SPINNAKER EXPLORATION CO, 424B4, 2000-08-11

SPINNAKER EXPLORATION CO
424B4, 2000-08-11
CRUDE PETROLEUM & NATURAL GAS

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<PAGE>

FILED PURSUANT TO RULE 424(b)(4)
REGISTRATION NO. 333-41626
4,900,000 Shares

[LOGO OF SPINNAKER EXPLORATION]

Spinnaker Exploration Company

Common Stock

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

Our common stock is listed for trading on the New York Stock Exchange under
the symbol "SKE." On August 10, 2000, the last reported sale price of our
common stock was $26.25 per share.

The underwriters have an option to purchase a maximum of 700,000 additional
shares to cover over-allotments of shares.

Investing in our common stock involves risks. See "Risk Factors" on page 11.

<TABLE>
<CAPTION>
Underwriting
Price to Discounts and Proceeds to
Public Commissions Spinnaker
------------ ------------- ------------
<S> <C> <C> <C>
Per Share................................... $26.25 $1.44 $24.81
Total....................................... $128,625,000 $7,056,000 $121,569,000
</TABLE>

Delivery of the shares of common stock will be made on or about August 16,
2000.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is truthful or complete. Any representation to the contrary is
a criminal offense.

Credit Suisse First Boston Donaldson, Lufkin & Jenrette

Banc of America Securities LLC

Dain Rauscher Wessels

Jefferies & Company, Inc.

The date of this prospectus is August 10, 2000.
<PAGE>

[Map of the onshore U.S. gulf coast and U.S. Gulf of Mexico showing the
location of our existing lease blocks, our discoveries and the coverage area of
the 3-D seismic data to which we have licenses.]

2
<PAGE>

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

TABLE OF CONTENTS

<TABLE>
<CAPTION>
Page
----
<S> <C>
Prospectus Summary.................. 4
Risk Factors........................ 11
Cautionary Statement About Forward-
Looking Statements................. 19
Use of Proceeds..................... 20
Price Range of Common Stock......... 20
Dividend Policy..................... 20
Dilution............................ 21
Capitalization...................... 22
Selected Consolidated Financial
Data............................... 23
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...................... 25
Business and Properties............. 32
Management.......................... 48
</TABLE>
<TABLE>
<CAPTION>
Page
----
<S> <C>
Certain Transactions.................................................. 56
Security Ownership of Management and Certain Beneficial Holders....... 58
Description of Capital Stock.......................................... 60
Underwriting.......................................................... 64
Notice to Canadian Residents.......................................... 66
Legal Matters......................................................... 67
Experts............................................................... 67
Where You Can Find More Information................................... 67
Glossary of Natural Gas and Oil Terms................................. 68
Index To Consolidated Financial Statements............................ F-1
Report of Independent Petroleum Engineers............................. A-1
</TABLE>

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

You should rely only on the information contained in this document or to
which we have referred you. We have not authorized anyone to provide you with
information that is different. This document may only be used where it is legal
to sell these securities. The information in this document may only be accurate
on the date of this document.

3
<PAGE>

PROSPECTUS SUMMARY

This summary highlights selected information from this prospectus, but does
not contain all information that may be important to you. This prospectus
includes specific terms of this offering, information about our business and
financial data. We encourage you to read this prospectus in its entirety before
making an investment decision. Unless otherwise indicated, this prospectus
assumes no exercise of the underwriters' over-allotment option. We have
provided definitions for some of the natural gas and oil industry terms used in
this prospectus in the "Glossary of Natural Gas and Oil Terms" on page 68 of
this prospectus.

About Spinnaker

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. We currently have license rights to approximately 8,750 blocks
of mostly contiguous, recent vintage 3-D seismic data in the Gulf of Mexico,
including approximately 5,700 blocks from our 3-D seismic data agreement with
Petroleum Geo-Services ASA. This database covers an area of approximately 35
million acres, which we believe is one of the largest recent vintage 3-D
seismic databases of any independent exploration and production company in the
Gulf of Mexico. We consider recent vintage 3-D seismic data to be data
generated since 1990. As of June 30, 2000, we had 173 leasehold interests
located in Texas state and federal waters covering approximately 639,000 gross
and 280,000 net acres. We believe our regional 3-D seismic approach allows us
to create and maintain a large inventory of high-quality prospects and provides
us the opportunity to enhance our exploration success and efficiently deploy
our capital resources. We also believe our license rights to large quantities
of high-quality seismic data and our management and technical staff are
important factors for our current and future success.

Our Chief Executive Officer, Petroleum Geo-Services and Warburg, Pincus
Ventures, L.P. formed Spinnaker in December 1996. Petroleum Geo-Services, a
leader in acquiring 3-D seismic data, received most of its equity ownership in
Spinnaker in exchange for providing us with access to its inventory of 3-D
seismic data covering a substantial portion of the natural gas and oil
producing area of the Gulf of Mexico. We plan to continue to grow our inventory
of 3-D seismic data through our agreement with Petroleum Geo-Services and
through acquisitions from other seismic data vendors.

Since our inception, we have participated in drilling 47 exploratory wells
in the Gulf of Mexico, with 28 of these wells being completed as discoveries.
As of June 30, 2000, Ryder Scott Company, L.P. estimated our net proved
reserves at approximately 123.1 Bcfe, 89 percent of which was natural gas,
representing an increase of approximately 129 percent over our estimated net
proved reserves of 53.8 Bcfe at December 31, 1998. Our daily production
increased to approximately 74,000 Mcfe at June 30, 2000, from approximately
8,000 Mcfe at December 31, 1998. Within our current inventory of leasehold
interests, we have identified approximately 86 exploratory prospects or leads.
We expect to drill approximately 15 or more of these prospects during the
remainder of 2000. Based on 3-D seismic analysis on blocks where we currently
have no leasehold interest, we also have identified over 100 additional leads
that may result in additional prospects. Our capital expenditure budget for
2000 includes approximately $150.0 million for exploration, development,
leasehold acquisitions and other capital expenditures, of which we incurred
$68.2 million through June 30, 2000.

Our Strategy

Our goals are to expand our reserve base, cash flow and net income and to
generate an attractive return on capital. We emphasize the following elements
in our strategy to achieve these goals:

4
<PAGE>

regions in North America. We also believe our geographic focus provides us with
an excellent opportunity to develop and maintain competitive advantages through
the combination of our 3-D seismic database, regional exploration and operating
expertise, and joint venture relationships.

Maintain a large database of 3-D seismic data. We believe our large database
of 3-D seismic data allows us to generate and maintain a large inventory of
high-quality exploratory prospects. We believe the 3-D seismic data we have
received from Petroleum Geo-Services will continue to serve as the foundation
for our exploration program. We will continue to supplement that data with 3-D
seismic data acquisitions from other seismic data vendors.

Employ a rigorous prospect selection process. We use our 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, we enhance
our understanding of the geology before selecting prospects and increase the
probability of accurately identifying hydrocarbon-bearing zones.

Emphasize technical expertise. Our 12 explorationists have an average of
approximately 20 years experience in exploration in the Gulf of Mexico. In our
efforts to attract and retain explorationists, we offer an entrepreneurial
culture, an extensive 3-D seismic database, state-of-the-art computer-aided
exploration technology and other technical tools.

As Spinnaker matures, we are 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 our technical expertise has allowed
us to act as the operator for an increasing number of these prospects,
providing us with more control of costs, the timing and amount of capital
expenditures, and the selection of technology.

Sustain a balanced, diversified exploration effort. We believe that our
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.

We have used joint ventures to help diversify our exploration activities.
Our 3-D seismic data's broad coverage of the Gulf of Mexico allows us to
participate in a variety of geologically diverse exploration opportunities and
create a diversified prospect portfolio. We intend to manage our 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 we believe 3-D seismic analysis provides attractive risk/reward benefits.
We also strive to diversify our exploration efforts by seeking to limit the
budgeted amount of the leasehold acquisition and drilling cost of the first
exploratory well on any one prospect to less than 10 percent of our annual
capital budget.

We believe that maintaining continuity in our exploration activity during
all phases of the commodity price cycles is an important element to balance and
diversification. By positioning Spinnaker to have a continuous exploration
program, we 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.

Risks related to our strategy. Prospective investors should carefully
consider the matters set forth under the caption "Risk Factors," as well as the
other information set forth in this prospectus, including that our future
operating results are difficult to forecast because of our limited operating
history, the 3-D seismic data and other technologies we use cannot eliminate
exploration risk, our ability to find additional reserves could be

5
<PAGE>

materially impaired if Petroleum Geo-Services terminates our data agreement,
our relatively small number of offshore properties increases our exposure to
production problems, reserve estimate inaccuracies materially affect the
quantities and net present value of our reserves, our Gulf of Mexico focus
subjects us to higher reserve replacement needs, and the natural gas and oil
business involves many operating and financial risks, especially in the deep
waters of the Gulf of Mexico. One or more of these matters could negatively
impact our ability to implement successfully our business strategy.

Significant Exploration Discoveries

The following table summarizes the most significant of our 28 exploration
discoveries since our inception. Please also read "Business and Properties--
Exploration Activities--Significant Exploration Discoveries" for a more
detailed discussion of these discoveries.

<TABLE>
<CAPTION>
Spinnaker Approximate Date Production
Working Water Depth Commenced/
Discovery Block Operator Interest (feet) Expected
--------------- --------- --------- ----------- ----------------
<S> <C> <C> <C> <C>
High Island 202......... Spinnaker 75% 50 May 2000
South Timbalier
219/211................ Spinnaker 72 3/4% 150 February 2000
North Padre Island 883.. Spinnaker 35% 80 Second half 2000
Brazos A-19............. Shell 15% 130 First half 2002
High Island A-18........ Spinnaker 100% 60 Second half 2000
Garden Banks 367
(Dulcimer)............. Mariner 33 1/3% 1,100 April 1999
Mississippi Canyon 496
(Zia).................. Shell 12 1/2% 1,800 Second half 2002
South Timbalier 220..... Samedan 33 1/3% 150 August 1998
West Cameron 39......... Spinnaker 60% 30 January 1999
Vermilion 375........... Spinnaker 70% 300 Second half 2000
West Cameron 522........ Newfield 46% 180 March 1998
High Island A-7......... Spinnaker 53% 50 Second half 2000
</TABLE>

Our Executive Offices

Our executive offices are located at 1200 Smith Street, Suite 800, Houston,
Texas 77002, and our telephone number is (713) 759-1770.

6
<PAGE>

The Offering

<TABLE>
<S> <C>
Common stock offered by 4,900,000 shares
Spinnaker........................

Common stock to be outstanding 25,478,303 shares(1)
after this offering..............

Use of proceeds................... We intend to use the net proceeds of this
offering to repay all outstanding
indebtedness under our credit facility, to
fund a portion of our exploration
activities, which includes drilling
approximately 15 or more wells during the
remainder of 2000, to acquire seismic data,
and for general corporate purposes,
including possible acquisitions of
properties or businesses.

New York Stock Exchange symbol.... SKE
</TABLE>
--------
(1) Excludes 3,611,185 shares of common stock issuable on exercise of
outstanding options at a weighted average exercise price of $11.41 per
share as of June 30, 2000.

7
<PAGE>

Summary Consolidated Financial Data

(in thousands, except per share data)

The following table sets forth some of our historical consolidated financial
data. You should read the following data in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our consolidated financial statements included elsewhere in this prospectus.

<TABLE>
<CAPTION>
Year Ended Six Months Ended June
December 31, 30,
---------------------------- ----------------------
1997 1998 1999 1999 2000
-------- -------- -------- -------- ------------
Statement of Operations
Data: (unaudited)
<S> <C> <C> <C> <C> <C>
Revenues................. $ 201 $ 3,298 $ 34,258 $ 9,583 $ 33,012
-------- -------- -------- -------- --------
Expenses:
Lease operating
expenses............... 72 474 5,411 1,183 3,875
Depreciation, depletion
and amortization--
natural gas and oil
properties............. 68 2,738 20,788 7,619 17,644
Depreciation and
amortization--other.... 349 437 213 98 144
Write-down of natural
gas and oil properties
(1).................... -- 2,642 -- -- --
General and
administrative......... 1,965 3,809 4,860 2,244 3,100
Stock appreciation
rights expense (2)..... -- -- 1,651 1,651 --
-------- -------- -------- -------- --------
Total expenses........ 2,454 10,100 32,923 12,795 24,763
-------- -------- -------- -------- --------
Income (loss) from
operations.............. (2,253) (6,802) 1,335 (3,212) 8,249
Other income (expense):
Interest income......... 91 221 528 85 313
Interest expense........ -- (516) (3,771) (2,007) (254)
Capitalized interest.... -- 237 966 634 17
-------- -------- -------- -------- --------
Income (loss) before
income taxes............ (2,162) (6,860) (942) (4,500) 8,325
Income tax provision.... -- -- -- -- --
-------- -------- -------- -------- --------
Income (loss) before
cumulative effect of
change in accounting
principle............... (2,162) (6,860) (942) (4,500) 8,325
Cumulative effect of
change in accounting
principle (3)........... -- -- (395) (395) --
-------- -------- -------- -------- --------
Net income (loss)........ $ (2,162) $ (6,860) $ (1,337) $ (4,895) $ 8,325
======== ======== ======== ======== ========
Accrual of dividends on
preferred stock......... (1,326) (7,094) (7,911) (5,088) --
-------- -------- -------- -------- --------
Net income (loss)
available to common
stockholders............ $ (3,488) $(13,954) $ (9,248) $ (9,983) $ 8,325
======== ======== ======== ======== ========
Basic income (loss) per
common share (4)(5):
Income (loss) before
cumulative effect of
change in accounting
principle.............. $ (0.88) $ (3.44) $ (1.06) $ (2.33) $ 0.41
Cumulative effect of
change in accounting
principle (3).......... -- -- (0.05) (0.10) --
-------- -------- -------- -------- --------
Net income (loss) per
common share........... $ (0.88) $ (3.44) $ (1.11) $ (2.43) $ 0.41
======== ======== ======== ======== ========
Diluted income (loss) per
common share (4)(5):
Income (loss) before
cumulative effect of
change in accounting
principle.............. $ (0.88) $ (3.44) $ (1.06) $ (2.33) $ 0.39
Cumulative effect of
change in accounting
principle (3).......... -- -- (0.05) (0.10) --
-------- -------- -------- -------- --------
Net income (loss) per
common share........... $ (0.88) $ (3.44) $ (1.11) $ (2.43) $ 0.39
======== ======== ======== ======== ========
Weighted average number
of common shares
outstanding--basic
(4)(5).................. 3,960 4,059 8,355 4,113 20,469
======== ======== ======== ======== ========
Weighted average number
of common shares
outstanding--diluted
(4)(5).................. 3,960 4,059 8,355 4,113 21,539
======== ======== ======== ======== ========
Other Data:
Adjusted EBITDA (6)...... $ (1,836) $ (985) $ 23,987 $ 6,156 $ 26,037
Net cash provided by
(used in) operating
activities.............. (5,523) (2,776) 14,905 4,508 22,668
Net cash used in
investing activities.... (15,236) (68,503) (85,101) (47,673) (54,839)
Net cash provided by
financing activities.... 18,863 70,738 88,507 45,000 13,111
Capital expenditures..... 15,578 85,681 79,810 33,575 68,237

<CAPTION>
At December 31, At June 30, 2000
---------------------------- ----------------------
As
1997 1998 1999 Actual Adjusted (7)
-------- -------- -------- -------- ------------
(unaudited)
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash and cash
equivalents............. $ 2,682 $ 2,141 $ 20,452 $ 1,392 $110,511
Current assets........... 6,348 6,737 32,126 20,726 129,845
Total assets............. 22,358 102,769 189,553 227,220 336,339
Short-term debt.......... -- 19,000 -- 12,000 --
Other current
liabilities............. 2,096 18,378 12,451 28,625 28,625
Total equity (5)......... 18,879 56,913 177,102 186,595 307,714
</TABLE>

8
<PAGE>

--------
(1) At December 31, 1998, we 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 Securities and Exchange
Commission rules, in calculating the amount of the write-down, we 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
we had used only December 31, 1998 natural gas and oil prices, we 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 our 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 our estimate of the share value of
Spinnaker, we 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 our
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 we
issued common units and preferred units. In connection with our conversion
to a corporation in January 1998, we exchanged common stock for all then
outstanding common units and preferred stock for all then outstanding
preferred units. We express all historical unit data in shares.

(5) In connection with our initial public offering, we 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.

(6) As used in this prospectus, Adjusted EBITDA means earnings before interest,
income taxes, depreciation, depletion and amortization, write-down of
natural gas and oil properties, and stock appreciation rights expense.
Adjusted EBITDA is not a calculation based upon generally accepted
accounting principles. Adjusted EBITDA should not be considered as an
alternative to net income as an indicator of our operating performance, or
as an alternative to cash flow as a better measure of liquidity. Adjusted
EBITDA measures presented in this prospectus may not be comparable to other
similarly titled measures reported by other companies. In evaluating
Adjusted EBITDA, Spinnaker believes that investors should consider, among
other things, the amount by which Adjusted EBITDA exceeds interest costs,
how Adjusted EBITDA compares to principal repayments on debt and how
Adjusted EBITDA compares to capital expenditures for each period.

(7) The "As Adjusted" balance sheet data gives effect to the application of the
$121.1 million of estimated net proceeds from the sale of common stock in
this offering.

9
<PAGE>

Summary Reserve Information

The table below presents our summary reserve information as of June 30,
2000. Estimates of proved reserves are based on the June 30, 2000 reserve
report prepared by Ryder Scott Company, L.P., our independent petroleum
engineering consultants. Appendix A to this prospectus contains a letter
prepared by Ryder Scott Company, L.P. summarizing the reserve report. For
additional information relating to our natural gas and oil reserves, please
read "Business and Properties--Natural Gas and Oil Reserves" and note 14 of the
notes to our consolidated financial statements.

