experienced increasing costs and reduced availability of these services.

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 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.

   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.

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.

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

   To reduce exposure to fluctuations in the prices of natural gas and oil,
the Company enters into hedging arrangements with respect to a portion of its
expected production. Hedging arrangements expose the Company to risks in some
circumstances, including situations when production is less than expected, 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
assure you 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 fair market value of the Company's hedges on December 31, 2000 was a
liability of approximately $41.7 million. The estimated intrinsic value of the
open collar arrangements as of December 31, 2000 was equal to an unrealized
loss of approximately $37.7 million in 2001 using NYMEX natural gas prices as
of year-end.

                                      14
<PAGE>

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
peculiar 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.

   The Company has not carried business interruption insurance in the past.
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 in the deep waters of the Gulf of Mexico
involves greater operational and financial risks than exploration in shallower
waters, and expansion into the deep water could result in substantial losses.

   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 and
costly than in shallower waters. 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 water prospects.
Furthermore, the deep waters of the Gulf of Mexico lack the physical and
oilfield service infrastructure present in the shallower waters of the Gulf of
Mexico. 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.

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'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

                                      15
<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 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 may 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.

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.

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
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.

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.

                                      16
<PAGE>

   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 some 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.

Warburg and Spinnaker's management own a significant amount of Common Stock,
giving them influence or control in corporate transactions and other matters,
and the interests of Warburg could differ from those of other stockholders.

   At December 31, 2000, Warburg and Spinnaker's executive officers
beneficially owned approximately 32 percent of the outstanding shares of
Common Stock. As a result, these stockholders are in a position to
significantly influence or control 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. Their control of
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 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 Company's Common Stock could drop due to sales of a
large number of shares of the Common Stock in the market or the perception
that such sales could occur. This could make it more difficult to raise funds
through future offerings 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 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.

                                      17
<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 Form 10-K.

   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.

   Mcf. Thousand cubic feet of natural gas.

                                      18
<PAGE>

   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.

   Net feet of pay. The true vertical thickness of reservoir rock estimated to
both contain hydrocarbons and be capable of contributing to producing rates.

   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.

                                      19
<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, 2000, proved
reserves associated with Spinnaker's discoveries were located on 24 different
blocks, including one property in which the Company has only a royalty
interest, with production established from 19 of these blocks. Spinnaker
operates 22 of its 37 discoveries, and the Company's working interests in
these wells range from 12.5 percent to 100 percent. Four of the blocks account
for approximately 56 percent of the Company's total proved reserves.

   As of December 31, 2000, the Company had license rights to approximately
9,500 blocks of mostly contiguous, recent vintage 3-D seismic data in the Gulf
of Mexico, including approximately 5,750 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, 2000, the Company had 207 leasehold interests
located in Texas state and federal waters covering approximately 739,000 gross
and 337,000 net acres.

Natural Gas and Oil Reserves

   The following table presents estimated net proved natural gas and oil
reserves and the net present value of the reserves at December 31, 2000 based
on a reserve report prepared by Ryder Scott Company, L.P. The present value,
discounted at 10 percent per annum, of estimated future net cash flows 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 from 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, 2000 was determined by
using prices of $9.99 per Mcf of natural gas and $30.41 per barrel of oil,
representing weighted average market prices in effect at December 31, 2000.

<TABLE>
<CAPTION>
                                                      Proved Reserves
                                              --------------------------------
                                              Developed Undeveloped   Total
                                              --------- ----------- ----------
   <S>                                        <C>       <C>         <C>
   Natural gas (MMcf)........................  112,315     51,783      164,098
   Oil and condensate (MBbls)................    1,042      2,056        3,098
   Total proved reserves (MMcfe).............  118,568     64,120      182,688
   Present value of future net cash flows
    (before income taxes) discounted at 10
    percent (in thousands)(1)(2)............. $946,578   $374,094   $1,320,672
   Standardized measure of discounted future
    net cash flows (in thousands)(1)(2)...... $644,447   $254,690   $  899,137
</TABLE>
  --------
  (1) Excludes unrealized losses of $37.7 million for the effects of
      hedging activities using natural gas and oil prices in effect at
      December 31, 2000.
  (2) Natural gas prices declined significantly subsequent to December
      31, 2000. Consequently, the present value of future net cash flows
      (before income taxes) discounted at 10 percent and standardized
      measure of discounted future net cash flows would be reduced if
      current natural gas prices were used in the calculations.
      Utilizing the same methodology with prices of $5.00 per Mcf and
      $25.00 per barrel, the standardized measure of discounted future
      net cash flows would be approximately $455 million at December 31,
      2000.

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

                                      20
<PAGE>

   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, 2000, approximately 68
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, 2000, approximately 35 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.

   You should not assume 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 Commission requirements, 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,
                                                        ---------------------
                                                         1998   1999    2000
                                                        ------ ------  ------
   <S>                                                  <C>    <C>     <C>
   Production:
     Natural gas (MMcf)(1).............................  1,675 11,962  28,845
     Oil and condensate (MBbls)........................     12    180     225
       Total (MMcfe)(1)................................  1,747 13,044  30,194

   Average sales price per unit:
     Natural gas revenues from production (per Mcf).... $ 1.89 $ 2.49  $ 4.62
     Effects of hedging activities (per Mcf)...........     --   0.08   (0.59)
                                                        ------ ------  ------
       Average price (per Mcf)......................... $ 1.89 $ 2.57  $ 4.03

     Oil and condensate revenues from production (per
      Bbl)............................................. $11.61 $20.33  $30.14
     Effects of hedging activities (per Bbl)...........     --  (0.57)  (7.16)
                                                        ------ ------  ------
       Average price (per Bbl)......................... $11.61 $19.76  $22.98

     Total revenues from production (per Mcfe)......... $ 1.89 $ 2.57  $ 4.64
     Effects of hedging activities (per Mcfe)..........     --   0.06   (0.62)
                                                        ------ ------  ------
       Total average price (per Mcfe).................. $ 1.89 $ 2.63  $ 4.02

   Expenses (per Mcfe):
     Lease operating expenses(2)....................... $ 0.27 $ 0.41  $ 0.30
     Depreciation, depletion and amortization--natural
      gas and oil properties........................... $ 1.57 $ 1.59  $ 1.57
</TABLE>
  --------
  (1) During the fourth quarter of 2000, the year-to-date average NYMEX
      natural gas price exceeded the threshold price established by the
      Minerals Management Service to maintain royalty relief on Garden
      Banks 367 (Dulcimer). As a result, Spinnaker recorded a reduction
      of approximately 454 MMcf in natural gas production in 2000.

                                      21
<PAGE>

  (2) Lease operating expenses per Mcfe in 1999 include 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 include approximately $0.03 per Mcfe associated with
      workovers on four wells.

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 exploration expenses, additions to exploratory
wells, including those in progress, and depreciation of support equipment used
in exploration activities. Development costs include costs of completions,
platforms, facilities and pipelines associated with exploratory wells.

<TABLE>
<CAPTION>
                                                          For the Year Ended
                                                             December 31,
                                                       ------------------------
                                                        1998    1999     2000
                                                       ------- ------- --------
   <S>                                                 <C>     <C>     <C>
   Property acquisition costs:
     Unproved......................................... $15,791 $13,911 $ 21,421
     Proved...........................................      --      --       --
   Exploration costs..................................  46,620  45,152  121,451
   Development costs..................................  23,067  23,614   51,144
                                                       ------- ------- --------
       Total costs incurred........................... $85,478 $82,677 $194,016
                                                       ======= ======= ========
</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 Ended
                                                           December 31,
                                                  ------------------------------
                                                    1998      1999       2000
                                                  --------- --------- ----------
                                                  Gross Net Gross Net Gross Net
                                                  ----- --- ----- --- ----- ----
   <S>                                            <C>   <C> <C>   <C> <C>   <C>
   Exploratory Wells:
     Productive..................................    9  2.9    8  4.6   16  10.4
     Nonproductive...............................    6  2.3    4  1.9   12   4.7
                                                   ---  ---  ---  ---  ---  ----
       Total.....................................   15  5.2   12  6.5   28  15.1
                                                   ===  ===  ===  ===  ===  ====
   Development Wells:
     Productive..................................   --   --   --   --   --    --
     Nonproductive...............................   --   --   --   --   --    --
                                                   ---  ---  ---  ---  ---  ----
       Total.....................................   --   --   --   --   --    --
                                                   ===  ===  ===  ===  ===  ====
</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 has been reclassified as a
discovery in 2000.

   Since December 31, 2000, the Company has drilled three gross (1.5 net)
productive exploratory wells and three gross (1.1 net) nonproductive
exploratory wells. As of February 28, 2001, the Company was drilling three
gross (1.0 net) exploratory wells.

                                      22
<PAGE>

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, 2000:

<TABLE>
<CAPTION>
                                                                        Total
                                                                      Productive
                                                                        Wells
                                                                      ----------
                                                                      Gross Net
                                                                      ----- ----
   <S>                                                                <C>   <C>
   Natural gas.......................................................   36  19.3
   Oil...............................................................    1   0.1
                                                                       ---  ----
       Total.........................................................   37  19.4
                                                                       ===  ====
</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, 2000 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..........   40   19    354   157  394  176
   Federal Waters Offshore Texas..............   40   25    260   117  300  142
   Texas State Waters.........................   10    4     35    15   45   19
                                                ---  ---  ----- -----  ---  ---
     Total....................................   90   48    649   289  739  337
                                                ===  ===  ===== =====  ===  ===
</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 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 2000.

                                      23
<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>
   1999:
     Third Quarter (from September 29, 1999)..................... $14.75 $13.00
     Fourth Quarter.............................................. $16.75 $12.56

   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
</TABLE>

   On February 28, 2001, the closing sale price of Spinnaker's Common Stock,
as reported by the New York Stock Exchange, was $38.00 per share. On that
date, there were 38 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 credit facility prohibits it from paying cash dividends on its
Common Stock. Any future dividends may also be restricted by any loan
agreements the Company may enter into from time to time.