The present value of future net cash flows attributable to our proved
reserves using prices and costs in effect at June 30, 2000, discounted at 10
percent per annum, was determined by using prices of $4.55 per Mcf of natural
gas and $32.72 per barrel of oil, which represents market prices in effect at
June 30, 2000 of $4.37 per MMBtu of natural gas and $32.50 per barrel of oil,
adjusted for transportation and grade differences.
<TABLE>
<CAPTION>
As of
June 30, 2000
-------------
<S> <C>
Estimated proved reserves:
Natural gas (MMcf)............................................ 109,500
Oil and condensate (MBbls).................................... 2,262
Total (MMcfe)............................................... 123,070
Proved developed reserves as a percentage of proved reserves.... 41%
Present value of future net cash flows (before income taxes)
discounted at 10% (1).......................................... 376,716
Standardized measure of discounted future net cash flows (1).... 303,393
</TABLE>
--------
(1) Includes unrealized losses of $16.3 million for the effects of our hedging
activities using natural gas and oil prices in effect at June 30, 2000.

Summary Operating Data

<TABLE>
<CAPTION>
Six Months
Year Ended Ended June
December 31, 30,
--------------------- -------------
1997 1998 1999 1999 2000
------ ------ ------- ------ ------
<S> <C> <C> <C> <C> <C>
Production:
Natural gas (MMcf)..................... 70 1,675 11,962 4,258 10,279
Oil and condensate (MBbls)............. -- 12 180 49 99
Total (MMcfe)........................ 70 1,747 13,044 4,552 10,872
Average sales price per unit:
Natural gas revenues from production
(per Mcf)............................. $ 2.87 $ 1.89 $ 2.49 $ 2.09 $ 3.18
Effects of hedging activities (per
Mcf).................................. -- -- 0.08 -- (0.17)
------ ------ ------- ------ ------
Average price (per Mcf).............. $ 2.87 $ 1.89 $ 2.57 $ 2.09 $ 3.01

Oil and condensate revenues from
production (per Bbl).................. $18.51 $11.61 $ 20.33 $14.70 $27.86
Effects of hedging activities (per
Bbl).................................. -- -- (0.57) -- (7.28)
------ ------ ------- ------ ------
Average price (per Bbl).............. $18.51 $11.61 $ 19.76 $14.70 $20.58

Total revenues from production (per
Mcfe)................................. $ 2.87 $ 1.89 $ 2.57 $ 2.11 $ 3.26
Effects of hedging activities (per
Mcfe)................................. -- -- 0.06 -- (0.22)
------ ------ ------- ------ ------
Total average price (per Mcfe)....... $ 2.87 $ 1.89 $ 2.63 $ 2.11 $ 3.04
Expenses (per Mcfe):
Lease operating expenses (1)........... $ 1.03 $ 0.27 $ 0.41 $ 0.26 $ 0.36
Depreciation, depletion and
amortization--natural gas and oil
properties............................ 0.97 1.57 1.59 1.67 1.62
</TABLE>
--------
(1) Lease operating expenses per Mcfe for the six months ended June 30, 2000
include approximately $0.08 per Mcfe associated with workovers on four
wells. Lease operating expenses per Mcfe for the year ended December 31,
1999 include approximately $0.13 per Mcfe associated with workovers on two
wells and well control activities on another well.

10
<PAGE>

RISK FACTORS

Investing in our common stock will provide you with an equity ownership in
Spinnaker. As one of our stockholders, you will be subject to risks inherent in
our business. The trading price of your shares will be affected by the
performance of our business relative to, among other things, competition,
market conditions and general economic and industry conditions. The value of
your investment may decrease, resulting in a loss. You should carefully
consider the following factors as well as other information contained in this
prospectus before deciding to invest in shares of our common stock.

Because we have a limited operating history and have incurred losses from
operations and net losses in recent years, our future operating results are
difficult to forecast. Our failure to achieve or sustain profitability in the
future could adversely affect the market price of our common stock.

We were formed in December 1996 and, as a result, we have a limited
operating history. Our limited operating history and the unpredictable results
of our exploration and development strategy make it difficult to forecast our
operating results. In considering whether to invest in our common stock, you
should consider the limited historical financial and operating information
available on which to base your evaluation of our performance. In addition,
because we have a limited operating history and fewer financial resources than
many companies in our industry, we may be at a disadvantage in bidding for
exploratory prospects and in developing natural gas and oil properties. Please
read "Business and Properties--Competition" for a description of the
competition we face in our business.

We have incurred losses from operations and net losses in recent years. We
incurred net losses of $328,000 in 1996, $2.2 million in 1997, $6.9 million in
1998 and $1.3 million in 1999. Our development of and participation in an
increasingly larger number of prospects has required and will continue to
require substantial capital expenditures. We cannot assure you that we will
achieve or sustain profitability or positive cash flows from operating
activities in the future. Our failure to achieve or sustain profitability in
the future could adversely affect the market price of our common stock.

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

Our future success will depend on the success of our 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, we often are uncertain as to the future cost or timing of drilling,
completing and producing wells. Furthermore, our 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. We could incur losses
as a result of these expenditures. Poor results from our exploration activities
could affect our future cash flows and results of operations materially and
adversely.

11
<PAGE>

Our exploratory drilling success will depend, in part, on our 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 we cannot retain our current personnel
or attract additional experienced personnel, our ability to compete in the Gulf
of Mexico could be adversely affected.

If Petroleum Geo-Services terminates our data agreement, our ability to find
additional reserves could be materially impaired. If Petroleum Geo-Services
does not resume 3-D seismic data acquisition in the Gulf of Mexico during the
remaining term of our agreement, we may incur additional costs to acquire data
from other vendors, which costs could be material.

Our success depends heavily on our access to 3-D seismic data, and our
primary source for 3-D seismic data is our data agreement with Petroleum Geo-
Services. If Petroleum Geo-Services terminates our agreement, we would lose
substantially all of our current access to 3-D seismic data which loss would
have a material adverse effect on our ability to find additional reserves.

Petroleum Geo-Services may terminate our data agreement on several grounds,
including if a Petroleum Geo-Services competitor acquires control of us or we
breach the agreement subject to specified exceptions. For a description of
these exceptions, please read "Business and Properties--Petroleum Geo-Services
Data Agreement--Termination Events."

We currently have license rights under our Petroleum Geo-Services data
agreement to approximately 5,700 blocks of 3-D seismic data in the Gulf of
Mexico. Our agreement does not require Petroleum Geo-Services to acquire or
process any further data. At this time, Petroleum Geo-Services has elected to
cease 3-D seismic data acquisitions in the Gulf of Mexico. We cannot assure you
that Petroleum Geo-Services will resume 3-D seismic data acquisitions in the
Gulf of Mexico during the remaining term of our agreement. If Petroleum Geo-
Services does not resume 3-D seismic data acquisition in the Gulf of Mexico
during the remaining term of our agreement, we may incur additional costs to
acquire data from other vendors, which costs could be material. Even if
Petroleum Geo-Services elects to resume 3-D seismic data acquisitions in the
Gulf of Mexico, it again could elect to cease 3-D seismic data acquisitions as
a result of a change of control of Petroleum Geo-Services or changes in
Petroleum Geo-Services' competitive, financial or technological status.

Petroleum Geo-Services also could significantly increase the acquisition or
processing of data in the Gulf of Mexico that it is not required to share with
us. For example, Petroleum Geo-Services could focus on acquiring and processing
data on an exclusive contractual basis and not for sale to multiple customers.
In addition, if Petroleum Geo-Services were to engage new marketing vendors who
would not agree to the terms of our agreement with Petroleum Geo-Services, then
we would not have access to the data marketed through those vendors. Petroleum
Geo-Services also could elect to acquire or process other seismic data,
including future generations of seismic data, to which we are not entitled or
for which our rights are limited. Our right to enhanced data also could be
adversely affected if Petroleum Geo-Services were to elect to sell the right to
enhance and market its data without retaining a material royalty or similar
interest.

Natural gas and oil prices fluctuate widely, and low prices could have a
material adverse impact on our business.

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. Among the
factors that can cause this fluctuation are:

. the level of consumer product demand;

. weather conditions;

12
<PAGE>

. 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 our
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 shown in this
prospectus. Please read "Business and Properties--Natural Gas and Oil Reserves"
for a discussion of our proved natural gas and oil reserves.

In order to prepare these estimates, we must project production rates and
timing of development expenditures. We 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 our estimates. Any
significant variance could materially affect the estimated quantities and
present value of reserves shown in this prospectus. In addition, we 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 our control. At June 30, 2000, 74 percent of
our proved reserves were either proved undeveloped or proved non-producing.
Moreover, the producing wells included in our reserve report had produced for a
relatively short period of time as of June 30, 2000. Because most of our
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
our proved reserves referred to in this prospectus is the current market value
of our estimated natural gas and oil reserves. In accordance with Securities
and Exchange Commission requirements, we base the estimated discounted future
net cash flows from our 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 our 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 our business.

During the first half of 2000, over 78 percent of our daily production came
from six of our properties in the Gulf of Mexico. If mechanical problems,
storms or other events curtailed a substantial portion of this production, our
cash flow would be adversely affected. In addition, at June 30, 2000, our
proved reserves were located on 25 discoveries in the Gulf of Mexico, with
approximately 51 percent of our proved reserves attributable to four of these
discoveries. If the actual reserves associated with any one of these four
discoveries are less than our estimated reserves, our results of operations and
financial condition could be adversely affected.

13
<PAGE>

We are vulnerable to operational, regulatory and other risks associated with
the Gulf of Mexico because we currently explore and produce exclusively in that
area.

Our operations and revenues are impacted acutely by conditions in the Gulf
of Mexico because we currently explore and produce exclusively in that area.
This concentration of activity makes us more vulnerable than many of our
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, we have experienced
increasing costs for and in the future may experience reduced availability of
these services.

Relatively short production periods for Gulf of Mexico properties subject us to
higher reserve replacement needs, require significant capital expenditures to
replace production and may impair our 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, our reserve replacement needs from new prospects are
greater and require us to incur significant capital expenditures to replace
production.

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

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

Our future natural gas and oil production depends on our success in finding
or acquiring additional reserves. If we fail to replace reserves, our 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. Our total proved
reserves decline as reserves are produced unless we conduct other successful
exploration and development activities or acquire properties containing proved
reserves, or both. Our ability to make the necessary capital investment to
maintain or expand our 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. We may not be successful in
exploring for, developing or acquiring additional reserves. If we are not
successful, our future production and revenues will be adversely affected.

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

To reduce our exposure to fluctuations in the prices of natural gas and oil,
we enter into hedging arrangements with respect to a portion of our expected
production. Hedging arrangements expose us to risks in some circumstances,
including the following:

. 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.

14
<PAGE>

These hedging arrangements have limited and may continue to limit the
benefit we could receive from increases in the prices for natural gas and oil.
The estimated fair value of our open collar arrangements as of June 30, 2000
was equal to an unrealized loss of approximately $12.5 million for the last six
months of 2000 and an unrealized loss of approximately $3.8 million for 2001
using NYMEX natural gas and oil prices as of June 30, 2000. However, if we
choose not to engage in hedging arrangements in the future, we may be more
adversely affected by changes in natural gas and oil prices than our
competitors who engage in hedging arrangements.

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, we 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 our operations; and

. repairs to resume operations.

If we experience any of these problems, it could affect well bores,
platforms, gathering systems and processing facilities, which could adversely
affect our 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,
we 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.

We do not carry business interruption insurance. For some risks, we may not
obtain insurance if we believe 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 our
operations.

15
<PAGE>

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 our expansion into the deep water could result in substantial
losses.

As part of our strategy, we explore 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. Our deep water drilling and operations require the
application of recently developed technologies that involve a higher risk of
mechanical failure. We have experienced and will continue to experience
significantly higher drilling costs for our 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 we can market the natural gas or oil, increasing
both the financial and operational risk involved with these operations.

We cannot control the activities on properties we do not operate.

Other companies operate some of the properties in which we have an interest.
As a result, we have a limited ability to exercise influence over operations
for these properties or their associated costs. Our dependence on the operator
and other working interest owners for these projects and our limited ability to
influence operations and associated costs could materially adversely affect the
realization of our targeted returns on capital in drilling or acquisition
activities. The success and timing of our drilling and development activities
on properties operated by others therefore depend on a number of factors that
are outside of our 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.

Our success depends on our Chief Executive Officer and other key personnel, the
loss of whom could disrupt our business operations.

We depend to a large extent on the efforts and continued employment of our
President and Chief Executive Officer, Roger L. Jarvis, and other key
personnel. If Mr. Jarvis or these other key personnel resign or become unable
to continue in their present role and if they are not adequately replaced, our
business operations could be adversely affected. Please read "Management" for
information regarding Mr. Jarvis and other members of our management team.

We may have difficulty financing our planned growth.

We have experienced and expect to continue to experience substantial capital
expenditure and working capital needs, particularly as a result of our drilling
program. In the future, we will require additional financing, in addition to
cash generated from our operations, to fund our planned growth. We cannot be
certain that additional financing will be available to us on acceptable terms
or at all. In the event additional capital resources are unavailable, we may
curtail our drilling, development and other activities or be forced to sell
some of our assets on an untimely or unfavorable basis.

Competition in our industry is intense, and we are smaller and have a more
limited operating history than most of our competitors in the Gulf of Mexico.

We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and develop properties. Most of our competitors have substantially
greater financial and other resources than us. As a result, in the deep water
where exploration is more expensive, our 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 we can, which would adversely
affect our competitive position. These

16
<PAGE>

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 we can. Our ability
to explore for natural gas and oil prospects and to acquire additional
properties in the future will depend on our ability to conduct operations, to
evaluate and select suitable properties and to consummate transactions in this
highly competitive environment. In addition, most of our competitors have been
operating in the Gulf of Mexico for a much longer time than we have and have
demonstrated the ability to operate through industry cycles.

Our competitors may use superior technology which we may be unable to afford or
which would require costly investment by us in order to compete.

Our industry is subject to rapid and significant advancements in technology,
including the introduction of new products and services using new technologies.
As our competitors use or develop new technologies, we may be placed at a
competitive disadvantage, and competitive pressures may force us to implement
new technologies at a substantial cost. In addition, our 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 we can. We cannot be certain that we will be able to
implement technologies on a timely basis or at a cost that is acceptable to us.
One or more of the technologies that we currently use or that we may implement
in the future may become obsolete, and we 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 our 3-D seismic data's
value.

One customer currently purchases all of our natural gas production. As a
result, if this customer defaults on its payment obligations, our near-term
earnings and cash flows would be adversely affected.

We are 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. We may be required to make large expenditures to comply with
environmental and other governmental regulations. Matters subject to regulation
include:

. discharge permits for drilling operations;

. drilling bonds;

. reports concerning operations; and

. taxation.

Under these laws and regulations, we could be liable for personal injuries,
property damage, oil spills, discharge of hazardous materials, remediation and
clean-up costs and other environmental damages. We do 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 our operations and subject us to
administrative, civil and criminal penalties. Moreover, these laws and
regulations could change in ways that substantially increase our costs. For
example, Congress or the Minerals Management Service 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 our
financial condition and results of operations.

17
<PAGE>

Petroleum Geo-Services, Warburg, Pincus Ventures and our management own a
significant amount of common stock, giving them influence or control in
corporate transactions and other matters, and the interest of Warburg, Pincus
Ventures or Petroleum Geo-Services could differ from those of other
stockholders.

On completion of this offering, Warburg, Pincus Ventures, Petroleum Geo-
Services, and our executive officers will beneficially own approximately 52
percent of our outstanding shares of common stock, assuming no exercise of the
underwriters' over-allotment option. As a result, these stockholders will
continue to be 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 our certificate of incorporation or bylaws and
the approval of mergers and other significant corporate transactions. In
addition, representatives of Petroleum Geo-Services and Warburg, Pincus
Ventures constitute a majority of our board of directors. Their control of
Spinnaker may delay or prevent a change of control of Spinnaker and may
adversely affect the voting and other rights of other stockholders.

Furthermore, conflicts of interest could arise in the future between
Spinnaker, on the one hand, and Warburg, Pincus Ventures or Petroleum Geo-
Services, on the other hand, concerning, among other things, potential
competitive business activities or business opportunities. Except for the
limited restrictions placed on Petroleum Geo-Services in our data agreement
with Petroleum Geo-Services, neither Warburg, Pincus Ventures nor Petroleum
Geo-Services are restricted from competitive natural gas and oil exploration
and production activities or investments. Warburg, Pincus Ventures currently
has significant equity interests in other public and private natural gas and
oil companies. The interest of Warburg, Pincus Ventures or Petroleum Geo-
Services could differ from those of our other stockholders. Please read
"Certain Transactions" for a discussion of agreements with those stockholders.

Substantially all of our outstanding shares may be sold into the market in the
near future. This could cause the market price of our common stock to drop
significantly, even if our business is doing well.

The market price of our common stock could drop due to sales of a large
number of shares of our common stock in the market after the offering or the
perception that such sales could occur. This could make it more difficult to
raise funds through future offerings of common stock.

Our certificate of incorporation and bylaws contain provisions that could
discourage an acquisition or change of control of Spinnaker.

Our certificate of incorporation authorizes our board of directors to issue
preferred stock without stockholder approval. If our board of directors elects
to issue preferred stock, it could be more difficult for a third party to
acquire control of us, 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 us. Please read "Description
of Capital Stock" for additional details concerning the provisions of our
certificate of incorporation and bylaws.

18
<PAGE>

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

Some of the information in this prospectus, including information
incorporated by reference, contains forward-looking statements within the
meaning of Section 27A of the Securities Act of 1933, as amended, and Section
21E of the Securities Exchange Act of 1934, as amended. The forward-looking
statements speak only as of the date made. 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 our operating
results, including:

. the risks associated with exploration;

. our 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 our properties;

. our ability to find and retain skilled personnel;

. availability of capital;

. the strength and financial resources of our competitors;

. regulatory developments;

. environmental risks; and

. general economic conditions.