                                      24
<PAGE>

Item 6. Selected Financial Data

   The following table sets forth some of the Company's historical
consolidated financial data. You should read the following data 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>
                             Period from
                              Inception
                            (December 20,
                            1996) through      Year Ended December 31,
                            December 31,  -------------------------------------
                                1996       1997      1998      1999      2000
                            ------------- -------  --------  --------  --------
                                 (in thousands, except per share data)
<S>                         <C>           <C>      <C>       <C>       <C>
Statement of Operations
 Data:
Revenues..................     $   --     $   201  $  3,298  $ 34,258  $121,383
Expenses:
 Lease operating
  expenses................         --          72       474     5,411     9,009
 Depreciation, depletion
  and amortization--
  natural gas and oil
  properties..............         --          68     2,738    20,788    47,451
 Depreciation and
  amortization--other.....         10         349       437       213       309
 Write-down of natural
  gas and oil
  properties(1)...........         --          --     2,642        --        --
 General and
  administrative..........        318       1,965     3,809     4,860     7,350
 Stock appreciation
  rights expense(2).......         --          --        --     1,651        --
                               ------     -------  --------  --------  --------
   Total expenses.........        328       2,454    10,100    32,923    64,119
                               ------     -------  --------  --------  --------
Income (loss) from
 operations...............       (328)     (2,253)   (6,802)    1,335    57,264
Other income (expense):
 Interest income..........         --          91       221       528     2,908
 Interest expense.........         --          --      (516)   (3,771)     (765)
 Capitalized interest.....         --          --       237       966        17
                               ------     -------  --------  --------  --------
   Total other income
    (expense).............         --          91       (58)   (2,277)    2,160
                               ------     -------  --------  --------  --------
Income (loss) before
 income taxes.............       (328)     (2,162)   (6,860)     (942)   59,424
 Income tax provision.....         --          --        --        --    20,858
                               ------     -------  --------  --------  --------
Income (loss) before
 cumulative effect of
 change in accounting
 principle................       (328)     (2,162)   (6,860)     (942)   38,566
 Cumulative effect of
  change in accounting
  principle(3)............         --          --        --      (395)       --
                               ------     -------  --------  --------  --------
Net income (loss).........       (328)     (2,162)   (6,860)   (1,337)   38,566
Accrual of dividends on
 preferred stock..........        (16)     (1,326)   (7,094)   (7,911)       --
                               ------     -------  --------  --------  --------
Net income (loss)
 available to common
 stockholders.............     $ (344)    $(3,488) $(13,954) $ (9,248) $ 38,566
                               ======     =======  ========  ========  ========
Basic income (loss) per
 common share(4)(5):
 Income (loss) before
  cumulative effect of
  change in accounting
  principle...............     $(0.09)    $ (0.88) $  (3.44) $  (1.06) $   1.70
 Cumulative effect of
  change in accounting
  principle(3)............         --          --        --     (0.05)       --
                               ------     -------  --------  --------  --------
Net income (loss) per
 common share.............     $(0.09)    $ (0.88) $  (3.44) $  (1.11) $   1.70
                               ======     =======  ========  ========  ========
Diluted income (loss) per
 common share(4)(5):
 Income (loss) before
  cumulative effect of
  change in accounting
  principle...............     $(0.09)    $ (0.88) $  (3.44) $  (1.06) $   1.61
 Cumulative effect of
  change in accounting
  principle(3)............         --          --        --     (0.05)       --
                               ------     -------  --------  --------  --------
Net income (loss) per
 common share.............     $(0.09)    $ (0.88) $  (3.44) $  (1.11) $   1.61
                               ======     =======  ========  ========  ========
Weighted average number of
 common shares
 outstanding(4)(5):
 Basic....................      3,960       3,960     4,059     8,355    22,679
                               ======     =======  ========  ========  ========
 Diluted..................      3,960       3,960     4,059     8,355    24,011
                               ======     =======  ========  ========  ========
Summary Balance Sheet
 Data:
Working capital
 (deficit)................     $2,730     $ 4,252  $(30,641) $ 19,675  $ 74,005
Property and equipment,
 net......................         --      15,452    95,607   157,397   304,381
Total assets..............      5,241      22,358   102,769   189,553   442,704
Short-term debt...........         --          --    19,000        --        --
Accrued preferred
 dividends payable(4).....         16       1,383     8,478        --        --
Total equity..............      3,367      18,879    56,913   177,102   361,259
</TABLE>

                                      25
<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 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.
(3) 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."
(4) 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.
(5) 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

   Since its inception in December 1996, Spinnaker recorded its best year ever
in 2000. The Company made considerable progress in 2000 related to both
production and reserve growth. Performance highlights in 2000 included record:

  . Production of 30.2 Bcfe, up 131 percent.

  . Proved reserves of 182.7 Bcfe, up 75 percent, with reserve and production
    replacements of 104 percent and 359 percent, respectively.

  . Income from operations of $57.3 million, up from $1.3 million in 1999.

  . Net income of $38.6 million, or $1.61 per diluted share, in 2000 compared
    to a net loss in 1999.

  . Cash flow from operating activities, before working capital changes, of
    $107.5 million, up 395 percent.

   Spinnaker's results of operations and financial position were significantly
impacted by natural gas production and prices in 2000. Natural gas revenues
increased $103.4 million in 2000, and 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.
Average natural gas prices increased, contributing $9.9 million of the
increase in natural gas revenues.

   Record 2000 earnings coupled with a $138.9 million equity offering
completed in August 2000 gave the Company $86.3 million in cash, cash
equivalents and short-term investments at December 31, 2000. In addition, the
Company had no debt at December 31, 2000.

                                      26
<PAGE>

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,
                                                   --------------------------
                                                    1998     1999      2000
                                                   -------  -------  --------
   <S>                                             <C>      <C>      <C>
   Production:
     Natural gas (MMcf)...........................   1,675   11,962    28,845
     Oil and condensate (MBbls)...................      12      180       225
       Total (MMcfe)..............................   1,747   13,044    30,194

   Revenues (in thousands):
     Natural gas.................................. $ 3,158  $29,839  $133,264
     Oil and condensate...........................     140    3,668     6,775
     Net hedging income (loss)....................      --      751   (18,656)
                                                   -------  -------  --------
       Total...................................... $ 3,298  $34,258  $121,383

   Average sales price per unit:
     Natural gas revenues from production (per
      Mcf)........................................ $  1.89  $  2.49  $   4.62
     Effects of hedging activities (per Mcf)......      --     0.08     (0.59)
                                                   -------  -------  --------
       Average price (per Mcf).................... $  1.89  $  2.57  $   4.03

     Oil and condensate revenues from production
      (per Bbl)................................... $ 11.61  $ 20.33  $  30.14
     Effects of hedging activities (per Bbl)......      --    (0.57)    (7.16)
                                                   -------  -------  --------
       Average price (per Bbl).................... $ 11.61  $ 19.76  $  22.98

     Total revenues from production (per Mcfe).... $  1.89  $  2.57  $   4.64
     Effects of hedging activities (per Mcfe).....      --     0.06     (0.62)
                                                   -------  -------  --------
       Total average price (per Mcfe)............. $  1.89  $  2.63  $   4.02

   Expenses (per Mcfe):
     Lease operating expenses..................... $  0.27  $  0.41  $   0.30
     Depreciation, depletion and amortization--
      natural gas and oil properties.............. $  1.57  $  1.59  $   1.57

   Income (loss) from operations (in thousands)... $(6,802) $ 1,335  $ 57,264
</TABLE>

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

   Production increased approximately 17.2 billion cubic feet equivalent
("Bcfe") in 2000 compared to 1999. The daily production rate at the end of
December 2000 was approximately 130,000 million cubic feet equivalent ("Mcfe")
as compared to approximately 53,000 Mcfe at the end of December 1999.

   Natural gas and oil revenues, including the effects of hedging activities,
increased $87.1 million and income from operations increased $55.9 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. 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 revenue, excluding the effects of hedging activities. During
the fourth quarter of 2000, the year-to-date average NYMEX natural gas price
exceeded the threshold price established by the Minerals Management Service to
maintain royalty relief on the Company's Dulcimer property. As a result,
Spinnaker recorded a reduction of approximately 454 MMcf in natural gas
production in 2000. Average natural gas prices increased, contributing $9.9
million of the increase in natural gas revenues. Oil and condensate production
volumes increased approximately 45 MBbls, primarily due to 11 wells 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.

                                      27
<PAGE>

   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 include 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 include approximately
$0.03 per Mcfe associated with workovers on four wells.

   Depreciation, depletion and amortization ("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.

 Year Ended December 31, 1999 as Compared to the Year Ended December 31, 1998

   Production increased approximately 11.3 Bcfe in 1999 compared to 1998. The
daily production rate at the end of December 1999 was approximately 53,000
Mcfe as compared to a rate of approximately 8,000 Mcfe at the end of December
1998.

   Natural gas and oil revenues increased $31.0 million and income from
operations increased $8.1 million in 1999 compared to 1998. Natural gas
revenues increased $26.7 million and oil and condensate revenues increased
$3.5 million in 1999 compared to 1998, and net natural gas and oil hedging
income was $751,000 in 1999 as a result of hedging activities beginning during
the fourth quarter of 1999. Natural gas production volumes increased primarily
due to seven wells which commenced production in 1999, contributing to $25.3
million of the increase in natural gas revenues. Average natural gas prices
also increased, contributing to $1.4 million of the increase in natural gas
revenues. Oil and condensate production volumes increased primarily due to six
wells that commenced production in 1999, contributing to $3.4 million of the
increase in oil and condensate revenues.

   The Brazos A-19 well commenced production on October 16, 1999 and reached a
peak production rate of 90 Mcfe per day on November 2, 1999. However, on
November 15, 1999, the operator reported to the Company that during a shutdown
of the well, it detected a pressure buildup in the production casing. The well
was plugged and abandoned, and the operator plans to drill a replacement well
during 2001.

   Lease operating expenses increased $4.9 million in 1999 compared to 1998.
Of the total increase in lease operating expenses, $4.5 million was
attributable to seven wells that commenced production in 1999, including $1.6
million of expense related to workovers at Garden Banks 367 (Dulcimer) and
High Island 235 and well

                                      28
<PAGE>

control activities at Brazos A-19. The Company expensed $225,000 related to
Brazos A-19 well control activities during the fourth quarter of 1999.