Any of the factors listed above and other factors contained in this
prospectus could cause our actual results to differ materially from the results
implied by these or any other forward-looking statements made by us or on our
behalf. We cannot assure you that our future results will meet our
expectations. You should pay particular attention to the risk factors and
cautionary statements described under "Risk Factors" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations."

19
<PAGE>

USE OF PROCEEDS

We estimate that we will receive net proceeds of $121.1 million, or $138.5
million if the underwriters exercise their over-allotment option in full, from
the sale of the shares of common stock offered by this prospectus, after
deducting underwriting discounts and commissions and estimated offering
expenses.

We intend to use approximately $17.0 million of the net proceeds to repay
all of our outstanding debt under our credit facility. We intend to use the
remainder of the net proceeds as follows:

. to fund a portion of our exploration activities, which includes drilling
approximately 15 or more wells during the remainder of 2000;

. to acquire seismic data; and

. for general corporate purposes, including possible acquisitions of
properties or businesses.

Pending use for these purposes, we plan to invest the net proceeds in short-
term investment-grade interest-bearing securities.

At August 10, 2000, we had $17.0 million outstanding under our credit
facility bearing interest at a weighted average rate of 8.5 percent. Our credit
facility matures in July 2001. We have used borrowings under our current credit
facility to repay indebtedness used to fund a portion of our exploration and
development activities and for other general corporate purposes. Please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources" for a discussion of our current
credit agreement.

PRICE RANGE OF COMMON STOCK

Our common stock began trading on the New York Stock Exchange on July 26,
2000 under the symbol "SKE." Prior to that date, our 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 (through August 10, 2000)....................... $31.50 $24.03
</TABLE>

On August 10, 2000, the closing sale price of our common stock, as reported
by the New York Stock Exchange, was $26.25 per share. On June 30, 2000, there
were 34 holders of record and approximately 1,000 beneficial owners of our
common stock.

DIVIDEND POLICY

We have never declared or paid any dividends on our common stock. We
currently intend to retain future earnings, if any, for the operation and
development of our business and do not anticipate paying any dividends on our
common stock in the foreseeable future. In addition, our current credit
agreement prohibits us from paying cash dividends on our common stock. Any
future dividends may also be restricted by any loan agreements which we may
enter into from time to time.

20
<PAGE>

DILUTION

The net tangible book value of our common stock on June 30, 2000 was $9.07
per share of common stock. Net tangible book value per share is determined by
dividing our tangible net worth, or tangible assets less total liabilities, by
the total number of outstanding shares of common stock. After giving effect to
the sale of common stock offered by this prospectus and the receipt of the
estimated net proceeds, after deducting underwriting discounts and commissions
and estimated offering expenses, our net tangible book value at June 30, 2000
would have been $12.08 per share. This represents an immediate increase in the
net tangible book value of $3.01 per share to existing stockholders and an
immediate and substantial dilution, resulting from the difference between the
public offering price and the net tangible book value after this offering, to
new investors purchasing common stock in this offering. The following table
illustrates the per share dilution to new investors purchasing common stock in
this offering:

<TABLE>
<S> <C> <C>
Assumed public offering price per share.......................... $26.25
Net tangible book value per share at June 30, 2000............. 9.07
Increase per share attributable to new investors............... 3.01
----
Net tangible book value per share after this offering............ 12.08
------
Dilution per share to new investors.............................. $14.17
======
</TABLE>

This table excludes all shares of common stock issuable on exercise of
options that will remain outstanding on completion of this offering. The
exercise of outstanding options with an exercise price less than the net
tangible book value per share after this offering would increase the dilutive
effect to new investors described above. Please read notes 5 and 6 of the notes
to our consolidated financial statements.

21
<PAGE>

CAPITALIZATION

The following table presents our capitalization and other information as of
June 30, 2000 on two bases:

. on an actual basis; and

. on an as adjusted basis to reflect our anticipated use of the estimated
net proceeds of this offering.

You should read the table in conjunction with "Use of Proceeds,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and our consolidated financial statements included in this
prospectus.

<TABLE>
<CAPTION>
June 30, 2000
---------------------
Actual As Adjusted
-------- -----------
(in thousands)
<S> <C> <C>
Cash and cash equivalents................................ $ 1,392 $110,511
======== ========
Short-term debt.......................................... $ 12,000 $ --

Stockholders' equity:
Preferred stock, $0.01 par value, 10,000,000 shares
authorized; no shares issued and outstanding, actual; no
shares issued and outstanding, as adjusted.............. -- --
Common stock, $0.01 par value, 50,000,000 shares
authorized; 20,597,035 shares issued and 20,575,675
shares outstanding, actual; 25,497,035 shares issued and
25,475,675 shares outstanding, as adjusted.............. 206 255
Additional paid-in capital............................... 205,151 326,221
Accumulated deficit...................................... (18,709) (18,709)
Less: Treasury stock, at cost, 21,360 shares............. (53) (53)
-------- --------
Total stockholders' equity............................. 186,595 307,714
-------- --------
Total capitalization................................. $198,595 $307,714
======== ========
</TABLE>

22
<PAGE>

SELECTED CONSOLIDATED FINANCIAL DATA

(in thousands, except per share data)

<TABLE>
<CAPTION>
Period from
Inception
(December 20, Six Months Ended
1996) through Year Ended December 31, June 30,
December 31, ---------------------------- ------------------
1996 1997 1998 1999 1999 2000
------------- -------- -------- -------- -------- --------
Statement of Operations
Data: (unaudited)
<S> <C> <C> <C> <C> <C> <C>
Revenues................ $ -- $ 201 $ 3,298 $ 34,258 $ 9,583 $ 33,012
------ -------- -------- -------- -------- --------
Expenses:
Lease operating
expenses.............. -- 72 474 5,411 1,183 3,875
Depreciation,
depletion and
amortization--natural
gas and oil
properties............ -- 68 2,738 20,788 7,619 17,644
Depreciation and
amortization--other... 10 349 437 213 98 144
Write-down of natural
gas and oil
properties (1)........ -- -- 2,642 -- -- --
General and
administrative........ 318 1,965 3,809 4,860 2,244 3,100
Stock appreciation
rights expense (2).... -- -- -- 1,651 1,651 --
------ -------- -------- -------- -------- --------
Total expenses....... 328 2,454 10,100 32,923 12,795 24,763
------ -------- -------- -------- -------- --------
Income (loss) from
operations............. (328) (2,253) (6,802) 1,335 (3,212) 8,249
Other income (expense):
Interest income........ -- 91 221 528 85 313
Interest expense....... -- -- (516) (3,771) (2,007) (254)
Capitalized interest... -- -- 237 966 634 17
------ -------- -------- -------- -------- --------
Income (loss) before
income taxes........... (328) (2,162) (6,860) (942) (4,500) 8,325
Income tax provision... -- -- -- -- -- --
------ -------- -------- -------- -------- --------
Income (loss) before
cumulative effect of
change in accounting
principle.............. (328) (2,162) (6,860) (942) (4,500) 8,325
Cumulative effect of
change in accounting
principle (3).......... -- -- -- (395) (395) --
------ -------- -------- -------- -------- --------
Net income (loss)....... $ (328) $ (2,162) $ (6,860) $ (1,337) $ (4,895) $ 8,325
====== ======== ======== ======== ======== ========
Accrual of dividends on
preferred stock........ (16) (1,326) (7,094) (7,911) (5,088) --
------ -------- -------- -------- -------- --------
Net income (loss)
available to common
stockholders........... $ (344) $ (3,488) $(13,954) $ (9,248) $ (9,983) $ 8,325
====== ======== ======== ======== ======== ========
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) $ (2.33) $ 0.41
Cumulative effect of
change in accounting
principle (3)......... -- -- -- (0.05) (0.10) --
------ -------- -------- -------- -------- --------
Net income (loss) per
common share.......... $(0.09) $ (0.88) $ (3.44) $ (1.11) $ (2.43) $ 0.41
====== ======== ======== ======== ======== ========
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) $ (2.33) $ 0.39
Cumulative effect of
change in accounting
principle (3)......... -- -- -- (0.05) (0.10) --
------ -------- -------- -------- -------- --------
Net income (loss) per
common share.......... $(0.09) $ (0.88) $ (3.44) $ (1.11) $ (2.43) $ 0.39
====== ======== ======== ======== ======== ========
Weighted average number
of common shares
outstanding--basic
(4)(5)................. 3,960 3,960 4,059 8,355 4,113 20,469
====== ======== ======== ======== ======== ========
Weighted average number
of common shares
outstanding--diluted
(4)(5)................. 3,960 3,960 4,059 8,355 4,113 21,539
====== ======== ======== ======== ======== ========
Other Data:
Adjusted EBITDA (6)..... $ (318) $ (1,836) $ (985) $ 23,987 $ 6,156 $ 26,037
Net cash provided by
(used in) operating
activities............. (12) (5,523) (2,776) 14,905 4,508 22,668
Net cash used in
investing activities... -- (15,236) (68,503) (85,101) (47,673) (54,839)
Net cash provided by
financing activities... 4,590 18,863 70,738 88,507 45,000 13,111
Capital expenditures.... -- 15,578 85,681 79,810 33,575 68,237
</TABLE>

23
<PAGE>

<TABLE>
<CAPTION>
At December 31, At June 30,
----------------------------- ---------------
1996 1997 1998 1999 1999 2000
------ ------ ------- ------- ------- -------
(unaudited)
<S> <C> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash and cash equivalents........ $4,578 $2,682 $ 2,141 $20,452 $ 3,976 $ 1,392
Current assets................... 4,588 6,348 6,737 32,126 15,156 20,726
Total assets..................... 5,241 22,358 102,769 189,553 139,552 227,220
Short-term debt.................. -- -- 19,000 -- 64,000 12,000
Other current liabilities........ 1,858 2,096 18,378 12,451 10,005 28,625
Total equity(5).................. 3,367 18,879 56,913 177,102 51,981 186,595
</TABLE>
--------
(1) At December 31, 1998, we 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 Securities and Exchange
Commission rules, in calculating the amount of the write-down, we 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
we had used only December 31, 1998 natural gas and oil prices, we would
have recognized a total non-cash write-down of natural gas and oil
properties of approximately $13.0 million.

(3) The cumulative effect of change in accounting principle represents our
adoption of Statement of Position 98-5 "Reporting on the Costs of Start-Up
Activities."

24
<PAGE>

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

Spinnaker is an independent energy company engaged in the exploration,
development and production of natural gas and oil in the Gulf of Mexico. Since
our inception in December 1996, we have focused our efforts on 3-D seismic
exploration in the Gulf of Mexico and have participated in drilling 47
exploratory wells in the Gulf of Mexico, with 28 of these wells being completed
as discoveries. As of June 30, 2000, Ryder Scott Company, L.P. estimated our
net proved reserves at approximately 123.1 Bcfe, 89 percent of which was
natural gas, representing an increase of approximately 129 percent over our
estimated net proved reserves of 53.8 Bcfe at December 31, 1998. As of June 30,
2000, we had 173 leasehold interests located in Texas state and federal waters,
within which we have identified approximately 86 exploratory prospects or
leads. We expect to drill approximately 15 or more of these prospects during
the remainder of 2000. Based on 3-D seismic analysis on blocks where we
currently have no leasehold interest, we also have identified over 100
additional leads that may result in additional prospects. We have acquired our
portfolio through lease sales, farm-ins and trades, some of which involved
acreage swaps, and others based on 3-D seismic data. Our future operating
results will depend substantially on the success of our exploratory drilling
program.

Our revenue, profitability and future growth rate substantially depend on
factors beyond our control, such as economic, political and regulatory
developments and competition from other sources of energy. The energy markets
historically have been very volatile, and natural gas and oil prices may
fluctuate widely in the future. Sustained periods of low prices for natural gas
and oil could materially and adversely affect our financial position, our
results of operations, the quantities of natural gas and oil reserves that we
can economically produce and our access to capital.

We use the full cost method of accounting for our investment in natural gas
and oil properties. Under this method, we capitalize all acquisition,
exploration and development costs incurred for the purpose of finding natural
gas and oil reserves, including salaries, benefits, related general and
administrative costs and other amounts directly attributable to these
exploration activities. We capitalized general and administrative costs and
other amounts of $1.3 million in 1997, $2.5 million in 1998, $2.5 million in
1999 and $2.2 million in the first six months of 2000. We expense costs
associated with production and general corporate activities in the period
incurred. We capitalize interest costs related to unproved properties and
properties under development. Sales of natural gas and oil properties 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.

We compute the provision for depreciation, depletion and amortization of
natural gas and oil properties using the unit-of-production method of
accounting based on production and estimates of proved reserve quantities. We
exclude unevaluated costs and related carrying costs from the amortization base
until we evaluate the properties associated with these costs. We periodically
assess the unamortized costs for possible impairments or reductions in value.
An impairment to our value may occur in the event of:

. decreases in natural gas and oil prices;

. downward adjustments to our estimated proved reserves;

. increases in our estimates of development costs; and

. deterioration in our exploration results.

If a reduction in value has occurred, we increase our amortization base by
the amount of this impairment. The amortization base includes estimated future
development costs and dismantlement, and restoration and abandonment costs, net
of estimated salvage values. The capitalized costs of proved natural gas and
oil properties, net of accumulated depreciation, depletion and amortization,
may not exceed a ceiling limit that is

25
<PAGE>

based on the estimated future net cash flows from proved natural gas and oil
reserves discounted at 10 percent per annum. If capitalized costs exceed this
limit, we charge the excess to write-down of natural gas and oil properties in
the quarter in which the excess occurs. We may not reverse these write-downs
even if natural gas and oil prices increase in subsequent periods. At December
31, 1998, we 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 Securities and Exchange Commission rules, in calculating the
amount of the write-down, we 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 we had used only December 31, 1998
natural gas and oil prices, we would have recognized a total non-cash write-
down of natural gas and oil properties of approximately $13.0 million.

We conduct substantially all of our exploration activities jointly with
others and, accordingly, recorded amounts for our natural gas and oil
properties reflect only our proportionate interest in those activities.

Effective January 1998, we completed the conversion of Spinnaker from a
limited liability company to a corporation and now account for income taxes in
accordance with Statement on Financial Accounting Standards No. 109,
"Accounting for Income Taxes." Under Statement No. 109, we must recognize
deferred income taxes 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.
We will establish valuation allowances when necessary to reduce deferred tax
assets to the amount to be realized.

Results of Operations

Six Months Ended June 30, 2000 as Compared to the Six Months Ended June 30,
1999

Our production increased approximately 6.3 Bcfe in the first six months of
2000 compared to the first six months of 1999. The daily production rate at the
end of June 2000 was approximately 74,000 Mcfe as compared to rates of
approximately 35,000 Mcfe at the end of June 1999 and approximately 53,000 Mcfe
at the end of December 1999.

Our natural gas and oil revenues, including the effects of our hedging
activities, increased $23.4 million and income from operations increased $11.5
million in the first six months of 2000 compared to the same period in 1999.
Natural gas revenues increased $23.8 million and oil and condensate revenues
increased $2.0 million in the first six months of 2000 compared to the same
period in 1999. We entered into hedging arrangements beginning in the fourth
quarter of 1999. Net natural gas and oil hedging losses were $2.4 million in
the first six months of 2000. Natural gas production volumes increased
primarily due to eight wells which commenced production after the second
quarter of 1999, contributing $18.8 million of the increase in natural gas
revenues. Average natural gas prices increased, contributing $5.0 million of
the increase in natural gas revenues. Oil and condensate production volumes
increased primarily due to seven wells which commenced production after the
second quarter of 1999, contributing $1.2 million of the increase in oil and
condensate revenues. Average oil and condensate prices increased, contributing
$872,000 of the increase in oil and condensate revenues.

Lease operating expenses increased $2.7 million in the first six months of
2000 compared to the same period in 1999. Of the total increase in lease
operating expenses, $803,000 was attributable to eight wells which commenced
production after the second quarter of 1999, $879,000 related to workover
activities on four wells in 2000 and $1.0 million was primarily attributable to
the timing of production associated with new wells during the first six months
of 1999. The increase in the lease operating expense rate per Mcfe was
primarily due to the workover activities in the first six months of 2000.

General and administrative expenses increased $856,000 in the first six
months of 2000 compared to the same period in 1999. The increase was primarily
due to employment-related costs associated with an increase in personnel after
the second quarter of 1999.

26
<PAGE>

Depreciation, depletion and amortization increased $10.1 million in the
first six months of 2000 compared to the same period in 1999. Of the total
increase in depreciation, depletion and amortization, $10.6 million was
attributable to a substantial increase in production, partially offset by a
reduction of $553,000 in the depletion rate from the prior year period.

Interest income increased $228,000 in the first six months of 2000 compared
to the same period in 1999 primarily due to investment income associated with
the remaining initial public offering proceeds invested during the first half
of 2000. Interest expense, net of capitalized interest, decreased $1.1 million
in the first six months of 2000 compared to the same period in 1999. We had
outstanding borrowings of $12.0 million at June 30, 2000 compared to
outstanding borrowings of $64.0 million at June 30, 1999.

No income tax expense was recognized during the first six months of 2000 due
to the availability of net operating loss carryforwards that offset taxable
income in 2000.

We recognized net income of $8.3 million, or $0.41 per basic share and $0.39
per diluted share, in the first six months of 2000 compared to a net loss of
$4.9 million in the same period in 1999. After dividends of $5.1 million on
preferred stock that is no longer outstanding, we recognized a net loss
available to common stockholders of $10.0 million, or a loss of $2.43 per basic
and diluted share, in the first six months of 1999.

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

Our 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.

Our 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 which 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 of natural gas per day on November 2, 1999.
However, on November 15, 1999, the operator reported to us that during a
shutdown of the well, it detected a pressure buildup in the production casing.
The well has been plugged and abandoned and the operator plans to drill a
replacement well in the second half of 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 which commenced production in 1999, including $1.6 million of
expense related to workovers at Garden Banks 367 (Dulcimer) and High Island 235
and well control activities at Brazos A-19. We expensed $225,000 related to
Brazos A-19 well control activities during the fourth quarter of 1999.
Diagnostic and other costs to bring the well back onto production will be
capitalized.

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
Spinnaker's officers provided that they could elect to have us 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 our estimate of
the share value of Spinnaker, 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.

27
<PAGE>

Depreciation, depletion and amortization increased $18.1 million in 1999
compared to 1998, primarily due to a substantial increase in production during
1999.

Interest income increased $307,000 in 1999 compared to 1998 primarily due to
invested initial public offering proceeds during the fourth quarter of 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.

We 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, we recognized
a net loss available to common stockholders of $9.2 million, or $1.11 per basic
and diluted share, in 1999. After preferred dividends of $7.1 million, we
recognized a net loss available to common stockholders of $14.0 million, or
$3.44 per basic and diluted share, in 1998.

Year Ended December 31, 1998 as Compared to the Year Ended December 31, 1997

We had natural gas and oil revenues of $3.3 million for the year ended
December 31, 1998 as compared to $201,000 for the year ended December 31, 1997.
This increase in natural gas and oil revenues was due primarily to production
commencing in 1998 from wells located at West Cameron 522 and South Timbalier
220. Primarily as a result of these wells, production substantially increased
to 1,747 MMcfe in 1998 from 70 MMcfe in 1997. This increased production more
than offset the decrease in the average price of the natural gas production to
$1.89 per Mcf for 1998 from $2.87 per Mcf for 1997.

Lease operating expenses were $474,000 in 1998 as compared to $72,000 in
1997. The increase in lease operating expenses was primarily the result of
operating expenses attributable to properties that commenced production during
the second half of 1997 and during 1998.

General and administrative expenses were $3.8 million in 1998 as compared to
$2.0 million in 1997. The increase in general and administrative expenses was
primarily due to an increase of $1.2 million in expenses related to personnel
during the latter part of 1997 and during 1998 and to an increase of $300,000
primarily related to legal and accounting services associated with the
conversion of Spinnaker from a limited liability company to a corporation.

Depreciation, depletion and amortization in 1998 was $2.7 million as
compared to $68,000 in 1997. Of the $2.6 million increase, $1.6 million was
attributable to a substantial increase in production and $1.0 million was due
to an increase in the unit depletion rate during 1998. Depreciation and
amortization-other increased to $437,000 in 1998 from $349,000 in 1997. The
increase was attributable to the purchase of additional computer hardware and
software.

We recognized a non-cash write-down of natural gas and oil properties of
$2.6 million due to a decline in prices during 1998 and through April 9, 1999.

We recognized a net loss of $6.9 million in 1998 compared to a net loss of
$2.2 million in 1997. After preferred dividends of $7.1 million, we recognized
a net loss available to common stockholders of $14.0 million, or $3.44 per
basic and diluted share, in 1998. After preferred dividends of $1.3 million, we
recognized a net loss available to common stockholders of $3.5 million, or
$0.88 per basic and diluted share, in 1997.

Liquidity and Capital Resources

We have experienced and expect to continue to experience substantial working
capital requirements, primarily due to our active exploration and development
programs. While we believe that the proceeds of this offering, working capital,
cash flows from operations and borrowings under our credit facility will be
sufficient to meet our capital requirements through the end of 2001, additional
financing may be required in the future to fund our growth and exploration and
development programs. In the event additional capital resources are
unavailable, we may curtail our drilling, development and other activities or
be forced to sell some of our assets on an untimely or unfavorable basis.

28
<PAGE>

Cash and cash equivalents decreased $19.1 million to $1.4 million at June
30, 2000 from $20.5 million at December 31, 1999. The decrease resulted from
$54.8 million used in investing activities, offset in part by $22.6 million
provided by operating activities and $13.1 million provided by financing
activities.

Operating Activities

We intend to use cash flows from operations to fund a portion of our future
acquisition, exploration and development activities. Net cash of $22.6 million
was provided by operating activities in the first six months of 2000, primarily
as a result of a substantial increase in natural gas and oil production and
prices.

Cash flow from operations will depend on our ability to increase production
through our exploration and development programs and the prices of natural gas
and oil. We have made significant investments to expand our operations in the
Gulf of Mexico. These investments have resulted in an increase in our daily
production to approximately 74,000 Mcfe at the end of June 2000 from
approximately 53,000 Mcfe at the end of December 1999. We expect higher
production and cash flow during the remainder of 2000 as recent discoveries
commence production. However, we cannot assure you that production volumes and
pricing in the remainder of 2000 will achieve our expectations.

We currently sell most of our natural gas and oil production under price
sensitive or market price contracts. To reduce exposure to fluctuations in
natural gas and oil prices, we enter into hedging arrangements. However, these
contracts also limit the benefits we would realize if prices increase. See "--
Quantitative and Qualitative Disclosures About Market Risk."

Our cash flow from operations also depends on our ability to manage our
working capital, including our accounts receivable and payable as well as our
accrued liabilities. The increase in "accounts receivable" was primarily due to
a $6.3 million increase in accrued natural gas and oil revenues resulting
primarily from an increase in production and prices in June 2000 compared to
December 1999 and a $3.1 million increase in joint interest billings associated
with additional wells operated by Spinnaker, offset in part by receipts and
other activity of $1.2 million. The increases in "accounts payable" and
"accrued liabilities" were primarily due to costs associated with increased
drilling and development activities during the first six months of 2000.

Investing Activities

Net cash of $54.8 million used in investing activities in the first six
months of 2000 included net oil and gas property capital expenditures of $55.2
million and purchases of other property and equipment of $989,000. In addition,
we received net proceeds of $1.4 million from the sale of a pipeline associated
with our South Timbalier 219/211 discoveries. We drilled 12 exploratory wells
in the first six months of 2000, six of which were successful. In 1999, we
drilled 12 exploratory wells, eight of which were successful.

The 2000 budget includes development costs that are contingent on the
success of future exploratory drilling. We do not anticipate that budgeted
leasehold acquisition activities will include the acquisition of producing
properties. We do not anticipate any significant abandonment or dismantlement
costs through 2000. We have capital expenditure plans for the second half of
2000 totaling approximately $82 million, primarily for costs related to our
exploration and development programs. Actual levels of capital expenditures may
vary significantly due to many factors, including drilling results, natural gas
and oil prices, industry conditions, decisions of operators and other prospect
owners and the prices of drilling rig dayrates and other oilfield goods and
services.

Financing Activities

During the first six months of 2000, we received proceeds from borrowings of
$12.0 million and cash of $1.1 million related to proceeds from exercises of
stock options.

In September 1998, we entered into an $85.0 million credit agreement. We
received $19.0 million and $53.0 million from borrowings under the credit
agreement during 1998 and 1999, respectively. Simultaneously

29
<PAGE>

with the completion of our initial public offering, we retired all outstanding
borrowings under the credit agreement, which were $72.0 million as of October
4, 1999. On October 29, 1999, we amended and restated the credit agreement to
provide for a $25.0 million credit facility.

On July 20, 2000, we amended and restated the credit agreement for a second
time. Our second amended and restated credit agreement with TD Securities (USA)
Inc. and Credit Suisse First Boston provides us with a $75.0 million credit
facility with an initial borrowing base of $40.0 million and an original term
of 364 days. Credit Suisse First Boston is an affiliate of one of the
underwriters in this offering. On July 20, 2000, we used available borrowings
under our second amended and restated credit agreement to repay all outstanding
indebtedness under our first amended and restated credit agreement.
Simultaneously with the completion of this offering, we will repay all
outstanding borrowings under the second amended and restated credit agreement,
which were $17.0 million as of August 10, 2000.

The second amended and restated credit agreement is secured by substantially
all of our assets, including our interests in our natural gas and oil
properties. We have 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 percentage of our borrowing base used at that time. The base interest rate
under the second amended and restated credit agreement 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 agreement contains covenants and restrictive provisions,
including the following limitations, subject to some exceptions:

. we may not incur any other indebtedness from borrowings other than
indebtedness of up to $1.0 million;

. we may not incur any liens upon our properties or assets other than
permitted liens securing indebtedness of up to $1.0 million and other
liens in the ordinary course of business;

. we may not enter into any amalgamation, demerger or merger;

. we may not dispose of all or substantially all of our property, business
or assets;

. we may not dispose of any properties valued in the borrowing base except
some interests in natural gas and oil properties included in the
borrowing base in an aggregate amount not to exceed $500,000;

. we may not make or pay any dividend, distribution or payment in respect
of our capital stock nor purchase, redeem, retire or permit any reduction
or retirement of our capital stock;

. we must maintain the ratio of our consolidated current assets as of the
end of each fiscal quarter to our consolidated current liabilities other
than debt under the credit agreement as of the end of such fiscal quarter
so that it is not less than 1.00 to 1.00;

. we must ensure that the ratio of EBITDAX, as defined, to our consolidated
interest expense is not less than 5.0 to 1.0 for any period of four
consecutive fiscal quarters (to be annualized for periods ending on or
subsequent to June 30, 2001); and

. we may not enter into any hedging agreement unless we meet specified
requirements including limits on the aggregate amounts maturing in any
month under any floor hedging contracts and under any forward sales
transactions, and at no time can any hedging agreement of any nature
contain a term to put up money or other assets against the event of its
nonperformance exceeding $5.0 million in the aggregate.

Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

We are exposed to changes in interest rates. Changes in interest rates
affect the interest earned on our cash and cash equivalents and the interest
rate paid on borrowings under the credit agreements. Under our current
policies, we do not use interest rate derivative instruments to manage exposure
to interest rate changes.

30
<PAGE>

Commodity Price Risk

Our 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 our ability to borrow and
raise additional capital. The amount we can borrow under the second amended and
restated credit agreement 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 we can economically produce. We currently
sell most of our 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, we entered into hedging
arrangements beginning in the fourth quarter of 1999. However, these contracts
also limit the benefits we would realize if prices increase. These financial
arrangements take the form of costless collars and are placed with major
financial institutions we believe represent minimum credit risks.

Under our current hedging practice, we do not hedge more than 50 percent of
our production quantities without the prior approval of our risk management
committee. Our daily production rates at the end of June 2000 were
approximately 70,000 Mcf of natural gas and approximately 700 barrels of oil
and condensate. We have entered into the following collar arrangements. One
MMBtu approximates one Mcf of gas.

<TABLE>
<CAPTION>
Gas Collars Oil Collars
------------------------------- ---------------------------
Average Average Average Average Average
Daily Average NYMEX Daily NYMEX NYMEX
Volume NYMEX Floor Ceiling Volume Floor Ceiling
Time Period (MMBtu) Price/MMBtu Price/MMBtu (Bbl) Price/Bbl Price/Bbl
----------- ------- ----------- ----------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Second Quarter 2000..... 41,758 $2.57 $2.86 600 $19.37 $21.78
Third Quarter 2000...... 50,000 2.63 2.96 600 18.61 21.03
Fourth Quarter 2000..... 50,000 2.95 3.43 600 22.11 25.15
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(1).. 50,000 3.00 4.72 -- -- --
</TABLE>
--------
(1) Collar arrangements through November 30, 2001.

We settle collar arrangements based on the average of the reported
settlement prices on the NYMEX for the last three trading days for natural gas
and the average of the daily reported settlement prices on the NYMEX for the
entire trading month for oil. In a collar transaction, the counterparty is
required to make a payment to us if the settlement price for any settlement
period is below the floor price for the transaction, and we are 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. We
recognized net hedging losses of $2.4 million during the first six months of
2000. The estimated fair value of our open collar arrangements as of June 30,
2000 is equal to an unrealized loss of approximately $12.5 million for the last
six months of 2000 and an unrealized loss of approximately $3.8 million in 2001
using NYMEX natural gas and oil prices as of June 30, 2000.

31
<PAGE>

BUSINESS AND PROPERTIES

Overview

Since our inception, we have participated in drilling 47 exploratory wells
in the Gulf of Mexico, with 28 of these wells being completed as discoveries.
As of June 30, 2000, Ryder Scott Company, L.P. estimated our net proved
reserves at approximately 123.1 Bcfe, 89 percent of which was natural gas,
representing an increase of approximately 129 percent over our estimated net
proved reserves of 53.8 Bcfe at December 31, 1998. Our daily production
increased to approximately 74,000 Mcfe at June 30, 2000 from approximately
8,000 Mcfe at December 31, 1998. Within our current inventory of leasehold
interests, we have identified approximately 86 exploratory prospects or leads.
We expect to drill approximately 15 or more of these prospects during the
remainder of 2000. Based on 3-D seismic analysis on blocks where we currently
have no leasehold interest, we also have identified over 100 additional leads
that may result in additional prospects. Our capital expenditure budget for
2000 includes approximately $150.0 million for exploration, development,
leasehold acquisitions and other capital expenditures, of which we incurred
$68.2 million through June 30, 2000.

Our Strategy

Our goals are to expand our reserve base, cash flow and net income and to
generate an attractive return on capital. We emphasize the following elements
in our 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. We have assembled a large 3-D seismic database
and focus our exploration activities in the Gulf of Mexico because we believe
this area represents one of the most attractive exploration regions in North
America. The Gulf of Mexico has the following characteristics which make it
attractive to exploration and production companies:

. Prolific exploration and production history

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<PAGE>

. Open access to acreage

. Substantial existing oilfield service infrastructure

. Attractive taxation and royalty rates

. Relatively high-productivity wells

. Geographic proximity to well-developed markets for natural gas and oil

. Geologic diversity that offers a variety of exploration opportunities

We also believe our geographic focus provides us with an excellent
opportunity to develop and maintain competitive advantages through the
combination of our 3-D seismic database, regional exploration and operating
expertise, and joint venture relationships.

Sustain a balanced, diversified exploration effort. We believe that our
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.

We have used joint ventures to help diversify our exploration activities.
Our 3-D seismic data's broad coverage of the Gulf of Mexico allows us to
participate in a variety of geologically diverse exploration opportunities and
create a diversified prospect portfolio. We intend to manage our 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 we believe 3-D seismic analysis provides attractive risk/reward benefits.
We also strive to diversify our exploration efforts by seeking to limit the
budgeted amount of our leasehold acquisition and drilling cost of the first
exploratory well on any one prospect to less than 10 percent of our annual
capital budget.

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<PAGE>

continuous exploration program, we 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.

Petroleum Geo-Services Data Agreement

Data Covered by the Agreement

Subject to the exceptions discussed below, we are entitled to receive and
use all of Petroleum Geo-Services' standard and enhanced multi-client 3-D
seismic data covering the Gulf of Mexico including its bays, channels,
tributaries, estuaries and transition zones that Petroleum Geo-Services
acquires or processes for itself prior to March 31, 2002 or is in the process
of acquiring or processing as of that date. However, Petroleum Geo-Services is
not obligated under our agreement to acquire any further data of any kind. At
this time, Petroleum Geo-Services has elected to cease 3-D seismic data
acquisitions in the Gulf of Mexico. Even if Petroleum Geo-Services elects to
resume 3-D seismic data acquisitions in the Gulf of Mexico, it again could
elect to cease 3-D seismic data acquisitions as a result of a change of control
of Petroleum Geo-Services or changes in Petroleum Geo-Services' competitive,
financial or technological status. We are also entitled to enhanced data
processed by third parties if Petroleum Geo-Services retains a material royalty
or similar interest in that data.

As part of its business activities, Petroleum Geo-Services acquires both
proprietary and multi-client marine seismic data. When Petroleum Geo-Services
acquires proprietary data, it does so on an exclusive contractual basis for its
customers. In this case, Petroleum Geo-Services simply provides acquisition
services. When Petroleum Geo-Services 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. We are entitled to receive only multi-client
data from Petroleum Geo-Services.

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
Petroleum Geo-Services' 3-D seismic survey customers. Enhanced data is data
created through additional computer processing of Petroleum Geo-Services'
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. We currently have license rights to approximately
4,400 blocks of standard data and 1,300 blocks of enhanced data under our
Petroleum Geo-Services agreement.

Petroleum Geo-Services 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. We are entitled
to select for our use up to 60 blocks of multi-component data that Petroleum
Geo-Services acquires, if any, prior to March 31, 2002 or is in the process of
acquiring as of that date. We 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.

Petroleum Geo-Services markets Gulf of Mexico seismic data through seismic
data marketing vendors. We have entered into agreements with some of these
marketing vendors which modify, to some extent, our rights under our agreement
with Petroleum Geo-Services. Material modifications of our rights resulting
from these agreements are noted below. If Petroleum Geo-Services enters into a
marketing agreement with a new party, then Petroleum Geo-Services has agreed to
use good faith efforts to obtain the consent of the new party to our rights
under our agreement with Petroleum Geo-Services. If Petroleum Geo-Services does
not obtain the consent of this new party, however, then we may not be entitled
to the future data of Petroleum Geo-Services that is marketed by that party. A
majority of the data we have received is subject to agreements with marketing
vendors.

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<PAGE>

Rights to Use the Data

We may use the data received under our agreement as follows:

. for our 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 our 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 our 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 our premises and must be held in confidence by those
individuals.

Our agreement with Petroleum Geo-Services provides that our rights to use
data are perpetual subject to the termination provisions discussed below.
However, our related agreements with Petroleum Geo-Services' marketing vendors
provide that our rights terminate automatically after 25 years. The data we
receive under the Petroleum Geo-Services agreement remains the property of
Petroleum Geo-Services subject to the rights granted to us in the agreement.

Restrictions on Transfer and Assignment

We have the limited right to transfer a copy of standard or enhanced data to
a qualified transferee. A qualified transferee is a party with which we have
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 Petroleum Geo-Services 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. We may
transfer copies only up to an aggregate of 568.6 blocks. We must transfer
copies of data in groups of blocks that are contiguous on at least one side and
which include at least 20 blocks.