   DD&A increased $18.1 million in 1999 compared to 1998, primarily due to a
substantial increase in production during 1999. The DD&A rate in 1999
increased slightly from the DD&A rate in 1998.

   General and administrative expenses increased $1.1 million in 1999 compared
to 1998. The increase in general and administrative expenses was primarily due
to employment-related costs associated with an increase in personnel in late
1998 and 1999. Stock appreciation rights expense in 1999 was approximately
$1.7 million compared to zero in 1998. 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
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.

   Interest income increased $307,000 in 1999 compared to 1998 primarily due
to investment income associated with proceeds from the Company's initial
public offering completed on October 4, 1999. Interest expense, net of
capitalized interest, increased $2.5 million in 1999 compared to 1998 as a
result of additional borrowings under the credit agreement during 1999.

   No income tax benefit was recorded in 1998 and 1999 due to the uncertainty
of future realization as the Company had not established a history of
operating income.

   The Company recognized a net loss of $1.3 million in 1999 compared to a net
loss of $6.9 million in 1998. After preferred dividends of $7.9 million, 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. After
preferred dividends of $7.1 million, the Company recognized a net loss
available to common stockholders of $14.0 million, or a loss of $3.44 per
basic and diluted share, in 1998.

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 1998, 1999
and 2000 were $68.5 million, $85.1 million and $163.7 million, respectively.
The Company has capital expenditure plans for 2001 totaling approximately $260
million. While the Company believes that working capital, cash flows from
operations and borrowings under its credit facility will be sufficient to meet
its capital requirements through the end of 2001, additional 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.

   Cash and cash equivalents increased $43.4 million to $63.9 million at
December 31, 2000 from $20.5 million at December 31, 1999. The Company also
has $22.4 million of highly liquid investments in commercial paper that have
maturity dates greater than three months. The increase in cash and cash
equivalents resulted from $141.6 million provided by financing activities and
$82.0 million provided by operating activities, offset in part by $180.2
million used in investing activities.

   The Company has a $75.0 million credit facility ("Credit Facility") with
two banks that expires in July 2001. Spinnaker and the banks have agreed to a
nominal $30.0 million borrowing base in order to minimize fees associated with
the commitment. This borrowing base is deemed adequate given the Company's
cash, cash equivalents, short-term investments and cash flow from operations.
Management believes that the borrowing base could increase substantially based
on year-end natural gas and oil reserves and current commodity prices.

                                      29
<PAGE>

 Operating Activities

   The Company intends to use cash and cash flows from operations to fund a
portion of its future lease acquisition, exploration and development
activities. Net cash of $82.0 million was provided by operating activities in
2000, primarily as a result of a substantial increase in natural gas
production and prices. Cash flow from operations will depend 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 daily production to
approximately 130,000 Mcfe at the end of December 2000 from approximately
53,000 Mcfe at the end of December 1999. The Company expects higher production
and cash flow during 2001 as recent discoveries commence production. However,
the Company can provide no assurance that production volumes and pricing in
2001 will achieve expectations.

   The Company currently sells most of its natural gas and oil production
under price sensitive or market price contracts. To reduce exposure to
fluctuations in natural gas and oil prices, the Company enters into hedging
arrangements. 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 increase in accounts receivable of $34.8 million was
primarily due to an increase in accrued natural gas and oil revenues of $28.7
million resulting primarily from an increase in production and prices in
December 2000 compared to December 1999 and an increase in joint interest
billings of $8.2 million associated with additional wells operated by the
Company. The increases in accounts payable and accrued liabilities were
primarily due to costs associated with increased drilling and development
activities at the end of 2000 compared to the end of 1999.

 Investing Activities

   Net cash of $180.2 million used in investing activities in 2000 included
net oil and gas property capital expenditures of $161.8 million and purchases
of other property and equipment of $1.9 million. The Company also received net
proceeds of approximately $5.9 million from the sale of natural gas and oil
assets. In addition, the Company purchased short-term investments of $22.4
million.

   The Company drilled 28 exploratory wells in 2000, 16 of which were
successful. Included in the 16 discoveries is one exploratory well drilled in
1999, preliminarily determined to be unsuccessful and 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 has been
reclassified as a discovery in 2000. In 1999, the Company drilled 12
exploratory wells, eight of which were successful.

   The 2001 budget includes development costs that are contingent on the
success of future exploratory drilling. The Company does not anticipate that
budgeted leasehold acquisition activities will include the acquisition of
producing properties. The Company does not anticipate any significant
abandonment or dismantlement costs in 2001. The Company has capital
expenditure plans for 2001 totaling approximately $260 million, primarily for
costs related to exploration and development programs. Actual levels of
capital expenditures may vary significantly due to many factors, including
drilling results, natural gas and oil prices, the availability of capital,
industry conditions, decisions of operators and other prospect owners and the
prices of drilling rig dayrates and other oilfield goods and services.

 Financing Activities

   Net cash of $141.6 million was provided by financing activities in 2000.
The Company received proceeds of $138.9 million from the sale of Common Stock
to the public, proceeds from borrowings of $17.0 million and proceeds of $3.2
million from stock option exercises, offset in part by payments on borrowings
of $17.0 million and public offering costs of $0.5 million.

                                      30
<PAGE>

   On August 16, 2000, the Company completed its 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. With a portion of the proceeds, the Company retired all then
outstanding debt of $17.0 million.

   The Company entered into a credit agreement dated July 20, 2000 that
provides it with a $75.0 million Credit Facility 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. At December 31, 2000, the Company had
no outstanding borrowings under the Credit Facility. The Credit Facility is
secured by substantially all of the Company's assets, including its interests
in natural gas and oil properties. 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 will be 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 various covenants and restrictive provisions
related to the Company's operations. It also requires the Company to satisfy
certain financial covenants, including the maintaining of a ratio of
consolidated current assets to consolidated current liabilities, other than
debt and hedging-related liabilities, as of the end of each fiscal quarter of
not less than 1.00 to 1.00, as well as a ratio of EBITDAX, as defined, to
consolidated interest expense of not less than 5.0 to 1.0 for any period of
four consecutive fiscal quarters.

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 the Company's cash and cash equivalents
and the interest rate paid on borrowings under the Credit Facility. Under its
current policies, the Company does not use interest rate derivative
instruments to manage exposure to interest rate changes.

 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. 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. The Company currently sells most of its natural gas and oil
production under price sensitive or market price contracts. To reduce exposure
to fluctuations in natural gas and oil prices and to achieve more predictable
cash flow, the Company entered into hedging arrangements beginning in the
fourth quarter of 1999. However, these contracts also limit the benefits the
Company would realize if prices increase. These financial arrangements take
the form of costless collars and are placed with major financial institutions
the Company believes represent minimum credit risks.

   Under its current hedging practice, the Company does not hedge more than 50
percent of its production quantities without the prior approval of the risk
management committee. The daily production rates at the end of December 2000
were approximately 123,000 Mcf of natural gas and approximately 1,100 barrels
of oil and condensate. The Company has entered into the following natural gas
collar arrangements. One MMBtu approximates one Mcf of gas.
<TABLE>
<CAPTION>
                                               Average               Average
                                                Daily    Average      NYMEX
                                                Volume NYMEX Floor   Ceiling
                   Time Period                 (MMBtu) Price/MMBtu Price/MMBtu
                   -----------                 ------- ----------- -----------
   <S>                                         <C>     <C>         <C>
   First Quarter 2001......................... 50,000     $2.95       $3.43
   Second Quarter 2001........................ 53,297      2.99        4.64
   Third Quarter 2001......................... 50,000      3.00        4.72
   Fourth Quarter 2001 (through November 30,
    2001)..................................... 50,000      3.00        4.72
</TABLE>

                                      31
<PAGE>

   The Company's open collar arrangements will settle based on the reported
settlement price on the NYMEX for the last trading day each month for natural
gas. In a collar transaction, the counterparty is required to make a payment
to the Company if the settlement price for any settlement period is below the
floor price for the transaction, and the Company is required to make a payment
to the counterparty if the settlement price for any settlement period is above
the ceiling price for the transaction. These transactions are designated as
hedges and accounted for on the accrual basis with realized gains and losses
recognized in revenues when the related production occurs. The Company
recognized net hedging income of $0.8 million in 1999 and net hedging losses
of $18.7 million in 2000.

   In June 1998, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards ("SFAS") No. 133, "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 recognized
currently in earnings unless specific hedge accounting criteria are met.
Accounting for qualifying hedges allows a derivative's gain and losses to
offset related results on the hedged item in the income statement and requires
a company to formally document, designate and assess the effectiveness of
transactions that qualify for hedge accounting. Adoption and implementation of
SFAS No. 133 is required for fiscal years beginning after June 15, 2000. The
Company adopted SFAS No. 133 on January 1, 2001.

   Based upon the Company's assessment of its derivative contracts on January
1, 2001, it will record (i) a net current liability of approximately $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 approximately $27.1 million, representing the intrinsic and time value
components of the derivatives as of January 1, 2001, net of income taxes of
$14.6 million. As the derivatives settle each month, the current liability is
adjusted to reflect the current fair market value, and the monthly settlement
is recorded to revenues with related adjustments to other comprehensive
income. The change in the time value component of the hedges will be recorded
currently in earnings. Accordingly, the Company's quarterly earnings may be
subject to increased volatility under SFAS No. 133.

Item 8. Financial Statements and Supplementary Data

   The consolidated financial statements and supplementary data of the Company
appear on pages 35 through 59 hereof and are incorporated by reference into
this Item 8. Selected quarterly financial data is set forth in Note 13 of
Notes to Consolidated Financial Statements, which is incorporated herein by
reference.

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.

                                      32
<PAGE>

                                   PART III

   The Company's Definitive Proxy Statement for its 2001 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 35.

     (3) Exhibits

       See "Exhibit Index" on page 60.

   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))
 10.5    --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))
 10.6    --Employment Agreement between Spinnaker and James M. Alexander dated
          December 20, 1996, as amended (incorporated by reference to Exhibit
          10.7 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
</TABLE>

   (b) Reports on Form 8-K

     The Company filed a Form 8-K dated December 7, 2000 announcing the
  hiring of Mr. Robert M. Snell as its new Vice President, Chief Financial
  Officer and Secretary. The Company also provided an operational update.