We may assign our rights under our agreement with Petroleum Geo-Services,
directly or by merger, to a successor to all or substantially all of our
business or assets or the business or assets of Spinnaker Exploration Company,
L.L.C., our principal subsidiary, as long as the successor is not a Petroleum
Geo-Services competitor. A Petroleum Geo-Services 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 our business
or assets is not a Petroleum Geo-Services major customer, then that successor
may in turn transfer the rights under our agreement with Petroleum Geo-Services
to a successor of all of its business or assets as long as that successor is
not a Petroleum Geo-Services competitor. A Petroleum Geo-Services major
customer is a customer that has purchased from Petroleum Geo-Services products
and services at least equal to 7.5 percent of Petroleum Geo-Services' prior 12
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 agreement by us or our successors are permitted. In addition, one of
our agreements with a Petroleum Geo-Services marketing vendor provides that we
may not assign our rights to Petroleum Geo-Services data marketed by that
vendor without the consent of that vendor.

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Termination Events

Petroleum Geo-Services may terminate substantially all of our rights under
the agreement by giving us notice after any of the following events:

. we transfer data or our rights under the agreement in violation of the
agreement;

. a Petroleum Geo-Services competitor acquires control of us or our
principal subsidiary;

. a Petroleum Geo-Services major customer acquires control of us or our
principal subsidiary after another Petroleum Geo-Services major customer
has previously acquired control of us or our principal subsidiary;

. we knowingly breach one of the provisions of the agreement relating to
the use, transfer or disclosure of the data and the breach results in
significant damages to Petroleum Geo-Services;

. we unknowingly breach one of these provisions of the agreement, the
breach results in significant damages to Petroleum Geo-Services and we
fail to diligently prevent a subsequent breach after we receive notice of
the breach;

. we commit a material breach of one of the other provisions of the
agreement and fail to remedy the breach within 90 days after notice to
us; or

. we commence a voluntary bankruptcy or similar proceeding or an
involuntary bankruptcy or similar proceeding is commenced against us and
remains undismissed for 30 days.

Non-Compete

Petroleum Geo-Services has agreed that it will not disclose data covering
the majority of the blocks in any survey in the Gulf of Mexico that is marketed
by Petroleum Geo-Services 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 our data agreement with Petroleum Geo-Services, we have 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., a subsidiary of
Petroleum Geo-Services.

We have agreed to purchase $2.0 million of seismic-related services from
Petroleum Geo-Services prior to December 31, 2002. We paid to Petroleum Geo-
Services approximately $59,000 in 1997, $122,000 in 1998, $318,000 in 1999 and
$138,000 in the first six months of 2000 for seismic-related services.

Limitation of Liability

The aggregate liability of Petroleum Geo-Services under the agreement for
all claims made by us is limited to $45.0 million. Our liability for claims
made against us by Petroleum Geo-Services under the 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-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

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<PAGE>

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.

We have invested extensively in the advanced computer hardware and software
necessary for 3-D seismic exploration. We currently have 18 workstations in-
house to analyze seismic data. Our 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, we
have invested in direct-link telecommunications technology that provides us
with disk-to-disk downloading of data volumes directly from Petroleum Geo-
Services that allows very rapid loading on our in-house storage. This
capability has benefited us when new data sets are made available only a short
time prior to state and federal lease sales.

Exploration Activities

Significant Exploration Discoveries

The following table summarizes the most significant of our 28 exploration
discoveries since our inception.

High Island 202. High Island 202 is located approximately 35 miles off the
Texas coast. The #1 exploratory well was drilled to a total measured depth of
13,500 feet in November 1999 and encountered 122 net feet of pay. The #2
exploratory well was drilled to a total measured depth of 15,700 feet in
February 2000 and encountered 149 net feet of pay. The #4 exploratory well was
drilled to a total measured depth of 8,200 feet in June 2000 and encountered
48 net feet of pay. The #3 exploratory well is currently drilling.

South Timbalier 219/211. South Timbalier 219 is located approximately 50
miles off the Louisiana coast. The discovery well was drilled to a total
measured depth of 10,800 feet in August 1999 and encountered 76 net feet of
pay. The South Timbalier 211 discovery well was drilled to a total measured
depth of 10,300 feet in September 1999 and encountered 56 net feet of pay.

North Padre Island 883. North Padre Island 883 is located approximately 45
miles off the Texas coast. The #1 exploratory well was drilled to a total
measured depth of 11,600 feet in January 2000 and encountered 29 net feet of
pay. The #2 exploratory well was drilled to a total measured depth of 13,000
feet in March 2000 and encountered 66 net feet of pay. We plan to drill a
development well during the second half of 2000.

Brazos A-19. Brazos A-19 is located approximately 32 miles off the Texas
coast. The discovery well was drilled to a total measured depth of 18,800 feet
in May 1998 and encountered 150 net feet of pay. The well commenced production
in October 1999; however, the operator reported to us that during a shutdown
of the well, it detected a pressure buildup in the production casing. The well
has been plugged and abandoned and the operator plans to drill a replacement
well in the second half of 2001.

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<PAGE>

High Island A-18. High Island A-18 is located approximately 40 miles off the
Texas coast. The discovery well was drilled to a total measured depth of 8,600
feet in July 2000 and encountered 39 net feet of pay.

Garden Banks 367 (Dulcimer). Dulcimer is located approximately 159 miles off
the Louisiana coast. The discovery well was drilled to a total measured depth
of 11,400 feet in February 1998 and encountered 124 net feet of pay. In May
2000, Dulcimer began to produce lower gas rates in conjunction with the onset
of reservoir-related water production. The well had been producing
approximately 43 million cubic feet of gas per day after cumulative production
of approximately 19 billion cubic feet of natural gas equivalent. The well
continues to produce additional natural gas volumes at lower rates. Other
possibilities exist for the project, including production of additional
reserves in the existing well bore as well as sidetracking the well to an updip
location in this fault block. An additional exploratory target has previously
been defined on the block that, if drilled successfully, would benefit from the
existing infrastructure.

Mississippi Canyon 496 (Zia). Zia is located approximately 33 miles off the
Louisiana coast. The discovery well was drilled to a total measured depth of
21,800 feet in November 1998 and encountered 217 net feet of pay. A second well
is planned during the second half of 2001.

Planned Exploration Prospects

We expect to drill approximately 15 or more exploration prospects during the
remainder of 2000. We have analyzed 3-D seismic data covering each of these
prospects. We continue to review and interpret data covering these prospects
and believe that many of the prospects have the potential for additional drill
sites. We operate several of these prospects. We typically have participated in
prospects with industry partners to share the up-front costs associated with
our exploration activities, to mitigate our exploration risk and to increase
the number of prospects in which we can participate.

Although we expect to drill these prospects, there can be no assurance that
these wells will be drilled at all or within the expected time frame. Please
read "Risk Factors" for a discussion of some factors that may affect the timing
of drilling.

Natural Gas and Oil Reserves

The following table presents our estimated net proved natural gas and oil
reserves and the net present value of our reserves at June 30, 2000 based on a
reserve report prepared by Ryder Scott Company, L.P. Appendix A to this
prospectus contains a letter prepared by Ryder Scott Company, L.P. summarizing
the reserve report. The present values, discounted at 10 percent per annum, of
estimated 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.

The present value of future net cash flows as of June 30, 2000 was
determined by using prices of $4.55 per Mcf of natural gas and $32.72 per
barrel of oil, which represents market prices in effect at June 30, 2000 of
$4.37 per MMBtu of natural gas and $32.50 per barrel of oil, adjusted for
transportation and grade differences.

<TABLE>
<CAPTION>
Proved Reserves
-----------------------------
Developed Undeveloped Total
--------- ----------- -------
<S> <C> <C> <C>
Natural gas (MMcf)........................... 48,113 61,387 109,500
Oil and condensate (MBbls)................... 337 1,925 2,262
Total proved reserves (MMcfe)................ 50,131 72,939 123,070
Present value of future net cash flows
(before income taxes) discounted at 10%(1).. 166,665 210,051 376,716
Standardized measure of discounted future net
cash flows(1)............................... 134,226 169,167 303,393
</TABLE>
--------
(1) Includes unrealized losses of $16.3 million for the effects of our hedging
activities using natural gas and oil prices in effect at June 30, 2000.

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<PAGE>

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

Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves most likely will vary from our estimates. Any
significant variance could materially affect the estimated quantities and net
present value of reserves shown in this prospectus. In addition, we 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 our control. At June 30, 2000, approximately
74 percent of our proved reserves were either undeveloped or non-producing.
Because most of our 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 June 30, 2000, approximately 59 percent of our proved reserves were
undeveloped. Recovery of undeveloped reserves generally requires significant
capital expenditures and successful drilling operations. The reserve data
assumes that we will make these expenditures. Although we estimate our 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
referred to in this prospectus is the current market value of our estimated
natural gas and oil reserves. In accordance with Securities and Exchange
Commission requirements, we base the estimated discounted future net cash flows
from proved reserves on prices and costs on the date of the estimate. Actual
future prices and costs may differ materially from those used in the present
value estimate.

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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 our sales of natural gas and oil for the periods indicated:

<TABLE>
<CAPTION>
Six Months
Year Ended Ended June
December 31, 30,
-------------------- -------------
1997 1998 1999 1999 2000
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Production:
Natural gas (MMcf)...................... 70 1,675 11,962 4,258 10,279
Oil and condensate (MBbls).............. -- 12 180 49 99
Total (MMcfe)......................... 70 1,747 13,044 4,552 10,872

Average sales price per unit:
Natural gas revenues from production
(per Mcf).............................. $ 2.87 $ 1.89 $ 2.49 $ 2.09 $ 3.18
Effects of hedging activities (per
Mcf)................................... -- -- 0.08 -- (0.17)
------ ------ ------ ------ ------
Average price......................... $ 2.87 $ 1.89 $ 2.57 $ 2.09 $ 3.01

Oil and condensate revenues from
production (per Bbl)................... $18.51 $11.61 $20.33 $14.70 $27.86
Effects of hedging activities (per
Bbl)................................... -- -- (0.57) -- (7.28)
------ ------ ------ ------ ------
Average price......................... $18.51 $11.61 $19.76 $14.70 $20.58

Total revenues from production (per
Mcfe).................................. $ 2.87 $ 1.89 $ 2.57 $ 2.11 $ 3.26
Effects of hedging activities (per
Mcfe).................................. -- -- 0.06 -- (0.22)
------ ------ ------ ------ ------
Total average price (per Mcfe)........ $ 2.87 $ 1.89 $ 2.63 $ 2.11 $ 3.04

Expenses (per Mcfe):
Lease operating expenses (1)............ $ 1.03 $ 0.27 $ 0.41 $ 0.26 $ 0.36
Depreciation, depletion and
amortization--natural gas and oil
properties............................. 0.97 1.57 1.59 1.67 1.62
</TABLE>
--------
(1) Lease operating expenses per Mcfe for the six months ended June 30, 2000
include approximately $0.08 per Mcfe associated with workovers on four
wells. Lease operating expenses per Mcfe for the year ended December 31,
1999 include approximately $0.13 per Mcfe associated with workovers on two
wells and well control activities on another well.

Development, Exploration and Acquisition Capital Expenditures

The following table presents information regarding our net costs incurred in
the purchase of proved and unproved properties and in exploration and
development activities:

<TABLE>
<CAPTION>
Six
Year Ended December 31, Months Ended
----------------------- June 30,
1997 1998 1999 2000
------- ------- ------- ------------
<S> <C> <C> <C> <C>
Property acquisition costs:
Unproved............................. $ 4,458 $15,791 $13,911 $ 8,527
Proved............................... -- -- -- --
Exploration costs (1).................. 7,116 46,620 45,152 34,514
Development costs (2).................. 2,422 23,067 23,614 23,357
------- ------- ------- -------
Total costs incurred............... $13,996 $85,478 $82,677 $66,398
======= ======= ======= =======
</TABLE>
--------
(1) Includes 3-D seismic data acquisitions of $1.4 million, $2.5 million and
$10.5 million in 1997, 1998 and 1999, respectively, and $803,000 for the
six months ended June 30, 2000.
(2) Includes costs of completions, platforms, facilities and pipelines
associated with exploratory wells.

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<PAGE>

Drilling Activity

The following table shows our drilling activity. In the table, "gross"
refers to the total wells in which we have a working interest and "net" refers
to gross wells multiplied by our working interest in such wells.

<TABLE>
<CAPTION>
Year Ended December 31, Six
----------------------------- Months Ended
1997 1998 1999 June 30, 2000
--------- --------- --------- --------------
Gross Net Gross Net Gross Net Gross Net
----- --- ----- --- ----- --- ------- ------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive.................... 4 1.5 9 2.9 8 4.6 6 3.9
Nonproductive................. -- -- 6 2.3 4 1.9 6 2.4
--- --- --- --- --- --- ------ ------
Total....................... 4 1.5 15 5.2 12 6.5 12 6.3
=== === === === === === ====== ======
Development Wells:
Productive.................... -- -- -- -- -- -- -- --
Nonproductive................. -- -- -- -- -- -- -- --
--- --- --- --- --- --- ------ ------
Total....................... -- -- -- -- -- -- -- --
=== === === === === === ====== ======
</TABLE>

Since June 30, 2000, we have drilled one gross (0.3 net) productive
exploratory well and three gross (1.4 net) nonproductive exploratory wells. We
are currently drilling three gross (1.9 net) exploratory wells.

Productive Wells

The following table sets forth the number of productive natural gas and oil
wells in which we owned an interest as of June 30, 2000:

<TABLE>
<CAPTION>
Total
Productive
Wells
----------
Gross Net
----- ----
<S> <C> <C>
Natural gas....................................................... 26 12.9
Oil............................................................... 1 0.1
--- ----
Total........................................................... 27 13.0
=== ====
</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 our developed and
undeveloped lease acreage as of June 30, 2000. Developed acreage refers to
acreage within producing units and undeveloped acreage refers to acreage that
has not been placed in producing units.

<TABLE>
<CAPTION>
Developed Undeveloped
Acreage Acreage Total
------------- --------------- ---------------
Gross Net Gross Net Gross Net
------ ------ ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Offshore Louisiana................ 34,687 15,733 365,172 162,707 399,859 178,440
Offshore Texas.................... 23,040 10,422 181,170 75,773 204,210 86,195
Texas State Waters................ 1,200 300 33,833 15,057 35,033 15,357
------ ------ ------- ------- ------- -------
Total........................... 58,927 26,455 580,175 253,537 639,102 279,992
====== ====== ======= ======= ======= =======
</TABLE>

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<PAGE>

Our 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.

Marketing

Most of our natural gas and oil production is sold under price sensitive or
market price contracts. Our revenues, profitability and future growth depend
substantially on prevailing prices for natural gas and oil. The price received
by us for our 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 our proved reserves and our revenues, profitability and cash
flow. Although we are not currently experiencing any significant involuntary
curtailment of our natural gas or oil production, market, economic and
regulatory factors may in the future materially affect our ability to sell our
natural gas or oil production. For the years ended December 31, 1997 and 1998,
sales to Cokinos Energy Corporation were 100 percent of our natural gas and oil
revenues, respectively. For the year ended December 31, 1999, sales to Columbia
Energy Services were 68 percent and sales to Cokinos Energy Corporation were 32
percent of our natural gas and oil revenues.

Currently, Enron North America Corp. purchases all of our natural gas
production at current market prices. The terms of our arrangement require Enron
to pay us within 60 days after we deliver our production to Enron. As a result,
if Enron were to default on its payment obligations to us, our near-term
earnings and cash flows would be adversely affected. However, due to the
availability of other markets and pipeline connections, we do not believe that
the loss of Enron or any other customer would adversely affect our ability to
market our production.

. 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 the actual prices received.

In addition, these hedging arrangements have limited and may continue to
limit the benefit we would receive from increases in the prices for natural gas
and oil. We cannot assure you that the hedging transactions we have entered
into, or will enter into, will adequately protect us from fluctuations in the
prices of natural gas and oil.

On the other hand, we may choose not to engage in hedging transactions in
the future. As a result, we may be more adversely affected by changes in
natural gas and oil prices than our competitors who engage in

42
<PAGE>

hedging transactions. For further information concerning our hedging
transactions, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Quantitative and Qualitative Disclosures
About Market Risk."

Competition

We compete with major and independent natural gas and oil companies for
property acquisitions. We also compete for the equipment and labor required to
operate and develop these properties. Most of our competitors have
substantially greater financial and other resources. As a result, in the deep
water where exploration is more expensive, our 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 we can, which would adversely
affect our 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 we can. Our ability to explore for natural gas and oil
prospects and to acquire additional properties in the future will depend upon
our ability to conduct operations, to evaluate and select suitable properties
and to consummate transactions in this highly competitive environment. In
addition, most of our competitors have been operating in the Gulf of Mexico for
a much longer time than we have 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. 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.

Our 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 Federal Energy Regulatory Commission 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 Federal Energy Regulatory Commission 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 our production and marketing activities, it does affect how
buyers and sellers gain access to the necessary transportation facilities and
how we and our 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 Federal Energy Regulatory Commission continues to review and
modify its regulations regarding the transportation of natural gas. For
example, the Federal Energy Regulatory Commission recently issued Order Nos.
637 and 637-A 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
Federal Energy Regulatory Commission Staff to analyze whether the Federal
Energy Regulatory Commission 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
Federal Energy Regulatory Commission should mandate greater standardization in
terms and conditions of service across the interstate pipeline grid. In
addition, the Federal

43
<PAGE>

Energy Regulatory Commission recently 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 a recent order 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 Federal Energy Regulatory Commission also
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
Federal Energy Regulatory Commission's purposes in issuing such rules was the
desire to provide producers and 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. We cannot predict what further action the Federal Energy
Regulatory Commission will take on these matters, nor can we accurately predict
whether the Federal Energy Regulatory Commission's actions will achieve the
goal of increasing competition in markets in which our natural gas is sold.
However, we do not believe that any action taken will affect us in a way that
materially differs from the way it affects other natural gas producers,
gatherers and marketers.

The Outer Continental Shelf Lands Act requires that all pipelines operating
on or across the Outer Continental Shelf provide open-access, non-
discriminatory service. Although the Federal Energy Regulatory Commission has
opted not to impose the regulations of Order No. 509, in which the Federal
Energy Regulatory Commission implemented the Outer Continental Shelf Lands Act,
on gatherers and other non-jurisdictional entities, the Federal Energy
Regulatory Commission has retained the authority to exercise jurisdiction over
those entities if necessary to permit non-discriminatory access to service on
the Outer Continental Shelf.

Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the Federal Energy Regulatory Commission
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 Federal Energy Regulatory Commission and
Congress will continue.

Federal Leases. A substantial portion of our operations is located on
federal natural gas and oil leases, which are administered by the Minerals
Management Service. Such leases are issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed Minerals
Management Service regulations and orders pursuant to the Outer Continental
Shelf Lands Act which are subject to interpretation and change by the Minerals
Management Service. For offshore operations, lessees must obtain Minerals
Management Service 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 Minerals Management Service prior to the commencement of drilling. The
Minerals Management Service has promulgated regulations requiring offshore
production facilities located on the Outer Continental Shelf to meet stringent
engineering and construction specifications. The Minerals Management Service
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 Minerals
Management Service 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 Minerals Management Service 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. We are currently in compliance with the bonding
requirements of the Minerals Management Service. Under some circumstances, the
Minerals Management Service may require any of our operations on federal leases
to be suspended or terminated. Any such suspension or termination could
materially adversely affect our financial condition and results of operations.

The Minerals Management Service 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 modifies the valuation
procedures for non-arm's-length crude oil transactions, establishes a new form
for collecting value

44
<PAGE>

differential data and amends the valuation procedure for the sale of federal
royalty oil. We believe this rule will not have a material impact on our
financial condition, liquidity or results of operations.

State and Local Regulation of Drilling and Production. We own 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 us are not currently regulated and are made at
market prices. The price we receive 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 Federal Energy Regulatory Commission 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. Beginning later this year, the Federal Energy
Regulatory Commission will conduct a scheduled review of the indexing system.
Any changes resulting from that review, however, would not take effect before
July 2001. The Federal Energy Regulatory Commission'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. We are unable at this time to
predict the effects of these regulations, if any, on the transportation costs
associated with oil production from our properties. However, we do not believe
that these regulations affect us any differently than other producers.

Environmental Regulations. Our 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, our business and prospects could be adversely affected.

The Oil Pollution Act of 1990 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 Oil Pollution Act of 1990 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 Oil Pollution Act of 1990.

The Oil Pollution Act of 1990 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 Oil Pollution Act of 1990 requires
parties responsible for offshore facilities to provide financial assurance in
the amount of $35.0 million to cover potential Oil Pollution Act of 1990
liabilities. This amount can be increased up to $150.0 million if a study by
the Minerals Management Service indicates that an amount higher than $35.0
million should be required. On August 11, 1998, the Minerals Management Service
adopted a rule implementing these Oil Pollution Act of 1990 financial
responsibility requirements. We are in compliance with this rule.

45
<PAGE>

The Oil Pollution Act of 1990 also imposes other requirements, such as the
preparation of an oil spill contingency plan. We have such a plan in place. We
are 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 Outer Continental Shelf Lands Act 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 Outer Continental Shelf Lands Act 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,
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 Comprehensive Environmental Response, Compensation, and Liability Act 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.

Our operations are also subject to regulation of air emissions under the
Clean Air Act, comparable state and local requirements and the Outer
Continental Shelf Lands Act. Future regulations under these laws could lead to
the gradual imposition of new air pollution control requirements on our
operations. Therefore, we may incur capital expenditures over the next several
years to upgrade our air pollution control equipment. We do not believe that
our operations would be materially affected by any such requirements, nor do we
expect such requirements to be any more burdensome to us than to other
companies our 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 our 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 us.

Our management believes that we are 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 us.

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;

46
<PAGE>

. 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, we 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 our operations; and

. repairs to resume operations.

If we experience any of these problems, it could affect well bores,
platforms, gathering systems and processing facilities, which could adversely
affect our ability to conduct operations.

As part of our strategy, we explore for natural gas and oil in the deep
waters of the Gulf of Mexico where operations are more difficult than in
shallower waters. Our 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 intrastructure 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 we can market
the natural gas or oil, increasing the risk involved with these operations.

Offshore operations also are 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, we 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, we maintain insurance against some,
but not all, potential risks and losses. We do not carry business interruption
insurance. For some risks, we may not obtain insurance if we believe 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 us.

Employees

At June 30, 2000, we had 41 full-time employees. We believe that our
relationships with our employees are satisfactory. None of our employees is
covered by a collective bargaining agreement. From time to time, we use 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
us, including pumping, maintenance, dispatching, inspection and testing.

Legal Proceedings

From time to time, we may be a party to various legal proceedings. We
currently are not a party to any material litigation.

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<PAGE>

MANAGEMENT

Executive Officers and Directors

The following table sets forth the names, ages and positions of our
executive officers and directors.

<TABLE>
<CAPTION>
Name Age Position
---- --- --------
<S> <C> <C>
Roger L. Jarvis......... 46 Chairman of the Board, President and Chief Executive Officer
James M. Alexander...... 48 Vice President, Chief Financial Officer and Secretary
William D. Hubbard...... 56 Vice President--Exploration
Kelly M. Barnes......... 46 Vice President--Land
L. Scott Broussard...... 42 Vice President--Drilling and Production
Jimmy W. Bennett........ 53 Vice President--Systems Technology and Processing
Jeffrey C. Zaruba....... 36 Treasurer
Bjarte Bruheim.......... 44 Director
Sheldon R. Erikson...... 58 Director
Jeffrey A. Harris....... 44 Director
Michael E. McMahon...... 52 Director
Reidar Michaelsen....... 56 Director
Howard H. Newman........ 53 Director
</TABLE>

The following biographies describe the business experience of our executive
officers and directors.

Roger L. Jarvis has served as President, Chief Executive Officer and a
director of Spinnaker since 1996 and as Chairman of Spinnaker since 1998. From
1986 to 1994, Mr. Jarvis served in various capacities with King Ranch Inc. and
its subsidiary, King Ranch Oil and Gas, Inc., including Chief Executive
Officer, President and Director of King Ranch Inc. and Chief Executive Officer
and President of King Ranch Oil and Gas, Inc., where he expanded its activities
in the Gulf of Mexico. Mr. Jarvis served as Chief Executive Officer, President
and Principal of (American) Barrick Exploration from 1981 to 1986. In 1979, he
co-founded an engineering and geological consulting firm, Lawson Engineering
Incorporated, where he worked until 1981. From 1976 to 1979, Mr. Jarvis worked
for Amoco Production Company as a petroleum engineer.

James M. Alexander has served as Vice President, Chief Financial Officer and
Secretary of Spinnaker since 1996. Mr. Alexander served as President of
Alexander Consulting from 1992 to 1994, and again from 1995 to 1996. From 1994
to 1995, he served as Chief Financial Officer and then President of Enron
Global Power and Pipeline L.L.C. Mr. Alexander also has served in various
positions within the corporate finance departments of Howard, Weil, Labouisse,
Friedrichs; Drexel Burnham Lambert; Lehman Brothers; and The First Boston
Corporation. Mr. Alexander is a director of Dril-Quip, Inc. Mr. Alexander has
recently announced his intention to retire on or before May 1, 2001.

William D. Hubbard has served as Vice President--Exploration of Spinnaker
since 1996. He served as Senior Vice President--Exploration at Global Natural
Resources Corp. from 1992 to 1996, where he was responsible for both onshore
and offshore exploration. From 1987 to 1992, Mr. Hubbard served as Vice
President--Exploration at Adobe Resources Corporation, which merged into Santa
Fe Energy Resources, Inc. in 1992.

Kelly M. Barnes has served as Vice President--Land of Spinnaker since 1997.
From 1992 to 1996, he served as Vice President--Land and Assistant Corporate
Secretary of Global Natural Resources Corporation of Nevada and its affiliated
corporations. Prior to joining Global Natural Resources Corporation of Nevada,
Mr. Barnes held various managerial positions with Adobe Resources Corporation
and its predecessors.

L. Scott Broussard has served as Vice President--Drilling and Production of
Spinnaker since August 1999 after joining Spinnaker as Operations Manager in
1998. Mr. Broussard served as Vice President and co-owner of HTK Consultants,
Inc., an engineering consulting firm, from 1994 to 1998. From 1990 to 1994, he

48
<PAGE>

served as Drilling Engineer for Samedan Oil Corporation, supervising operations
in the Gulf of Mexico. From 1981 to 1990, he served in various capacities with
Placid Oil Company, including the position of Senior Drilling Engineer and
supervising operations in the deepwater Gulf of Mexico.

Jimmy W. Bennett has served as Vice President--Systems Technology and
Processing since May 2000. From 1997 to 2000 he served as Spinnaker's Systems
Manager. Prior to joining Spinnaker, Mr. Bennett served as Systems Manager for
King Ranch Oil and Gas, Inc. from 1991 to 1997. From 1969 to 1991, he held
various seismic data processing and acquisition positions including Manager,
Seismic Processing and Acquisition for Superior Oil Company and Seismic
Processing Specialist with Chevron Oil Company.

Jeffrey C. Zaruba has served as Treasurer since joining Spinnaker in August
1999. From 1992 to 1999, Mr. Zaruba served as Assistant Controller and held
various financial and tax reporting positions with Cliffs Drilling Company,
which merged with R&B Falcon Corporation in 1998. From 1987 to 1992, he was an
Audit Manager and held senior and staff audit positions with Arthur Young.

Bjarte Bruheim has served as a director of Spinnaker since 1996. Mr. Bruheim
has served as the President and Chief Operating Officer of Petroleum Geo-
Services since March 1993 and was President of PGS Exploration (U.S.), Inc.
from 1991 to 1994. Mr. Bruheim was employed with Geco Geophysical Company,
Inc., Houston from 1981 to 1991, most recently as Vice President, Marine
Operations North/South America.

Sheldon R. Erikson has served as a director of Spinnaker since February
2000. Mr. Erikson has served as the Chairman of the Board of Cooper Cameron
Corporation since 1996 and President and Chief Executive Officer and Director
since 1995. He was Chairman of the Board from 1988 to 1995, and President and
Chief Executive Officer from 1987 to 1995, of The Western Company of North
America. Previously, he was President of the Joy Petroleum Equipment Group of
Joy Manufacturing Company. He is a director of Triton Energy Corporation, Layne
Christensen Co., National Ocean Industries Association, Petroleum Equipment
Suppliers Association and American Petroleum Institute.

Jeffrey A. Harris has served as a director of Spinnaker since 1996. Mr.
Harris has been a Member and Managing Director of E.M. Warburg, Pincus & Co.,
LLC and a general partner of Warburg, Pincus & Co. since 1988, where he has
been employed since 1983. He is currently a member of that firm's Operating
Committee. Mr. Harris serves on the board of directors of Industri-Matematik
International, ECsoft Group plc and Knoll, Inc.

Michael E. McMahon has served as a director of Spinnaker since October 1999.
Mr. McMahon has served as a partner in RockPort Partners LLC, an investment
company, since June 1998. From July 1997 to June 1998, Mr. McMahon was a
Managing Director of Chase Securities, Inc., and from October 1994 until July
1997, Mr. McMahon was a Managing Director of Lehman Brothers. Prior to joining
Lehman Brothers, Mr. McMahon had been a partner in Aeneas Group, Inc., a
subsidiary of Harvard Management Company, Inc., since January 1993. Harvard
Management Company, Inc. is a private investment company responsible for
managing the endowment fund of Harvard University. Mr. McMahon was primarily
responsible for the fund's energy and commodities investments. Mr. McMahon also
has served as a director of Triton Energy Limited since 1993.

Reidar Michaelsen has served as a director of Spinnaker since 1996. He has
served as the Chairman of the Board and Chief Executive Officer of Petroleum
Geo-Services since 1993. He was President of Petroleum Geo-Services from 1991
to 1993. Mr. Michaelsen served as managing director of Norsk Vekst AAS from
1989 to 1991. He headed the Selmer Sande Group from 1986 to 1989 and was with
Geco Geophysical Company, Inc., Houston from 1982 to 1986, reaching the
position of managing director.

Howard H. Newman has served as a director of Spinnaker since 1996. Mr.
Newman has been a Member and Managing Director of the investment firm of E.M.
Warburg, Pincus & Co., LLC and a general partner of Warburg, Pincus & Co. since
1987. He is currently a member of that firm's Operating Committee. Prior to

49
<PAGE>

joining Warburg, Pincus Ventures, he held various positions with Morgan Stanley
& Co., Incorporated. Mr. Newman serves on the board of directors of ADVO, Inc.,
Newfield Exploration Company, EEX Corporation, Cox Insurance Holdings, Plc,
Eagle Family Foods Holdings, Inc. and several privately held companies.

Our board of directors currently has seven members. Our directors are
elected annually and hold office until the next annual meeting of stockholders
and until their successors are duly elected and qualified. Our executive
officers serve at the discretion of our board of directors.

Committees of the Board of Directors

Our board of directors has established an audit committee, compensation
committee and a risk management committee.

Audit Committee

The audit committee currently consists of Messrs. McMahon and Erikson. The
audit committee is responsible for:

. recommending the selection of our independent public accountants;

. reviewing and approving the scope of our independent public accountants'
audit activity and the extent of non-audit services;

. reviewing with management and the independent public accountants the
adequacy of our basic accounting systems and the effectiveness of our
internal audit plan and activities;

. reviewing our consolidated financial statements with management and the
independent public accountants and exercising general oversight of our
financial reporting process; and

. reviewing our litigation and other legal matters that may affect our
financial condition and monitoring compliance with our business ethics
and other policies.

Compensation Committee

The compensation committee currently consists of Messrs. Harris, Bruheim,
Erikson, McMahon, Michaelsen and Newman. This committee's responsibilities
include:

. administering and granting awards under our 1998 Stock Option Plan, the
1999 Stock Incentive Plan and the Adjunct Stock Option Plan;

. reviewing the compensation of our Chief Executive Officer and
recommendations of the Chief Executive Officer as to appropriate
compensation for our other executive officers and key personnel;

. examining periodically our general compensation structure; and

. supervising our welfare and pension plans and compensation plans.

Risk Management Committee

The risk management committee currently consists of Messrs. Jarvis and
Newman. This committee is responsible for monitoring the hedging program and
adherence to the hedging policy.

Compensation Committee Interlocks and Insider Participation

None of our executive officers serves as a member of the board of directors
or compensation committee of any entity that has one or more of its executive
officers serving as a member of our board of directors or compensation
committee.

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<PAGE>

Compensation of Directors

We paid no compensation to any non-employee director prior to our initial
public offering in September 1999. Following this date, non-employee directors
unaffiliated with Warburg, Pincus Ventures or Petroleum Geo-Services are
granted options pursuant to the 1999 Stock Incentive Plan to purchase 16,000
shares of common stock at fair market value, as defined, upon appointment to
the board of directors, with 20 percent vesting on the date of grant and 20
percent vesting on each anniversary of the grant date. In addition, these
directors are granted 600 options quarterly during the year commencing upon the
annual meeting that vest 100 percent on the date of grant. We granted options
to purchase 16,000 shares of common stock to Mr. McMahon in October 1999. Non-
employee directors are also reimbursed for out-of-pocket expenses incurred to
attend board and committee meetings.

Executive Compensation

The following table sets forth information regarding the compensation of our
Chief Executive Officer and each of our four other most highly compensated
executive officers for the years ended December 31, 1999, 1998 and 1997. The
annual compensation amounts in the table exclude perquisites and other personal
benefits because they did not exceed the lesser of $50,000 or 10 percent of the
total annual salary and bonus reported for each executive officer:

Summary Compensation Table

<TABLE>
<CAPTION>
Long-Term
Compensation
Awards
Annual ------------
Compensation Shares
Name and Principal ----------------- Underlying All Other
Position Year Salary Bonus Options Compensation(1)
------------------ ---- ------ -------- ------------ --------------
<S> <C> <C> <C> <C> <C>
Roger L. Jarvis........... 1999 $265,000 $134,000 236,529 $750
Chairman, President and 1998 265,000 91,498 -- 750
Chief Executive Officer 1997 250,000 50,000 -- 317

James M. Alexander........ 1999 184,000 65,000 95,898 750
Vice President, Chief
Financial Officer 1998 184,000 67,342 -- 750
and Secretary 1997 175,000 40,000 -- 317

William D. Hubbard........ 1999 175,000 60,000 59,960 750
Vice President--
Exploration 1998 175,000 56,042 -- 750
1997 165,000 35,000 248,000 317

L. Scott Broussard........ 1999 137,700 62,100 23,798 750
Vice President--Drilling
and Production 1998 112,500 43,233 52,800 625
1997 -- -- -- --

Kelly M. Barnes........... 1999 118,000 41,300 63,593 750
Vice President--Land 1998 118,000 37,789 -- 750
1997 110,000 30,000 111,600 317
</TABLE>
--------
(1) The All Other Compensation column shows the dollar value of insurance
premiums that we have paid with respect to term life insurance for the
benefit of the named executive officer.

51
<PAGE>

Stock Options Granted in 1999

The following table contains information concerning stock options granted to
the named executive officers in 1999.
<TABLE>
<CAPTION>
Individual Grants Potential Realizable
------------------------------------------ Value at Assumed
Number of % of Total Annual Rates of Stock
Shares Options Price Appreciation
Underlying Granted to Exercise for Option Terms(3)
Options Employees Price Expiration ---------------------
Name Granted(1) In 1999(2) Per Share Date 5% 10%
---- ---------- ---------- --------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Roger L. Jarvis......... 236,529 27.3% $14.50 10/04/09 $2,156,901 $5,466,012
James M. Alexander...... 95,898 11.1 14.50 10/04/09 874,491 2,216,132
William D. Hubbard...... 59,960 6.9 14.50 10/04/09 546,774 1,385,632
L. Scott Broussard...... 5,000 0.6 15.63 01/15/09 49,132 124,511
18,798 2.2 14.50 10/04/09 171,418 434,408
Kelly M. Barnes......... 30,000 3.5 15.63 01/15/09 294,794 747,067
33,593 3.9 14.50 10/04/09 306,334 776,310
</TABLE>

--------
(1) The options expire ten years from the date of grant and vest 20 percent on
the grant date and 20 percent on each anniversary of the grant date.
(2) The board of directors granted options representing 866,574 shares in
1999.
(3) Calculated based on the indicated rates of appreciation, compounded
annually, from the date of grant to the end of each option term. Actual
gains, if any, on stock option exercises and common stock holdings depend
on the future performance of the common stock and overall market
conditions. We cannot assure you that the amounts reflected in this table
will be achieved. The calculation does not take into account the effects,
if any, of provisions of the option plans governing termination of options
upon employment termination, transferability or vesting.

Stock Option Exercises and Fiscal Year-End Values

The following table contains certain information concerning the value of
unexercised options at December 31, 1999.

<TABLE>
<CAPTION>
Number of Shares
Underlying Unexercised Value of Unexercised
Options at In-the-Money Options at
December 31, 1999 December 31, 1999(1)
------------------------- -------------------------
Name Exercisable Unexercisable Exercisable Unexercisable
---- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
Roger L. Jarvis............. 840,906 387,623 $4,438,400 $1,109,600
James M. Alexander.......... 336,620 156,078 1,775,360 443,840
William D. Hubbard.......... 160,792 147,168 832,200 554,800
L. Scott Broussard.......... 25,880 50,718 125,840 188,760
Kelly M. Barnes............. 79,679 95,514 374,490 249,660
</TABLE>
--------
(1) The value of each unexercised in-the-money stock option is equal to the
difference between the closing price of our common stock on The Nasdaq
National Market on December 31, 1999 of $14.13 per share and the exercise
price of the stock option.

Employment Agreements

Mr. Jarvis entered into an employment agreement with Spinnaker effective
December 20, 1996. The agreement provides that Mr. Jarvis will receive a
minimum annual base salary equal to $250,000. Under the agreement, Mr. Jarvis
also may receive bonuses, at the discretion of the board of directors, and will
be allowed to participate in all benefit plans offered by Spinnaker to
similarly situated employees.

52
<PAGE>

Either the board of directors or Mr. Jarvis can terminate the employment
agreement at any time. If the employment agreement, which has an initial term
ending on December 31, 2000, is not terminated on or before December 15, 2000,
or on or before each December 15th thereafter, the term of the agreement shall
automatically be extended for one additional year. If we terminate the
employment agreement prior to the expiration of the initial term without cause
or if Mr. Jarvis terminates his employment prior to the expiration of the
initial term for good reason, then we will continue to pay his then current
base salary and continue, at our cost, his coverages under our group health
plans, for the greater of the balance of the initial term or one year. In
addition, if any payment or distribution by Spinnaker or its affiliates to Mr.
Jarvis is subject to Section 4999 of the Internal Revenue Code of 1986, as
amended, Spinnaker is required to compensate him for the amount of any excise
tax imposed on any payments or distributions pursuant to Section 4999 of the
Internal Revenue Code of 1986, as amended, and for any taxes imposed on that
additional payment. Section 4999 of the Internal Revenue Code addresses
additional taxes payable in the event of a change in control of Spinnaker.

Mr. Alexander entered into an employment agreement with Spinnaker effective
December 20, 1996. The agreement provides that he will receive a minimum annual
base salary equal to $175,000. The other terms of Mr. Alexander's employment
agreement are substantially similar to the terms of Mr. Jarvis' employment
agreement.

Mr. Hubbard entered into an employment agreement with Spinnaker effective
December 20, 1996. The agreement provides that he will receive a minimum annual
base salary equal to $165,000. The other terms of Mr. Hubbard's employment
agreement are substantially similar to the terms of the employment agreements
described above. However, on December 31, 1998, Mr. Hubbard's employment
agreement became a year-to-year employment agreement. As a result, if his
employment is not terminated before December 15, 2000, and on each year
thereafter, the term of the agreement will automatically be extended for one
additional year.

Mr. Barnes entered into an employment agreement with Spinnaker effective
December 20, 1996. The agreement provides that he will receive a minimum annual
base salary equal to $110,000. The other terms of Mr. Barnes' employment
agreement are substantially similar to the terms of Mr. Hubbard's employment
agreement.

1998 Stock Option Plan

In January 1998, we adopted a stock option plan. The plan was amended and
restated in September 1999. The plan permits grants of both incentive stock
options and nonqualified stock options. No option will be treated as an
incentive stock option unless the purchase price equals or exceeds the fair
market value of common stock subject to the option on the grant date for the
option. The stock option plan authorizes for issuance 2,673,242 shares of our
common stock, with adjustment in the case of changes in our capitalization
affecting the options. The compensation committee of our board of directors
administers the plan. Unless terminated by our board of directors, the plan
continues for 10 years from the date of adoption.

The purchase price of an aggregate of 1,520,608 shares of common stock
issuable under options authorized under the 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 plan is $15.63 per share. Messrs. Jarvis and
Alexander were granted stock appreciation rights in connection with their
options. On July 12, 1999, Messrs. Jarvis and Alexander each agreed to
eliminate his stock appreciation rights.

In the event of certain significant changes in Spinnaker, all options then
outstanding generally will become immediately exercisable in full. Significant
changes include:

. any merger, consolidation or other reorganization in which Spinnaker is
not the surviving entity, or which Spinnaker survives, but only as a
subsidiary of an entity;

. any sale, lease or exchange of all or substantially all our assets;

. the dissolution and liquidation of Spinnaker; or

. a change in control of Spinnaker.

This offering does not constitute a significant change in Spinnaker under the
plan.

53
<PAGE>

At June 30, 2000, we had outstanding options to purchase a total of
2,496,457 shares of common stock granted under the 1998 Stock Option Plan, of
which 1,368,003 are exercisable at $5.00 per share and 1,128,454 are
exercisable at $15.63 per share. All outstanding options are currently
exercisable for a term of up to 10 years from the date of each grant.

1999 Stock Incentive Plan

In September 1999, our board of directors and the stockholders of Spinnaker
adopted the Spinnaker 1999 Stock Incentive Plan. The purpose of the plan is to
provide directors, employees and consultants of Spinnaker additional incentive
and reward opportunities designed to enhance the profitable growth of
Spinnaker. The plan provides for the granting of incentive stock options
intended to qualify under Section 422 of the Internal Revenue Code, options
that do not constitute incentive stock options and restricted stock awards. In
general, the compensation committee of our board of directors administers the
plan and is authorized to select the recipients of awards and the terms and
conditions of awards. However, the board of directors is expected to administer
the plan with respect to awards to directors.

The number of shares of our common stock that may be issued under the plan
may not exceed 1,300,000 shares, subject to adjustment to reflect stock
dividends, stock splits, recapitalizations and similar changes in Spinnaker's
capital structure. Shares of our common stock which are attributable to awards
which have expired, terminated or been canceled or forfeited are available for
issuance or use in connection with future awards. The maximum number of shares
of our common stock that may be subject to awards granted under the plan to any
one individual during any calendar year may not exceed 300,000 shares, subject
to adjustment to reflect stock dividends, stock splits, recapitalizations and
similar changes in our capital structure.

The compensation committee determines the price at which a share of our
common stock may be purchased upon exercise of an option granted under the
plan. However, in the case of an incentive stock option, the purchase price
will not be less than the fair market value of a share of our common stock on
the date the option is granted. In addition, in the case of an option that does
not constitute an incentive stock option, the purchase price will not be less
than the fair market value of a share of our common stock on the date the
option is granted. Shares of our common stock that are the subject of a
restricted stock award under the plan will be subject to restrictions on
disposition by the holder of the award and an obligation of the holder to
forfeit and surrender the shares under some circumstances. These obligations to
forfeit or surrender the shares, or forfeiture restrictions, will be determined
by the compensation committee in its sole discretion, and the compensation
committee may provide that these forfeiture restrictions will lapse upon:

. the attainment of one or more performance targets established by the
compensation committee;

. the award holder's continued employment with Spinnaker or continued
service as a consultant or director for a specified period of time;

. the occurrence of any event or the satisfaction of any other condition
specified by the compensation committee in its sole discretion; or

. a combination of any of the foregoing.

If Spinnaker is involved in a merger or consolidation in which its
stockholders beneficially own less than 50% of the voting stock of the
surviving entity or any person, entity or group acquires beneficial ownership
of more than 50% of the voting stock of Spinnaker, then all options will become
immediately exercisable and forfeiture restrictions or restricted stock awards
will lapse.

No awards under the plan may be granted after ten years from the date the
plan was adopted by our board of directors. The plan will remain in effect
until all awards granted under it have been satisfied or expired. Our board of
directors in its discretion may terminate the plan at any time with respect to
any shares of our common stock for which awards have not been granted. The plan
may be amended, other than to increase the

54
<PAGE>

maximum aggregate number of shares that may be issued under the plan or to
change the class of individuals eligible to receive awards under the plan, by
the board of directors without the consent of the stockholders of Spinnaker. No
change in any award previously granted under the plan may be made which would
impair the rights of the holder of the award without the approval of the
holder.

At June 30, 2000, we had outstanding options to purchase a total of
1,093,624 shares of common stock granted under the 1999 Stock Incentive Plan,
of which 678,824 options are exercisable at $14.50 per share, 373,050 options
are exercisable at $16.13 per share and 41,750 options are exercisable at
prices ranging from $15.56 to $23.38 per share.

Adjunct Stock Option Plan

In connection with the 1999 Stock Incentive Plan, our board of directors and
the stockholders of Spinnaker adopted the Adjunct Stock Option Plan. The number
of shares of our common stock that may be issued under the plan may not exceed
21,920 shares, subject to adjustment to reflect stock dividends, stock splits,
recapitalization and similar changes in Spinnaker's capital structure.

At June 30, 2000, we had outstanding options to purchase a total of 21,104
shares of common stock granted under the Adjunct Stock Option Plan. All of
these options are exercisable at $2.50 per share.

55
<PAGE>

CERTAIN TRANSACTIONS

Following is a discussion of transactions between us and our officers,
directors and stockholders owning more than 5% of the outstanding shares of
common stock.

Registration Rights

We, Petroleum Geo-Services, Warburg, Pincus Ventures and some of our other
stockholders, each of whom is a current or former employee of Spinnaker, are
parties to a registration rights agreement. This registration rights agreement
is described under "Description of Capital Stock--Registration Rights."

Petroleum Geo-Services Data Agreement

On December 20, 1996, we entered into the data agreement with Petroleum Geo-
Services. We amended the agreement as of January 6, 1998 when we converted from
a limited liability company to a corporation. We amended the agreement again as
of June 30, 1999 to modify the amount, type and geographic coverage of the data
and related information made available to us. In connection with that second
amendment we issued 1,000,000 shares of common stock to Petroleum Geo-Services.
We have agreed to purchase $2.0 million of seismic-related services from
Petroleum Geo-Services prior to December 31, 2002. Our purchases of seismic
related services from Petroleum Geo-Services were $59,000 in 1997, $122,000 in
1998, $318,000 in 1999 and $138,000 for the six months ended June 30, 2000. We
believe the terms of the data agreement are at least as fair to us as we could
have obtained from an unaffiliated third party. The Petroleum Geo-Services data
agreement, as amended, is described under "Business and Properties--Petroleum
Geo-Services Data Agreement."

Investments in Spinnaker

Since our inception and prior to or concurrently with our initial public
offering, our executive officers, directors and 5 percent stockholders invested
cash and other property in Spinnaker in exchange for shares of our stock. The
following table summarizes the shares of our common stock acquired from us by
our executive officers, directors and 5 percent stockholders since our
inception and prior to or concurrently with our initial public offering.

<TABLE>
<CAPTION>
Common
Executive Officers, Directors and 5% Stockholders Stock(8)
------------------------------------------------- ---------
<S> <C>
Warburg, Pincus Ventures, L.P. (1)................................. 6,800,585
Petroleum Geo-Services ASA (2)..................................... 5,388,743
Roger L. Jarvis (3)................................................ 164,959
James M. Alexander (4)............................................. 37,883
William D. Hubbard (5)............................................. 22,384
Kelly M. Barnes (6)................................................ 10,072
L. Scott Broussard (7)............................................. 1,276
</TABLE>
--------
(1) Warburg, Pincus Ventures paid us approximately $60.0 million and, prior to
our initial public offering, provided a guarantee of our credit facility
in consideration for the shares listed above. Please read "Management's
Discussion and Analysis of Financial Condition and Results of Operations--
Liquidity and Capital Resources" for a description of our credit facility.
Two of our directors, Jeffrey A. Harris and Howard H. Newman, are
affiliated with Warburg, Pincus Ventures. Please read "Security Ownership
of Management and Certain Beneficial Owners" for a description of Messrs.
Harris' and Newman's affiliations with Warburg, Pincus Ventures.

(2) Petroleum Geo-Services received the shares listed above as consideration
for the rights granted to us under the Petroleum Geo-Services Data
Agreement, for an additional $15.0 million and for providing a guarantee
of our credit facility prior to our initial public offering. Please read
"Business and Properties--Petroleum Geo-Services Data Agreement" for a
description of the Petroleum Geo-Services Data Agreement and

56
<PAGE>

"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources" for a description of our
credit facility. Two of our directors, Bjarte Bruheim and Reidar
Michaelsen, are affiliated with Petroleum Geo-Services. Please read
"Security Ownership of Management and Certain Beneficial Owners" for a
description of Messrs. Bruheim's and Michaelsen's affiliations with
Petroleum Geo-Services.

(3) As consideration for the shares listed above, Mr. Jarvis paid us
approximately $70,270 in cash and contributed to Spinnaker the intangible
assets owned by him associated with his creation of Spinnaker, including
rights to Spinnaker's name and related patents, copyrights and goodwill.
Mr. Jarvis has sold 48,800 shares of common stock to employees of
Spinnaker.

(4) Mr. Alexander paid us approximately $128,000 for the shares listed above.

(5) Mr. Hubbard paid us approximately $80,000 for the shares listed above.

(6) Mr. Barnes paid us approximately $36,000 for the shares listed above.

(7) Mr. Broussard paid us approximately $16,000 for the shares listed above.

(8) Includes shares of common stock issued upon conversion of each share of
our preferred stock into two shares of our common stock upon consummation
of our initial public offering. In addition, Warburg, Pincus Ventures,
Petroleum Geo-Services, Mr. Jarvis and Mr. Alexander agreed to receive
additional shares of our common stock upon consummation of our initial
public offering in lieu of receiving accrued cash dividends on the
preferred stock of approximately $12.9 million, $3.3 million, $70,000 and
$28,000, respectively. For purposes of determining the number of shares
of common stock that each person received in lieu of the cash dividends,
the common stock issued to these persons was valued at the initial public
offering price less the underwriters' discounts and commissions per
share.

Credit Agreement

In September 1998, we entered into an $85.0 million credit agreement with
Credit Suisse First Boston, New York Branch, Bank of Montreal and Bank of
America, N.A. Credit Suisse First Boston and Bank of America N.A. are each
affiliates of one of the underwriters for this offering. Borrowings under the
credit agreement were used to fund exploration and development activities. The
credit agreement was secured by substantially all of our assets, including our
interests in our natural gas and oil properties, and supported by guarantees
of Petroleum Geo-Services and Warburg, Pincus Ventures, our principal
stockholders. Simultaneously with the completion of the initial public
offering, we retired all outstanding borrowings under the credit agreement,
which were $72.0 million as of October 4, 1999.

Indemnification Agreements

We have entered into indemnification agreements with our officers and
directors containing provisions requiring us to, among other things, indemnify
our officers and directors against liabilities that may arise by reason of
their status or service as officers or directors, other than liabilities
arising from willful misconduct of a culpable nature, and to advance expenses
they incur as a result of any proceeding against them as to which they could
be indemnified.

57
<PAGE>

SECURITY OWNERSHIP OF MANAGEMENT
AND CERTAIN BENEFICIAL HOLDERS

The following table presents information regarding beneficial ownership of
our common stock as of August 10, 2000 and as adjusted to reflect the sale of
common stock in this offering by:

. each person who we know owns beneficially more than 5 percent of our
common stock;

. each of our directors;

. our chief executive officer and each of our four other most highly
compensated executive officers; and

. all our executive officers and directors as a group.

Unless otherwise indicated, each person listed has sole voting and
dispositive power over the shares indicated as owned by that person, and the
address of each stockholder is the same as our address. Furthermore, under the
regulations of the Securities and Exchange Commission, shares are deemed to be
"beneficially owned" by a person if the holder directly or indirectly has or
shares the power to vote or dispose of these shares, whether or not the holder
has any pecuniary interest in these shares, or if the holder has the right to
acquire the power to vote or dispose of these shares within 60 days, including
any right to acquire through the exercise of any option, warrant or right.
Therefore, in this table the shares beneficially owned by Messrs. Jarvis,
Alexander, Hubbard, Barnes, Broussard, Erikson and McMahon include 902,912,
362,399, 207,384, 109,717, 41,199, 3,800 and 7,600 shares, respectively, that
may be acquired within 60 days through the exercise of stock options. Please
note that the address of Warburg, Pincus Ventures, L.P. and Messrs. Harris and
Newman is 466 Lexington Avenue, 10th Floor, New York, New York 10017, and the
address of Petroleum Geo-Services and Messrs. Bruheim and Michaelsen is
Strandvein 50E, P.O. Box 89, N-1325, Lysaker, Norway.