     The Company filed a Form 8-K dated December 14, 2000 announcing that it
  had entered into an underwriting agreement in connection with the sale by
  Seismic Energy Holdings, Inc., a subsidiary of PGS, of up to 5,388,743
  shares of Spinnaker Common Stock.

                                      33
<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 1, 2001                             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.


<TABLE>
<CAPTION>
              Signature                          Title                   Date
              ---------                          -----                   ----

<S>                                    <C>                        <C>
       /s/ ROGER L. JARVIS             Chairman, President, Chief    March 1, 2001
______________________________________  Executive Officer and
           Roger L. Jarvis              Director

       /s/ ROBERT M. SNELL             Vice President, Chief         March 1, 2001
______________________________________  Financial Officer and
           Robert M. Snell              Secretary (Principal
                                        Financial Officer)

      /s/ JEFFREY C. ZARUBA            Treasurer (Principal          March 1, 2001
______________________________________  Accounting Officer)
          Jeffrey C. Zaruba

        /s/ BJARTE BRUHEIM             Director                      March 1, 2001
______________________________________
            Bjarte Bruheim

      /s/ SHELDON R. ERIKSON           Director                      March 1, 2001
______________________________________
          Sheldon R. Erikson

      /s/ JEFFREY A. HARRIS            Director                      March 1, 2001
______________________________________
          Jeffrey A. Harris

      /s/ MICHAEL E. MCMAHON           Director                      March 1, 2001
______________________________________
          Michael E. McMahon

      /s/ REIDAR MICHAELSEN            Director                      March 1, 2001
______________________________________
          Reidar Michaelsen

       /s/ HOWARD H. NEWMAN            Director                      March 1, 2001
______________________________________
           Howard H. Newman
</TABLE>

                                      34
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                  INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
                                                                          Page
                                                                          ----
<S>                                                                       <C>
Report of Independent Public Accountants.................................  36
Consolidated Balance Sheets as of December 31, 1999 and 2000.............  37
Consolidated Statements of Operations for each of the three years in the
 period ended December 31, 2000..........................................  38
Consolidated Statements of Equity for each of the three years in the
 period ended December 31, 2000..........................................  39
Consolidated Statements of Cash Flows for each of the three years in the
 period ended December 31, 2000..........................................  40
Notes to Consolidated Financial Statements...............................  41
</TABLE>

   All 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.

                                      35
<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, 1999 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, 2000. 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, 1999 and 2000, and the
results of their operations and their cash flows for each of the three years
in the period ended December 31, 2000, in conformity with accounting
principles generally accepted in the United States.

                                          ARTHUR ANDERSEN LLP

Houston, Texas
February 15, 2001

                                      36
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                          CONSOLIDATED BALANCE SHEETS

                (In thousands, except share and per share data)

<TABLE>
<CAPTION>
                                                                  As of
                                                              December 31,
                                                            ------------------
                                                              1999      2000
                          ASSETS                            --------  --------
<S>                                                         <C>       <C>
CURRENT ASSETS:
  Cash and cash equivalents................................ $ 20,452  $ 63,910
  Short-term investments...................................       --    22,387
  Accounts receivable......................................   10,795    45,594
  Other....................................................      879     6,402
                                                            --------  --------
    Total current assets...................................   32,126   138,293

PROPERTY AND EQUIPMENT:
  Oil and gas, on the basis of full-cost accounting:
   Proved properties.......................................  141,455   293,002
   Unproved properties and properties under development,
    not being amortized....................................   40,696    83,165
  Other....................................................    3,714     5,642
                                                            --------  --------
                                                             185,865   381,809
  Less--Accumulated depreciation, depletion and
   amortization............................................  (28,468)  (77,428)
                                                            --------  --------
    Total property and equipment...........................  157,397   304,381

OTHER ASSETS...............................................       30        30
                                                            --------  --------
    Total assets........................................... $189,553  $442,704
                                                            ========  ========

<CAPTION>
                  LIABILITIES AND EQUITY
<S>                                                         <C>       <C>
CURRENT LIABILITIES:
  Accounts payable......................................... $  4,509  $ 28,616
  Accrued liabilities......................................    7,942    35,672
                                                            --------  --------
    Total current liabilities..............................   12,451    64,288
DEFERRED INCOME TAXES......................................       --    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, 1999 and 2000, respectively.........................       --        --
  Common stock, $0.01 par value; 50,000,000 shares
   authorized; 20,426,192 shares issued and 20,404,336
   shares outstanding at December 31, 1999 and 26,494,593
   shares issued and 26,476,817 shares outstanding at
   December 31, 2000.......................................      204       265
  Additional paid-in capital...............................  203,987   349,506
  Retained earnings (accumulated deficit)..................  (27,034)   11,532
  Less: Treasury stock, at cost, 21,856 and 17,776 shares
   at December 31, 1999 and 2000, respectively.............      (55)      (44)
                                                            --------  --------
    Total equity...........................................  177,102   361,259
                                                            --------  --------
    Total liabilities and equity........................... $189,553  $442,704
                                                            ========  ========
</TABLE>

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

                                       37
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                     CONSOLIDATED STATEMENTS OF OPERATIONS

                     (In thousands, except per share data)

<TABLE>
<CAPTION>
                                                      For the Year Ended
                                                         December 31,
                                                   ---------------------------
                                                     1998     1999      2000
                                                   --------  -------  --------
<S>                                                <C>       <C>      <C>
REVENUES.......................................... $  3,298  $34,258  $121,383
EXPENSES:
  Lease operating expenses........................      474    5,411     9,009
  Depreciation, depletion and amortization--
   natural gas and oil properties.................    2,738   20,788    47,451
  Write-down of natural gas and oil properties....    2,642       --        --
  Depreciation and amortization--other............      437      213       309
  General and administrative......................    3,809    4,860     7,350
  Stock appreciation rights expense...............       --    1,651        --
                                                   --------  -------  --------
    Total expenses................................   10,100   32,923    64,119
                                                   --------  -------  --------
INCOME (LOSS) FROM OPERATIONS.....................   (6,802)   1,335    57,264
OTHER INCOME (EXPENSE):
  Interest income.................................      221      528     2,908
  Interest expense................................     (516)  (3,771)     (765)
  Capitalized interest............................      237      966        17
                                                   --------  -------  --------
    Total other income (expense)..................      (58)  (2,277)    2,160
                                                   --------  -------  --------
INCOME (LOSS) BEFORE INCOME TAXES.................   (6,860)    (942)   59,424
  Income tax provision............................       --       --    20,858
                                                   --------  -------  --------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE
 IN ACCOUNTING PRINCIPLE..........................   (6,860)    (942)   38,566
  Cumulative effect of change in accounting
   principle (Note 2).............................       --     (395)       --
                                                   --------  -------  --------
NET INCOME (LOSS).................................   (6,860)  (1,337)   38,566
ACCRUAL OF DIVIDENDS ON PREFERRED STOCK...........   (7,094)  (7,911)       --
                                                   --------  -------  --------
NET INCOME (LOSS) AVAILABLE TO COMMON
 STOCKHOLDERS..................................... $(13,954) $(9,248) $ 38,566
                                                   ========  =======  ========
BASIC INCOME (LOSS) PER COMMON SHARE:
  Income (loss) before cumulative effect of change
   in accounting principle........................ $  (3.44) $ (1.06) $   1.70
  Cumulative effect of change in accounting
   principle......................................       --    (0.05)       --
                                                   --------  -------  --------
NET INCOME (LOSS) PER COMMON SHARE................ $  (3.44) $ (1.11) $   1.70
                                                   ========  =======  ========
DILUTED INCOME (LOSS) PER COMMON SHARE:
  Income (loss) before cumulative effect of change
   in accounting principle........................ $  (3.44) $ (1.06) $   1.61
  Cumulative effect of change in accounting
   principle......................................       --    (0.05)       --
                                                   --------  -------  --------
NET INCOME (LOSS) PER COMMON SHARE................ $  (3.44) $ (1.11) $   1.61
                                                   ========  =======  ========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
 OUTSTANDING:
  Basic...........................................    4,059    8,355    22,679
                                                   ========  =======  ========
  Diluted.........................................    4,059    8,355    24,011
                                                   ========  =======  ========
</TABLE>

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

                                       38
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                       CONSOLIDATED STATEMENTS OF EQUITY

             (In thousands, except shares and share dividend data)

<TABLE>
<CAPTION>
                                                                                                  Retained
                          Shares             Par Value       Preferred   Additional Unitholder/   Earnings
                   ---------------------- ----------------     Unit       Paid-In   Stockholder (Accumulated Treasury
                   Preferred     Common   Preferred Common Subscriptions  Capital   Receivables   Deficit)    Stock    Total
                   ----------  ---------- --------- ------ ------------- ---------- ----------- ------------ -------- --------
<S>                <C>         <C>        <C>       <C>    <C>           <C>        <C>         <C>          <C>      <C>
Balance, December
 31, 1997........     958,921   3,960,000   $ --     $ --    $ 54,480     $     29   $(31,798)    $ (3,832)    $ --   $ 18,879
 Conversion to
  Spinnaker
  Exploration
  Company........          --      97,200     10       20     (54,480)      54,450         --           --       --         --
                   ----------  ----------   ----     ----    --------     --------   --------     --------     ----   --------
                      958,921   4,057,200     10       20          --       54,479    (31,798)      (3,832)      --     18,879
 Net loss........          --          --     --       --          --           --         --       (6,860)      --     (6,860)
 Common stock
  issuance.......          --      25,000     --       --          --          188         --           --       --        188
 Preferred stock
  subscriptions..          --          --     --       --          --       19,982    (19,982)          --       --         --
 Preferred stock
  dividends
  ($3.00 per
  share).........          --          --     --       --          --           --         --       (7,094)      --     (7,094)
 Preferred stock
  payments.......   2,071,999          --     20       --          --           --     51,780           --       --     51,800
                   ----------  ----------   ----     ----    --------     --------   --------     --------     ----   --------
Balance, December
 31, 1998........   3,030,920   4,082,200     30       20          --       74,649         --      (17,786)      --     56,913
 Net loss........          --          --     --       --          --           --         --       (1,337)      --     (1,337)
 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
 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
                   ==========  ==========   ====     ====    ========     ========   ========     ========     ====   ========
</TABLE>

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

                                       39
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                     CONSOLIDATED STATEMENTS OF CASH FLOWS

                                 (In thousands)

<TABLE>
<CAPTION>
                                                     For the Year Ended
                                                        December 31,
                                                 -----------------------------
                                                   1998      1999      2000
                                                 --------  --------  ---------
<S>                                              <C>       <C>       <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
 Net income (loss).............................. $ (6,860) $ (1,337) $  38,566
 Adjustments to reconcile net income (loss) to
  net cash provided by (used in) operating
  activities:
  Depreciation, depletion and amortization......    3,175    21,001     47,760
  Write-down of natural gas and oil properties..    2,642        --         --
  Deferred income tax expense...................       --        --     20,833
  Other.........................................       --        --        306
  Stock appreciation rights expense.............       --     1,651         --
  Cumulative effect of change in accounting
   principle....................................       --       395         --
 Change in components of working capital:
  Accounts receivable...........................     (218)   (6,974)   (34,799)
  Accounts payable and accrued liabilities......     (896)     (636)    14,861
  Other current assets and other................     (619)      805     (5,523)
                                                 --------  --------  ---------
    Net cash provided by (used in) operating
     activities.................................   (2,776)   14,905     82,004

CASH FLOWS FROM INVESTING ACTIVITIES:
 Oil and gas properties.........................  (84,823)  (78,894)  (198,787)
 Change in property related payables............   17,178    (5,291)    36,976
 Proceeds from sale of natural gas and oil
  assets........................................       --        --      5,971
 Purchases of other property and equipment......     (858)     (916)    (1,928)
 Purchases of short-term investments............       --        --    (22,387)
                                                 --------  --------  ---------
    Net cash used in investing activities.......  (68,503)  (85,101)  (180,155)

CASH FLOWS FROM FINANCING ACTIVITIES:
 Proceeds from borrowings.......................   19,000    53,000     17,000
 Payments on borrowings.........................       --   (72,000)   (17,000)
 Proceeds from issuance of common stock.........       --   108,720    138,936
 Common stock issuance costs....................       --    (1,109)      (538)
 Proceeds from exercise of stock options........       --        29      3,211
 Preferred stock dividends......................       --       (78)        --
 Acquisition of treasury stock..................       --       (55)        --
 Proceeds from issuance of preferred stock,
  net...........................................   51,738        --         --
                                                 --------  --------  ---------
    Net cash provided by financing activities...   70,738    88,507    141,609
                                                 --------  --------  ---------
NET INCREASE (DECREASE) IN CASH AND CASH
 EQUIVALENTS....................................     (541)   18,311     43,458
CASH AND CASH EQUIVALENTS, beginning of year....    2,682     2,141     20,452
                                                 --------  --------  ---------
CASH AND CASH EQUIVALENTS, end of year.......... $  2,141  $ 20,452  $  63,910
                                                 ========  ========  =========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
 Cash paid for interest, net of amounts
  capitalized................................... $     84  $  2,591  $     380
 Cash paid for income taxes.....................       --        --         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.

                                       40
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

                  NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization, Nature of Operations and Formation:

 Organization and Nature of Operations

   The accompanying consolidated financial statements include the activities
and accounts of Spinnaker Exploration Company ("Spinnaker" or the "Company")
and all wholly-owned subsidiaries of the Company. All significant intercompany
transactions and balances are eliminated in consolidation. The Company is
engaged in the exploration, development and production of natural gas and oil
properties in the U.S. Gulf of Mexico.

 Initial Public Offering

   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.
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 Preferred Stock into shares of Common Stock, and certain
shareholders reinvested preferred dividends payable of $16.3 million into
shares of Common Stock.

 Formation

   Spinnaker Exploration Company, L.L.C. ("Spinnaker"), a Delaware limited
liability company, was formed on December 20, 1996. Spinnaker was formed by WP
Spinnaker Holdings, Inc. ("Holdings"), a subsidiary of Warburg, Pincus
Ventures L.P. ("Warburg"), Seismic Energy Holdings, Inc. ("SEHI"), a
subsidiary of Petroleum Geo-Services ASA ("PGS"), a Norwegian joint-stock
company, and certain members of management of Spinnaker (collectively known as
the "Investors").

   As a part of the formation of Spinnaker, Warburg purchased 1,000,000 common
units ("Common Units") at $0.0125 per Common Unit and agreed to subscriptions
on preferred units ("Preferred Units") of up to $50.0 million at a price of
$25.00 per unit, of which 151,476 Preferred Units were purchased at formation.
PGS purchased 1,000,000 Common Units at $0.0125 per Common Unit and subscribed
for up to $15.0 million of Preferred Units also at a price of $25.00 per unit,
of which 45,093 Preferred Units were purchased at formation. PGS was only
obligated to purchase an aggregate of $5.0 million Preferred Units unless
Spinnaker sold additional Preferred Units to other investors. As a result,
preferred stock subscriptions were recorded at approximately $54.5 million at
inception. Management purchased 160,000 Common Units at $0.0125 per Common
Unit and agreed to subscriptions on Preferred Units of up to $798,000 at
$25.00 per unit, of which 2,352 Preferred Units were purchased at formation.
Property contributed by management related to this formation included cash of
$9,726 and property resulting from expenditures made by Mr. Jarvis in
anticipation of the formation of the Company. The total value, for purposes of
the agreement, of the initial management contributions was $60,790. The
198,921 Preferred Units purchased at inception resulted in consideration
received of approximately $5.0 million and net of $1.3 million in offering
costs, resulted in net proceeds of $3.7 million. Additionally, PGS entered
into a seismic data agreement ("Data Agreement") with Spinnaker dated
December 20, 1996, whereby it agreed to transfer to Spinnaker certain rights
to 3-D seismic data in consideration of Common Units. Spinnaker accounted for
the contribution of the Data Agreement at PGS' cost, which was immaterial. See
Note 4.

 Change in Reporting Entity

   On January 6, 1998, Spinnaker Exploration Corp. ("Spinco"), a Delaware
corporation, was formed by Spinnaker Exploration Company, L.L.C., with Mr.
Jarvis acting as sole director until a board was elected. Contemporaneous with
the formation of Spinco, the Investors, other than Warburg, contributed their
respective

                                      41
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

Preferred Units and Common Units to Spinco and in exchange for such
contributions, Spinco issued a like number of its shares of common stock, par
value $0.01 per share ("Common Stock"), and Series A Convertible Preferred
Stock ("Preferred Stock"), par value $0.01 per share. Warburg contributed all
of its issued and outstanding common shares of Holdings to Spinco in exchange
for shares of Common Stock and Preferred Stock of Spinco. As of January 6,
1998, the equity owners of Spinnaker were Spinco and Spinco's wholly owned
subsidiary, Holdings. On April 27, 1998, Spinco filed an amendment to its
certificate of incorporation with the State of Delaware to change its name
from Spinco to Spinnaker Exploration Company. As a part of the change in
entity, SEHI was issued an additional 97,200 shares of Common Stock.

2. Summary of Significant Accounting Policies:

 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, Spinnaker Exploration Company, L.L.C. and WP
Spinnaker Holdings, Inc. 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 includes unamortized debt financing costs of $242,000
and $114,000 at December 31, 1999 and 2000, respectively. These costs are
amortized to interest expense over the term of the related credit facility.
Amortization of these and other debt financing costs included in interest
expense was $116,000, $576,000 and $354,000 for the years ended December 31,
1998, 1999 and 2000, respectively. See Note 3.

                                      42
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 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 $2.5
million, $2.5 million and $3.8 million of internal costs in 1998, 1999 and
2000, respectively. 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. 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. The amortization base includes estimated
future development costs and dismantlement, restoration and abandonment costs,
net of estimated salvage values.

   The Company limits the capitalized costs of natural gas and oil properties,
net of accumulated DD&A and related deferred taxes, to the estimated future
net cash flows from proved natural gas and oil reserves 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. At December 31, 1998, the Company recognized a non-cash write-
down of natural gas and oil properties in the amount of $2.6 million pursuant
to the ceiling limitation required by the full cost method of accounting for
natural gas and oil properties, using prices as of April 9, 1999. The write-
down was primarily the result of the precipitous decline in natural gas prices
experienced in 1998. Using December 31, 1998 prices, the Company would have
recognized a non-cash write-down of natural gas and oil properties in the
amount of $13.0 million. The write-down was reduced due to the increase in
natural gas and oil prices from December 31, 1998 through April 9, 1999.

   The costs of certain unevaluated leasehold acreage and wells drilled, but
currently under evaluation, are not being amortized. Costs not being amortized
are assessed quarterly for possible impairments or reduction in value. If a
reduction in value has occurred, costs being amortized are increased. Of the
$83.2 million of net unproved property costs at December 31, 2000 excluded
from the amortizable base, $5.7 million was incurred prior to 1998, and $22.7
million, $12.3 million and $42.5 million were incurred in 1998, 1999 and 2000,
respectively. 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

   As of December 31, 1998, Other assets included capitalized organization
costs incurred by the Company in its initial formation. The Company was
amortizing the start-up costs over a period of five years. Amortization
expense for the year ended December 31, 1998 was $132,000.

                                      43
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   On April 3, 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 is 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
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-
deliveries are included in accounts receivable and over-deliveries are
included in accrued liabilities. The Company had no significant imbalances at
December 31, 1999 and 2000.

 Income Taxes

   Prior to January 6, 1998, the Company was not a tax-paying entity for
federal income tax purposes. The profit or loss of the Company for federal
income tax reporting purposes was included in the income tax returns of the
Investors.

   Effective January 6, 1998, with the formation of Spinco, the Company became
subject to federal income taxes and began to apply the provisions of Statement
of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income
Taxes." See Note 10. Under SFAS No. 109, 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. The total provision for income taxes is the
sum of taxes payable for the year and the change during the year in deferred
tax assets and liabilities.

 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 related footnotes have been restated as appropriate to reflect
the effect of the Stock Split for all periods presented.

 Financial Instruments and Price Risk Management Activities

   At December 31, 2000, the Company's financial instruments consist of cash
and cash equivalents, short-term investments, receivables and payables. The
carrying amounts of cash and cash equivalents, short-term investments,
receivables and payables approximate fair value because of the short-term
nature of these items.

   The Company's commodity hedging policy permits the use of certain financial
instruments and commodity contracts to mitigate its exposure to natural gas
and oil price volatility. These financial instruments, which are placed with
major financial institutions the Company believes are minimum credit risks,
take the form of costless collars. These transactions are designated as hedges
and accounted for on the accrual basis with realized gains and losses
recognized in revenues when the related production occurs. The Company
recognized net hedging income of $0.8 million in 1999 and net hedging losses
of $18.7 million in 2000. The Company's costless collars mature monthly
through November 2001. See "New Accounting Policies."

                                      44
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 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 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.

 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.

 Risk Factors

   The Company's revenue, profitability, cash flow and future rate of growth
is 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. Other factors that could affect the
revenue, profitability, cash flow and future growth of the Company include its
limited operating history and the incurrence of losses from 1996 through 1999,
the inherent uncertainties in reserve estimates, the concentration of
production and reserves in a small number of offshore properties, and the
ability to finance growth and replace reserves. The Company is also dependent
upon the continued success of its exploratory drilling program.

 New Accounting Policies

   In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"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 recognized currently in earnings unless specific
hedge accounting criteria are met. Accounting for qualifying hedges allows a
derivative's gain and losses to offset related results on the hedged item in
the income statement and requires a company to formally document, designate
and assess the effectiveness of transactions that qualify for hedge
accounting. SFAS No. 133 was originally effective for fiscal years beginning
after June 15, 1999; however, SFAS No. 137, "Accounting for Derivative
Instruments and Hedging Activities--Deferral of the Effective Date of FASB
Statement No. 133-- An Amendment of FASB Statement No. 133" extended
implementation to fiscal years beginning after June 15, 2000. Early adoption
was permitted. The Company adopted SFAS No. 133 on January 1, 2001.

   The Company currently utilizes collar arrangements to reduce its exposure
to fluctuations in natural gas and oil prices and to achieve a more
predictable cash flow. Based upon the Company's assessment of its derivative
contracts on January 1, 2001, it will record (i) a net current liability of
approximately $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 approximately $27.1 million, representing the
intrinsic and time value components of the derivatives as of January 1, 2001,
net of income taxes of $14.6 million. As the derivatives settle each month,
the current liability is adjusted to reflect the current fair market value,
and the monthly settlement is recorded to revenues with related adjustments to
other comprehensive income. The change in the time value component of

                                      45
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

the hedges will be recorded currently in earnings. Accordingly, the Company's
quarterly earnings may be subject to increased volatility under SFAS No. 133.

3. Debt:

   In September 1998, the Company entered into an $85.0 million credit
agreement ("Credit Agreement") with certain financial institutions. Proceeds
from borrowings under the Credit Agreement were used to fund exploration and
development activities. The Credit Agreement was secured by the Company's
interests in natural gas and oil properties and by certain guarantees of PGS
and Warburg. The stockholder guarantees for the Credit Agreement were $75.0
million, split evenly between PGS and Warburg.

   The Credit Agreement was comprised of three tranches, each with a specified
interest rate. The weighted average interest rate for each of the PGS and the
Warburg tranches was 5.67 percent in 1998 and 5.54 percent in 1999. The
weighted average interest rate for the borrowing base tranche was 8.23 percent
in 1998 and 7.45 percent in 1999. The overall weighted average interest rate
for borrowings outstanding under the Credit Agreement was 6.54 percent in 1998
and 5.71 percent in 1999. 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 $212,000 and $2.4
million for the years ended December 31, 1998 and 1999, respectively,
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, from time to time, Common Stock. Any related
stock issuances were accounted for at the fair value of the guarantees
provided. Such amounts were $188,000 and $840,000 for the years ended December
31, 1998 and 1999, respectively, and have been included in interest expense in
the accompanying consolidated statements of operations.

   The Credit Agreement was scheduled to mature on December 31, 1999; however,
the Company amended and restated the original Credit Agreement on October 29,
1999. The Company, Bank of Montreal and Credit Suisse First Boston entered
into the $25.0 million Amended and Restated 364-Day Credit Agreement ("Amended
and Restated Credit Agreement"). The weighted average interest rate for
borrowings outstanding under the Amended and Restated Credit Agreement was
8.72 percent in 2000. The Amended and Restated Credit Agreement was amended on
July 20, 2000.

   The Company is currently a party to the Second Amended and Restated Credit
Agreement that provides it with a $75.0 million credit facility ("Credit
Facility") 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. At December 31, 2000, the Company had no outstanding borrowings under
the Credit Facility. The Credit Facility is secured by substantially all of
the Company's assets, including its interests in natural gas and oil
properties. 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 will be 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 weighted average interest rate for borrowings outstanding under the
Credit Facility was 8.51 percent in 2000.

   The Credit Facility contains various covenants and restrictive provisions.
It also requires the Company to maintain certain financial covenants,
including the ratio of consolidated current assets as of the end of each
fiscal quarter to consolidated current liabilities, other than debt and
hedging-related liabilities, under the Credit Facility as of the end of such
fiscal quarter so that it is not less than 1.00 to 1.00 and the ratio of
EBITDAX, as defined, to consolidated interest expense so that it is not less
than 5.0 to 1.0 for any period of four consecutive fiscal quarters.


                                      46
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

4. Seismic Data Agreement:

   As part of the Company's formation, SEHI agreed to transfer to Spinnaker
certain rights to 3-D seismic data in exchange for issuing 1,800,000 Common
Units to SEHI pursuant to the Data Agreement dated December 20, 1996. See
Notes 1 and 5. The Company also had the ability under the Data Agreement to
acquire additional rights to 3-D seismic data in exchange for issuing
additional Common Units to SEHI. SEHI's obligation to the Company in
connection with the Data Agreement is guaranteed by its parent, PGS. In
addition, 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 $122,000, $318,000 and $449,000 in 1998, 1999 and 2000,
respectively, for seismic-related services. Through December 31, 2000, the
Company has paid PGS a total of approximately $948,000 for seismic-related
services.

   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 has been accounted for at
PGS' cost of $2.9 million, pursuant to Staff Accounting Bulletin No. 48.

5. Equity:

 Convertible Preferred Units/Stock

   On December 20, 1996, Spinnaker authorized 3,030,720 units of Series A
Convertible Preferred Units, and on the same day sold 198,921 Preferred Units
to the Investors for consideration of approximately $5.0 million, composed of
cash and certain previously incurred organization costs. Offering costs of
$1.3 million, consisting principally of investment banking fees, were incurred
in connection with this transaction. In 1997, Spinnaker sold an additional
760,000 Preferred Units to the Investors for consideration of approximately
$19.0 million.

   The Investors initially committed, subject to certain conditions, to
purchase a total of up to approximately $65.8 million of Preferred Units. In
1998, the total capital commitment for the Investors was increased to $75.8
million, allocated as follows: $15.0 million to SEHI, $60.0 million to
Holdings and $800,000 to management.

   On January 6, 1998, concurrent with the formation of Spinco, Spinco
authorized 3,030,920 shares of Preferred Stock with a par value of $0.01. All
Preferred Units of Spinnaker, except those issued to Holdings, were
contributed to Spinco in exchange for a like number of shares in Spinco's
Preferred Stock. The Preferred Stock had a liquidation preference of $25.00
per share plus accrued dividends. Each share of Preferred Stock was
convertible into two shares of Common Stock subject to certain anti-dilution
provisions, upon one of the following: (a) at the holder's option, (b) by a
vote of a majority of the board of directors and holders of the Preferred
Stock representing at least 65 percent of the voting power of the Preferred
Stock, or (c) a qualified public offering. In the event of a qualified public
offering, the Company, at its option, could have automatically converted the
Preferred Stock into Common Stock if the Common Stock was sold for not less
than 150 percent of the conversion price of $12.50, subject to adjustments in
the event of stock dividends, stock splits, and issuance of shares below the
$12.50 conversion price, etc.

   Dividends accrued at the rate of $3.00 per share and unpaid dividends
compounded quarterly at a rate of 12 percent per annum until December 31,
2006, at which time, the rate would have decreased to $2.00 per share per
annum thereafter if all dividends for the then prior periods had been declared
and paid in full. Otherwise, the dividend rate would have increased to $5.00
per share per annum and the rate at which the dividends compounded quarterly
would have increased to an annual rate of 20 percent after December 31, 2006.
At December 31, 1998, accrued dividends on the Preferred Stock were $8.5
million. Dividends were payable in

                                      47
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

cash on the earliest to occur of a qualified initial public offering, a merger
or consolidation involving the Company, a sale of all or substantially all of
the assets of the Company or a change of control of the Company. The Preferred
Stock was entitled to vote together with the Common Stock on an as converted
basis. The Preferred Stock could have been redeemed by the Company on or after
January 21, 2018 at a redemption price of $25.00 per share plus any accrued
and unpaid dividends through the redemption date.

   The Preferred Stock had substantially the same economic terms as the
Preferred Units had except that the dividend rate on the Preferred Units
increased after December 31, 2006 to $5.00 per share and the Preferred Units
could be redeemed by the Company after December 31, 2006.

   During 1998, Preferred Stock subscriptions increased by approximately $20.0
million as a result of Warburg increasing its Preferred Unit subscriptions by
$10.0 million and PGS agreeing that it would be obligated to purchase an
aggregate of $15.0 million of Preferred Stock rather than $5.0 million.

   In 1998, Spinnaker sold an additional 2,071,999 shares of Preferred Stock
to the Investors for consideration of approximately $51.8 million, of which
$11.0 million was sold during the first quarter. At December 31, 1996 and
1997, receivables on the conditional commitments for the sale of Preferred
Units/Stock to the Investors were approximately $50.8 million and $31.8
million, respectively, and are presented as a reduction in equity. At December
31, 1998, all commitments from Investors for Preferred Stock had been
fulfilled.

   In connection with the initial public offering, the Company converted all
outstanding Preferred Stock into shares of Common Stock, and certain
shareholders reinvested preferred dividends payable of $16.3 million into
shares of Common Stock.

 Common Units/Stock

   In December 1996, Spinnaker authorized 14,701,440 Common Units, of which
3,960,000 were sold to the Investors on December 21, 1996, for consideration
of $25,000 of cash, certain organization costs and the Data Agreement. See
Note 4. The Common Units were subject to certain transfer restrictions, and
holders of Common Units were bound by certain tax-sharing arrangements which
had the effect of providing economic benefits to Holdings greater than would
be expected in the absence of such agreement.

   The Company issued a total of 25,000 and 76,096 shares of Common Stock to
PGS and Warburg in 1998 and 1999, respectively, under terms of the Credit
Agreement related to the guarantor commitments of both parties. See Note 3.

   On January 6, 1998, concurrent with the formation of Spinco, Spinco
authorized 14,399,040 shares of Common Stock with a par value of $0.01 per
share. All issued Common Units of Spinnaker, except for those issued to
Holdings, were contributed to Spinco in exchange for a like number of shares
in Spinco's Common Stock. In September 1998, the Company amended its
certificate of incorporation and increased the number of authorized shares of
Common Stock to 22,000,000.

   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.

                                      48
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   On December 20, 2000, PGS completed a public offering of its 5,388,743
shares of Common Stock at $29.25 per share. Spinnaker received no proceeds
from this sale.

 Common Stock Split

   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.

6. Stock Plans:

 Stock Options

   At December 31, 2000, officers, directors and employees had been granted
options to purchase the Company's Common Stock under stock plans adopted in
1998, 1999 and 2000 ("Stock Plans"). 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 Company adopted 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. The purchase
price of an aggregate of 1,520,608 shares of Common Stock issuable under
options authorized under the 1998 Plan is $5.00 per share, and the purchase
price of an aggregate of 1,152,634 shares of Common Stock issuable under
options authorized under the 1998 Plan is $15.63 per share. In September 1999,
the board of directors and the stockholders of the Company adopted 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 board of directors and
stockholders adopted 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"). The number of shares of Common Stock that may
be issued under the 2000 Plan may not exceed 500,000 shares.

                                      49
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 Stock Option Activity

   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 $0, $150,000 and $158,000
in 1998, 1999 and 2000, 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 this plan 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 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,
                                                   ---------------------------
                                                     1998      1999     2000
                                                   --------  --------  -------
   <S>                                             <C>       <C>       <C>
   Pro forma net income (loss) available to
    common stockholders..........................  $(14,172) $(10,950) $35,543
                                                   ========  ========  =======
   Pro forma net income (loss) per basic common
    share........................................  $  (3.49) $  (1.31) $  1.57
                                                   ========  ========  =======
   Pro forma net income (loss) per diluted common
    share........................................  $  (3.49) $  (1.31) $  1.48
                                                   ========  ========  =======
</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 1998, 1999 and 2000 as follows:

<TABLE>
<CAPTION>
                                              For the Year Ended December 31,
                                            -----------------------------------
                                               1998        1999        2000
                                            ----------- ----------- -----------
   <S>                                      <C>         <C>         <C>
   Risk-free interest rate................. 4.96%-5.96% 4.67%-6.08% 5.14%-6.82%
   Volatility factor.......................     0%         54.8%       42.5%
   Dividend yield..........................     0%          0%          0%
   Expected life of the options (years)....     10          4.5          4
</TABLE>

   Presented below is a summary of stock option activity.

<TABLE>
<CAPTION>
                                       1998                      1999                       2000
                             ------------------------- -------------------------- --------------------------
                               Shares      Weighted      Shares       Weighted      Shares       Weighted
                               Under       Average       Under        Average       Under        Average
                               Option   Exercise Price   Option    Exercise Price   Option    Exercise Price
                             ---------- -------------- ----------  -------------- ----------  --------------
   <S>                       <C>        <C>            <C>         <C>            <C>         <C>
   Outstanding, beginning
    of year................   2,198,000     $9.10       2,526,880      $ 9.11      3,382,974      $10.56
     Granted...............     328,880      9.13         866,574       14.74        802,470       23.45
     Exercised.............          --        --          (5,872)       4.97       (466,558)       6.88
     Forfeited.............          --        --          (4,608)       9.29             --          --
                             ----------                ----------                 ----------
   Outstanding, end of
    year...................   2,526,880      9.11       3,382,974       10.56      3,718,886       13.80
                             ==========                ==========                 ==========
   Exercisable, end of
    year...................   1,222,736      9.11       1,919,019        9.62      2,364,270       11.38
                             ==========                ==========                 ==========
   Available for grant, end
    of year................     172,250                   605,676                    303,206
                             ==========                ==========                 ==========
   Weighted average fair
    value of options
    granted during the
    year...................  $     0.83                $     6.78                 $    15.17
                             ==========                ==========                 ==========
</TABLE>

   Options to purchase 640 shares of Common Stock forfeited during 1999 were
canceled and are not available for future grants.

                                      50
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   At December 31, 2000, 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                   Price                  Price     Contractual
    Prices Per     Number of     Per      Number of     Per         Life
       Share        Options     Share      Options     Share       (Years)
    ----------     ---------   --------   ---------   --------   -----------
   <S>             <C>         <C>        <C>         <C>        <C>
    $2.50-$5.00    1,151,855    $ 4.96    1,033,303    $ 4.98        6.2
   $14.50-$16.13   2,140,861     15.36    1,245,733     15.41        7.7
   $22.25-$32.78     324,970     27.27       64,994     27.37        9.9
   $37.94-$40.31     101,200     38.20       20,240     38.20        9.7
</TABLE>

   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 share is computed based on the
following information (in thousands, except per share amounts):

<TABLE>
<CAPTION>
                                                       For the Year Ended
                                                          December 31,
                                                    --------------------------
                                                      1998     1999     2000
                                                    --------  -------  -------
   <S>                                              <C>       <C>      <C>
   Numerator:
     Net income (loss) available to common
      stockholders................................. $(13,954) $(9,248) $38,566
                                                    ========  =======  =======
   Denominator:
     Basic weighted average number of shares.......    4,059    8,355   22,679
                                                    ========  =======  =======
     Dilutive securities:
       Stock options...............................       --       --    1,332
                                                    --------  -------  -------
     Diluted adjusted weighted average number of
      shares and assumed conversions...............    4,059    8,355   24,011
                                                    ========  =======  =======
   Net income (loss) per common share:
     Basic:
       Income (loss) before cumulative effect of
        change in accounting principle............. $  (3.44) $ (1.06) $  1.70
       Cumulative effect of change in accounting
        principle..................................       --    (0.05)      --
                                                    --------  -------  -------
     Net income (loss) per common share............ $  (3.44) $ (1.11) $  1.70
                                                    ========  =======  =======
     Diluted:
       Income (loss) before cumulative effect of
        change in accounting principle............. $  (3.44) $ (1.06) $  1.61
       Cumulative effect of change in accounting
        principle..................................       --    (0.05)      --
                                                    --------  -------  -------
     Net income (loss) per common share............ $  (3.44) $ (1.11) $  1.61
                                                    ========  =======  =======
</TABLE>

                                      51
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


   For purposes of the diluted earnings per share calculation, the Preferred
Stock and stock options are considered anti-dilutive for the years ended
December 31, 1998 and 1999 and are therefore not considered in the
calculations.

8. Major Customers:

   The Company had natural gas and oil sales to one customer accounting for
100 percent of total natural gas and oil revenues for the year ended December
31, 1998. 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. 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.

9. Related-Party Transactions:

   The Company paid to PGS approximately $122,000, $318,000 and $449,000 in
1998, 1999 and 2000, respectively, for seismic-related services.

   The Company paid $528,000 in 2000 to an oilfield services company
affiliated with one of the Company's board members.

   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:

   Effective with the formation of Spinco, the Company became subject to
federal income taxes. The formation of Spinco required the Company to
establish a deferred tax liability, which resulted in a one-time non-cash
charge to income of $1.7 million. During 1998, the Company generated
additional operating losses and the related tax benefits offset this amount.
No net income tax benefit was recognized in 1998 or 1999 due to the
uncertainty of future realization as the Company had not established a history
of net operating income. As of December 31, 2000, the Company had
approximately $93.8 million of net operating loss carryforwards, of which
$23.0 million, $30.2 million and $40.6 million expire in 2018, 2019 and 2020,
respectively.

                                      52
<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,
                                                                ---------------
                                                                 1999    2000
                                                                ------  -------
   <S>                                                          <C>     <C>
   Deferred income tax liabilities:
     Basis differences in natural gas and oil properties....... $9,063  $50,925
     Other.....................................................     56       --
                                                                ------  -------
       Total deferred income tax liabilities...................  9,119   50,925

   Deferred income tax assets:
     Net operating losses...................................... $9,304  $32,836
     Other.....................................................    414      932
                                                                ------  -------
       Total deferred income tax assets........................  9,718   33,768
   Valuation allowance.........................................   (599)      --
                                                                ------  -------
   Net deferred income tax assets..............................  9,119   33,768
                                                                ------  -------
   Net deferred income tax liabilities......................... $   --  $17,157
                                                                ======  =======
</TABLE>

   A tax benefit of $3.7 million associated with the exercise of non-qualified
stock options during the year ended December 31, 2000 is reflected as a
component of equity.

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

<TABLE>
<CAPTION>
                                                                 For the Year
                                                                     Ended
                                                                 December 31,
                                                               -----------------
                                                               1998 1999  2000
                                                               ---- ---- -------
   <S>                                                         <C>  <C>  <C>
   Current.................................................... $ -- $ -- $    25
   Deferred...................................................   --   --  20,833
                                                               ---- ---- -------
     Total provision.......................................... $ -- $ -- $20,858
                                                               ==== ==== =======
</TABLE>

   The difference 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 loss before income taxes is analyzed as below (in thousands):

<TABLE>
<CAPTION>
                                                       For the Year Ended
                                                          December 31,
                                                      -----------------------
                                                       1998    1999    2000
                                                      -------  -----  -------
   <S>                                                <C>      <C>    <C>
   Federal income tax expense (benefit) at statutory
    rates...........................................  $(2,400) $(468) $20,798
   Change in tax status.............................    1,668     --       --
   Non-deductible expenses and other................       --    601      659
   Valuation allowance..............................      732   (133)    (599)
                                                      -------  -----  -------
     Total provision................................  $    --  $  --  $20,858
                                                      =======  =====  =======
</TABLE>

                                      53
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


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.

 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, 2000, the Company
has paid to PGS a total of approximately $948,000 for seismic-related
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 6 percent of the participant's annual base
salary. For the year ended December 31, 2000, the Company issued 5,923 shares
of Common Stock valued at approximately $148,000 in connection with the
Company match.

 Leases

   The Company leases administrative offices under non-cancelable operating
leases expiring in 2002. 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. Minimum future
obligations under non-cancelable operating leases at December 31, 2000 for the
following five years are $623,000, $268,000, $70,000, $11,000 and $2,000,
respectively.

                                      54
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


12. Pro Forma Financial Information (Unaudited)

   The pro forma condensed consolidated statements of operations for the years
ended December 31, 1998 and 1999 assume the completion of the initial public
offering, the conversion of each share of Preferred Stock into two shares of
Common Stock, the reinvestment of Preferred Stock dividends into shares of
Common Stock and the retirement of all outstanding debt occurred on January 1,
1998 and 1999, respectively, and are as follows (in thousands, except per
share data):

<TABLE>
<CAPTION>
                                                              For the Year
                                                                  Ended
                                                              December 31,
                                                             ----------------
                                                              1998     1999
                                                             -------  -------
                                                               (Pro Forma)
   <S>                                                       <C>      <C>
   Revenues................................................. $ 3,298  $34,258
   Expenses.................................................  10,100   32,923
                                                             -------  -------
   Income (loss) from operations............................  (6,802)   1,335
   Other income (expense)...................................     458     (269)
                                                             -------  -------
   Income (loss) before income taxes........................  (6,344)   1,066
     Income tax provision...................................      --       --
                                                             -------  -------
   Income (loss) before cumulative effect of change in
    accounting principle....................................  (6,344)   1,066
     Cumulative effect of change in accounting principle....      --     (395)
                                                             -------  -------
   Pro forma net income (loss).............................. $(6,344) $   671
                                                             =======  =======
   Pro forma basic income (loss) per common share:
     Income (loss) before cumulative effect of change in
      accounting principle.................................. $ (0.45) $  0.05
     Cumulative effect of change in accounting principle....      --    (0.02)
                                                             -------  -------
   Pro forma net income (loss) per common share............. $ (0.45) $  0.03
                                                             =======  =======
   Pro forma diluted income (loss) per common share:
     Income (loss) before cumulative effect of change in
      accounting principle.................................. $ (0.45) $  0.05
     Cumulative effect of change in accounting principle....      --    (0.02)
                                                             -------  -------
   Pro forma net income (loss) per common share............. $ (0.45) $  0.03
                                                             =======  =======
   Pro forma weighted average number of common shares
    outstanding:
     Basic..................................................  14,078   19,274
                                                             =======  =======
     Diluted................................................  14,078   19,926
                                                             =======  =======
</TABLE>

   The pro forma condensed consolidated statement of operations for the year
ended December 31, 1998 reflects adjustments of approximately $516,000 to
eliminate interest expense as a result of the retirement of all outstanding
debt and $7.1 million to eliminate dividends as a result of the conversion of
each share of Preferred Stock into two shares of Common Stock.

   The pro forma condensed consolidated statement of operations for the year
ended December 31, 1999 reflects adjustments of approximately $3.0 million and
$966,000 to eliminate interest expense and capitalized interest as a result of
the retirement of all outstanding debt and $7.9 million to eliminate dividends
as a result of the conversion of each share of Preferred Stock into two shares
of Common Stock.

   The pro forma weighted average number of common shares outstanding includes
adjustments for the issuance of Common Stock in connection with the initial
public offering, the conversion of each share of Preferred Stock into two
shares of Common Stock, the reinvestment of Preferred Stock dividends into
shares of Common Stock and an adjustment to shares issued to PGS and Warburg
as consideration for providing guarantees under the Credit Agreement.

                                      55
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


13. Quarterly Financial Data (Unaudited):

   Quarterly operating results for the years ended December 31, 1999 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>
   1999:
   Revenues....................   $ 1,839  $ 7,744      $10,300      $14,375
   Income (loss) from
    operations.................    (1,193)  (2,019)       1,321        3,226
   Net income (loss)...........    (2,009)  (2,886)         249        3,309
   Net income (loss) available
    to common stockholders.....    (4,502)  (5,481)      (2,453)       3,188
   Net income (loss) per basic
    and diluted common share...   $ (1.10) $ (1.33)     $ (0.48)     $  0.16

   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>

   The first quarter of 1999 includes a charge of $395,000 related to a change
in accounting principle associated with previously capitalized organization
costs. The second quarter of 1999 includes compensation expense of
approximately $1.7 million related to the stock appreciation rights of two
officers' stock option agreements. See Note 6. The first two quarters of 1999
net loss per share amounts have been retroactively adjusted for the Stock
Split.

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,
                                                            ------------------
                                                              1999      2000
                                                            --------  --------
   <S>                                                      <C>       <C>
   Capitalized costs:
     Proved properties..................................... $141,455  $293,002
     Unproved properties not being amortized...............   40,696    83,165
                                                            --------  --------
       Total...............................................  182,151   376,167
   Accumulated depreciation, depletion and amortization....  (26,236)  (73,687)
                                                            --------  --------
       Net capitalized costs............................... $155,915  $302,480
                                                            ========  ========
</TABLE>

                                      56
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


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

   Acquisition costs include costs incurred to purchase, lease or otherwise
acquire property. Exploration costs include exploration expenses and additions
to exploratory wells, including those in progress. Development costs include
costs of completions, platforms, facilities and pipelines associated with
exploratory wells.

<TABLE>
<CAPTION>
                                                          For the Year Ended
                                                             December 31,
                                                       ------------------------
                                                        1998    1999     2000
                                                       ------- ------- --------
   <S>                                                 <C>     <C>     <C>
   Property acquisition costs:
     Unproved......................................... $15,791 $13,911 $ 21,421
     Proved...........................................      --      --       --
   Exploration costs..................................  46,620  45,152  121,451
   Development costs..................................  23,067  23,614   51,144
                                                       ------- ------- --------
       Total costs incurred........................... $85,478 $82,677 $194,016
                                                       ======= ======= ========
</TABLE>

 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, 1997....  12,607      125       13,358
     Extensions, discoveries and other
      additions...............................  40,014      357       42,155
     Revisions of previous estimates..........      --       --           --
     Production...............................  (1,675)     (12)      (1,747)
                                               -------    -----      -------
   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
                                               =======    =====      =======
   Proved developed reserves:
     December 31, 1997........................   5,615       46        5,892
                                               =======    =====      =======
     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
                                               =======    =====      =======
</TABLE>

                                      57
<PAGE>

                         SPINNAKER EXPLORATION COMPANY

            NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)


 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.

  . 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.

   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,
                                                ------------------------------
                                                  1998      1999       2000
                                                --------  --------  ----------
   <S>                                          <C>       <C>       <C>
   Future cash inflows........................  $ 99,436  $275,539  $1,730,754
   Future operating expenses..................   (16,562)  (36,396)    (60,259)
   Future development costs...................   (18,059)  (48,717)    (68,929)
                                                --------  --------  ----------
   Future net cash flows before income taxes..    64,815   190,426   1,601,566
   Future income taxes(1).....................        --        --    (516,488)
                                                --------  --------  ----------
   Future net cash flows......................    64,815   190,426   1,085,078
   10 percent annual discount per annum.......   (12,706)  (38,862)   (185,941)
                                                --------  --------  ----------
   Standardized measure of discounted future
    net cash flows............................  $ 52,109  $151,564  $  899,137
                                                ========  ========  ==========
</TABLE>
  --------
  (1) Net operating loss carryforwards and basis in natural gas and oil
      properties eliminated the need for future income taxes in 1998 and
      1999.

   Natural gas prices declined significantly subsequent to December 31, 2000.
Consequently, the present value of future net cash flows (before income taxes)
discounted at 10 percent and standardized measure of discounted future net
cash flows would be reduced if current natural gas prices were used in the
calculations. Utilizing the same methodology with prices of $5.00 per Mcf and
$25.00 per barrel, the standardized measure of discounted future net cash
flows would be approximately $455 million at December 31, 2000.

                                      58
<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,
                                                 ----------------------------
                                                  1998      1999      2000
                                                 -------  --------  ---------
   <S>                                           <C>      <C>       <C>
   Standardized measure, beginning of year...... $18,981  $ 52,109  $ 151,564
     Extensions and discoveries, net of related
      costs.....................................  35,952    75,572    719,694
     Sales of natural gas and oil produced, net
      of production costs.......................  (2,824)  (28,097)  (131,030)
     Net changes in prices and production
      costs.....................................  (4,329)   22,869    486,496
     Change in future development costs.........   2,713    (1,957)    (3,501)
     Development costs incurred during the
      period that reduced future development
      costs.....................................   2,246    14,494     37,851
     Revisions of quantity estimates............      --    13,624     34,749
     Accretion of discount......................   1,898     5,211     15,156
     Net change in income taxes.................      --        --   (421,535)
     Change in production rates and other.......  (2,528)   (2,261)     9,693
                                                 -------  --------  ---------
   Standardized measure, end of year............ $52,109  $151,564  $ 899,137
                                                 =======  ========  =========
</TABLE>

                                      59
<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-1
           (Commission File No. 333-41626))
   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)
   10.5   --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))
   10.6   --Employment Agreement between Spinnaker and James M. Alexander dated
           December 20, 1996, as amended (incorporated by reference to Exhibit
           10.7 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))
  10.11   --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))
</TABLE>

                                       60
<PAGE>

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

                                       61