<TABLE>
<CAPTION>
Beneficial Ownership
----------------------------
Percent
-----------------
Before After
Beneficial Owner Shares Offering Offering
---------------- ---------- -------- --------
<S> <C> <C> <C>
Warburg, Pincus Ventures, L.P. (1)............. 6,800,585 33.0% 26.7%
Petroleum Geo-Services ASA (2)................. 5,388,743 26.2 21.2
Strong Capital Management, Inc. (3)............ 1,154,700 5.6 4.5
Roger L. Jarvis................................ 1,001,151 4.7 3.8
James M. Alexander............................. 462,782 2.2 1.8
William D. Hubbard............................. 229,768 1.1 *
Kelly M. Barnes................................ 119,789 * *
L. Scott Broussard............................. 42,475 * *
Bjarte Bruheim (2)............................. 5,393,743 26.2 21.2
Sheldon R. Erikson............................. 3,800 * *
Jeffrey A. Harris (1).......................... 6,800,585 33.0 26.7
Michael E. McMahon............................. 22,075 * *
Reidar Michaelsen (2).......................... 5,393,743 26.2 21.2
Howard H. Newman (1)........................... 6,800,585 33.0 26.7
All executive officers and directors as a group
(13 persons).................................. 14,135,564 63.5 52.0
</TABLE>
--------
* Represents beneficial ownership of less than 1 percent.
(1) The sole general partner of Warburg, Pincus Ventures, L.P. is Warburg,
Pincus & Co., a New York general partnership. E. M. Warburg, Pincus & Co.,
LLC, a New York limited liability company, manages Warburg, Pincus
Ventures, L.P. The members of E. M. Warburg, Pincus & Co., LLC are
substantially the same as the partners of Warburg, Pincus & Co. Lionel I.
Pincus is the managing partner of Warburg, Pincus & Co. and the managing
member of E. M. Warburg, Pincus & Co., LLC and may be deemed to control
both Warburg, Pincus & Co. and E. M. Warburg, Pincus & Co., LLC. Messrs.
Newman and Harris

58
<PAGE>

are Managing Directors and members of E.M. Warburg, Pincus & Co., LLC and
general partners of Warburg, Pincus & Co. As such, Messrs. Newman and
Harris may be deemed to have an indirect pecuniary interest in an
indeterminate portion of the shares beneficially owned by Warburg, Pincus
Ventures. Messrs. Newman and Harris disclaim beneficial ownership of the
shares owned by Warburg, Pincus Ventures.

(2) The 5,388,743 shares are owned directly by Petroleum Geo-Services or by a
wholly owned subsidiary of Petroleum Geo-Services. Mr. Michaelsen serves
as Chairman of the Board and Chief Executive Officer and Mr. Bruheim
serves as President and Chief Operating Officer of Petroleum Geo-Services.
As such, Messrs. Michaelsen and Bruheim may be deemed to have an indirect
pecuniary interest in an indeterminate portion of the shares beneficially
owned by Petroleum Geo-Services. Messrs. Michaelsen and Bruheim disclaim
beneficial ownership of the securities owned by Petroleum Geo-Services.

(3) Based solely on the Schedule 13G dated January 25, 2000 and filed jointly
with the Securities and Exchange Commission on behalf of Strong Capital
Management, Inc., an Investment Adviser registered under Section 203 under
the Investment Advisors Act of 1940, and Mr. Richard S. Strong, Chairman
of the Board and principal shareholder of Strong Capital Management, Inc.
Strong Capital Management, Inc. has voting and dispositive power with
respect to 602,100 and 1,154,700 shares, respectively. Mr. Strong could be
deemed to have voting and/or investment power with respect to the shares
beneficially owned by Strong Capital Management, Inc.

59
<PAGE>

DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock consists of 50,000,000 shares of common stock,
par value $0.01 per share, and 10,000,000 shares of preferred stock, par value
$0.01 per share. As of August 10, 2000, we had outstanding 20,578,303 shares of
common stock and no shares of preferred stock. On completion of this offering,
we will have outstanding 25,478,303 (26,178,303 if the over-allotment option is
exercised in full) shares of common stock and no shares of preferred stock.

Common Stock

Subject to any special voting rights of any series of preferred stock that
we may issue in the future, each share of common stock has one vote on all
matters voted on by our stockholders, including the election of our directors.
No share of common stock affords any cumulative voting or preemptive rights or
is convertible, redeemable, assessable or entitled to the benefits of any
sinking or repurchase fund. Holders of common stock will be entitled to
dividends in the amounts and at the times declared by our board of directors in
its discretion out of funds legally available for the payment of dividends.

Holders of common stock will share equally in our assets on liquidation
after payment or provision for all liabilities and any preferential liquidation
rights of any preferred stock then outstanding. All outstanding shares of
common stock are fully paid and non-assessable.

Preferred Stock

At the direction of our board, we may issue shares of preferred stock from
time to time. Our board of directors may, without any action by holders of the
common stock:

. adopt resolutions to issue preferred stock in one or more classes or
series;

. fix or change the number of shares constituting any class or series of
preferred stock; and

. establish or change the rights of the holders of any class or series of
preferred stock.

The rights any class or series of preferred stock may evidence may include:

. general or special voting rights;

. preferential liquidation or preemptive rights;

. preferential cumulative or noncumulative dividend rights;

. redemption or put rights; and

. conversion or exchange rights.

We may issue shares of, or rights to purchase, preferred stock the terms of
which might:

. adversely affect voting or other rights evidenced by, or amounts
otherwise payable with respect to, the common stock;

. discourage an unsolicited proposal to acquire us; or

. facilitate a particular business combination involving us.

Any of these actions could discourage a transaction that some or a majority
of our stockholders might believe to be in their best interests or in which our
stockholders might receive a premium for their stock over its then market
price.

60
<PAGE>

Registration Rights

We, Petroleum Geo-Services, Warburg, Pincus Ventures and some of our other
stockholders are parties to a registration rights agreement. That agreement
grants Petroleum Geo-Services and Warburg, Pincus Ventures the right to require
us to file a registration statement covering all or part of their shares at our
expense, subject to the following restrictions:

. we are not required to respond to a request until 90 days after the
closing of this offering;

. we are not required to register the shares if Petroleum Geo-Services or
Warburg, Pincus Ventures proposes to sell them at an aggregate price to
the public of less than $20.0 million;

. we are not required to effect more than one requested registration for
an underwritten offering in any six-month period; and

. we generally are not required to effect more than two requested
registrations for underwritten offerings and more than one requested
registration covering the resale of securities for either Petroleum Geo-
Services or Warburg, Pincus Ventures unless we are then eligible to
register the requested sale on Securities and Exchange Commission Form
S-3.

Some of our stockholders also have rights to include their shares, at our
expense, in a registration statement filed by us for purposes of a public
offering. However, the amended registration rights agreement does not permit
those stockholders to include their shares in this offering. An underwriter
participating in these offerings may limit the number of shares offered, and
the number will be allocated first to us, then to participating stockholders on
a pro rata basis.

Anti-Takeover Provisions of our Certificate of Incorporation and Bylaws

Business Combinations under Delaware Law

We are a Delaware corporation and are subject to Section 203 of the Delaware
General Corporation Law. Section 203 prevents an interested stockholder, a
person who owns 15 percent or more of our outstanding voting stock, from
engaging in business combinations with Spinnaker for three years following the
time that the person becomes an interested stockholder. These restrictions do
not apply if:

. before the person becomes an interested stockholder, our board of
directors approves the business combination or the transaction in which
the person becomes an interested stockholder;

. upon completion of the transaction that results in the person becoming
an interested stockholder, the interested stockholder owns at least 85
percent of our outstanding voting stock at the time the transaction
commenced, excluding for purposes of determining the number of shares
outstanding those shares owned by persons who are directors and also
officers and employee stock plans in which employee participants do not
have the right to determine confidentially whether shares held subject
to the plan will be tendered in a tender or exchange offer; or

. at or following the time of the transaction in which the person became
an interested stockholder, the business combination is approved by our
board of directors and authorized at an annual or special meeting of our
stockholders, and not by written consent, by the affirmative vote of at
least two-thirds of our outstanding voting stock not owned by the
interested stockholder.

In addition, the law does not apply to interested stockholders, such as
Petroleum Geo-Services and Warburg, Pincus Ventures, who became interested
stockholders before common stock of the company was listed on The Nasdaq
National Market or the New York Stock Exchange.

The law defines the term "business combination" to encompass a wide variety
of transactions with or caused by an interested stockholder, including mergers,
asset sales and other transactions in which the interested stockholder receives
or could receive a benefit on other than a pro rata basis with other
stockholders. This law could have an anti-takeover effect with respect to
transactions not approved in advance by our board

61
<PAGE>

of directors, including discouraging takeover attempts that might result in a
premium over the market price for the shares of our common stock.

Written Consent of Stockholders

Our certificate of incorporation provides that any action by our
stockholders must be taken at an annual or special meeting of stockholders.
Special meetings of the stockholders may be called only by the board of
directors.

Advance Notice Procedure for Stockholder Proposals

Our bylaws establish an advance notice procedure for the nomination of
candidates for election as directors as well as for stockholder proposals to be
considered at annual meetings of stockholders. In general, notice of intent to
nominate a director must be delivered to or mailed and received at our
principal executive offices as follows:

. With respect to an election to be held at the annual meeting of
stockholders, not less than 90 days nor more than 120 days prior to the
first anniversary date of the preceding year's annual meeting of
stockholders.

. With respect to an election to be held at a special meeting of
stockholders for the election of directors, not earlier than the close
of business on the 120th day prior to the special meeting and not later
than the close of business on the later of the 90th day prior to the
special meeting or the 10th day following the day on which public
disclosure is first made of the date of the special meeting, and must
contain specified information concerning the person to be nominated.

Notice of stockholders' intent to raise business at an annual meeting must
be delivered to or mailed and received at our principal executive offices not
less than 90 days nor more than 120 days prior to the first anniversary date of
the preceding year's annual meeting of stockholders. These procedures may
operate to limit the ability of stockholders to bring business before a
stockholders meeting, including with respect to the nomination of directors or
considering any transaction that could result in a change of control.

Limitation of Liability and Indemnification of Officers and Directors

Limitation of Liability. Delaware law authorizes corporations to limit or
eliminate the personal liability of their officers and directors to them and
their stockholders for monetary damages for breach of officers' and directors'
fiduciary duty of care. The duty of care requires that, when acting on behalf
of the corporation, officers and directors must exercise an informed business
judgment based on all material information reasonably available to them. Absent
the limitations authorized by Delaware law, officers and directors are
accountable to corporations and their stockholders for monetary damages for
conduct constituting gross negligence in the exercise of their duty of care.
Delaware law enables corporations to limit available relief to equitable
remedies such as injunction or rescission.

Our certificate of incorporation limits the liability of our directors to us
or our stockholders to the fullest extent permitted by Delaware law.
Specifically, our directors will not be personally liable for monetary damages
for breach of a director's fiduciary duty in such capacity, except for
liability

. for any breach of the director's duty of loyalty to Spinnaker or our
stockholders;

. for acts or omissions not in good faith or which involve intentional
misconduct or a knowing violation of law;

. for unlawful payments of dividends or unlawful stock repurchases or
redemptions as provided in Section 174 of the Delaware General
Corporation Law; or

. for any transaction from which the director derived an improper personal
benefit.

62
<PAGE>

Indemnification. Delaware law also authorizes corporations to indemnify its
officers, directors, employees and agents for liabilities, other than
liabilities to the corporation, arising because such individual was an officer,
director, employee or agent of the corporation so long as the individual acted
in good faith and in a manner he or she reasonably believed to be in the best
interests of the corporation and not unlawful.

Our bylaws provide that our officers and directors will be indemnified by us
for liabilities arising because such individual was an officer or director of
Spinnaker to the fullest extent permitted by Delaware law. Our bylaws also
provide that we may, by action of our board of directors, provide similar
indemnification to our employees and agents.

The inclusion of these provisions in our certificate of incorporation and
our bylaws may reduce the likelihood of derivative litigation against our
officers and directors and may discourage or deter our stockholders or
management from bringing a lawsuit against our officers and directors for
breach of their duty of care, even though the action, if successful, might
otherwise have benefited us and our stockholders.

These provisions in our certificate of incorporation and bylaws do not alter
the liability of our officers and directors under federal securities laws and
do not affect the right to sue under federal securities laws for violations
thereof.

We have entered into indemnification agreements with each of our directors
and officers. These agreements require us to, among other things, indemnify the
director or officer against expenses and costs incurred by the individual in
connection with any action, suit or proceeding arising out of the individual's
status or service as a director or officer of Spinnaker, other than liabilities
arising from willful misconduct or conduct that is knowingly fraudulent or
deliberately dishonest. The agreement also requires us to advance expenses
incurred by the individual in connection with any proceeding against the
individual with respect to which he or she may be entitled to indemnification
by us. Following completion of this offering, we also will maintain directors'
and officers' liability insurance.

At present, we are not aware of any pending litigation or proceeding
involving any director, officer, employee or agent of Spinnaker where
indemnification will be required or permitted. Furthermore, we are not aware of
any threatened litigation or proceeding that might result in a claim for
indemnification.

Transfer Agent and Registrar

The transfer agent and registrar of our common stock is Computershare
Investor Services, LLC.

63
<PAGE>

UNDERWRITING

Under the terms and subject to the conditions contained in an underwriting
agreement dated August 10, 2000, we have agreed to sell to the underwriters
named below the following respective numbers of shares of common stock:

<TABLE>
<CAPTION>
Number of
Underwriter Shares
----------- ---------
<S> <C>
Credit Suisse First Boston Corporation............................. 1,124,109
Donaldson, Lufkin & Jenrette Securities Corporation................ 1,124,109
Banc of America Securities LLC..................................... 720,594
Dain Rauscher Incorporated......................................... 720,594
Jefferies & Company, Inc........................................... 720,594
Petrie Parkman & Co., Inc.......................................... 196,000
Prudential Securities Incorporated................................. 196,000
Sanders Morris Harris Inc.......................................... 98,000
---------
Total............................................................ 4,900,000
=========
</TABLE>

The underwriting agreement provides that the underwriters are obligated to
purchase all the shares of common stock in this offering if any are purchased,
other than those shares covered by the over-allotment option described below.
The underwriting agreement also provides that if an underwriter defaults, the
purchase commitments of non-defaulting underwriters may be increased or this
offering of common stock may be terminated.

We have granted to the underwriters a 30-day option to purchase on a pro
rata basis up to 700,000 additional shares from us at the public offering price
less the underwriting discounts and commissions. The option may be exercised
only to cover any over-allotments of common stock.

The underwriters propose to offer the shares of common stock initially at
the public offering price on the cover page of this prospectus and to selling
group members at that price less a concession of $0.86 per share. The
underwriters and selling group members may allow a discount of $0.10 per share
on sales to other broker/dealers. After the offering, the public offering price
and concession and discount to broker/dealers may be changed by the
underwriters.

The following table summarizes the compensation and estimated expenses we
will pay.

<TABLE>
<CAPTION>
Per Share Total
----------------------------- -----------------------------
Without With Without With
Over-allotment Over-allotment Over-allotment Over-allotment
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Underwriting discounts
and commissions payable
by us.................. $1.44 $1.44 $7,056,000 $8,064,000
Expenses payable by us.. $0.09 $0.08 $ 450,000 $ 450,000
</TABLE>

The underwriters do not intend to confirm sales to any accounts over which
they exercise discretionary authority.

We intend to use a portion of the net proceeds from the sale of our common
stock to repay indebtedness owed by us to Credit Suisse First Boston, New York
Branch, an affiliate of one of the underwriters. Accordingly, this offering is
being made in compliance with the requirements of Rule 2710(c)(8) of the
National Association of Securities Dealers, Inc. Conduct Rules.

We currently comply in all material respects with the terms of the credit
agreement we entered into with, among others, an affiliate of one of the
underwriters. Credit Suisse First Boston Corporation decided to

64
<PAGE>

participate in the distribution of the shares in this offering independent of
its affiliate, which is currently a lender to Spinnaker and will receive a
portion of the net proceeds of this offering. Credit Suisse First Boston, New
York Branch, had no involvement in determining whether or when to sell the
shares in this offering or the terms of this offering. Excluding the proceeds
to Credit Suisse First Boston, New York Branch, as previously described, Credit
Suisse First Boston Corporation will not receive any benefit from this offering
other than its portions of the underwriting discounts and commissions described
in this prospectus.

Credit Suisse First Boston Corporation, one of the underwriters for this
offering, is a subsidiary of Credit Suisse Group, which indirectly holds a 19.9
percent passive minority interest in Warburg, Pincus & Co., the general partner
of Warburg, Pincus Ventures, one of our principal stockholders.

We, Warburg, Pincus Ventures, Petroleum Geo-Services and our officers and
directors who own shares of our common stock have agreed not to offer, sell,
contract to sell, pledge or otherwise dispose of, directly or indirectly, or
file with the Securities and Exchange Commission a registration statement under
the Securities Act relating to, any shares of our common stock or securities
convertible into or exchangeable or exercisable for any shares of our common
stock, or publicly disclose the intention to make any such offer, sale, pledge,
disposition or filing, without the prior written consent of Credit Suisse First
Boston Corporation for a period of 90 days after the date of this prospectus,
except, in our case, issuances pursuant to employee benefit plans existing on
the date of this prospectus.

We have agreed to indemnify the underwriters against liabilities under the
Securities Act, or to contribute to payments that the underwriters may be
required to make in that respect.

The underwriters may engage in over-allotment, stabilizing transactions,
syndicate covering transactions and penalty bids in accordance with Regulation
M under the Securities Exchange Act of 1934.

. Over-allotment involves syndicate sales in excess of the offering size,
which creates a syndicate short position.

. Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.

. Syndicate covering transactions involve purchases of the common stock in
the open market after the distribution has been completed in order to
cover syndicate short positions.

. Penalty bids permit the underwriters to reclaim a selling concession
from a syndicate member when the common stock originally sold by the
syndicate member is purchased in a stabilizing or a syndicate covering
transaction to cover syndicate short positions.

These stabilizing transactions, syndicate covering transactions and penalty
bids may cause the price of our common stock to be higher than it would
otherwise be in the absence of these transactions. These transactions may be
effected on the New York Stock Exchange or otherwise and, if commenced, may be
discontinued at any time.

65
<PAGE>

NOTICE TO CANADIAN RESIDENTS

Resale Restrictions

The distribution of the common stock in Canada is being made only on a
private placement basis exempt from the requirement that we prepare and file a
prospectus with the securities regulatory authorities in each province where
trades of common stock are effected. Accordingly, any resale of the common
stock in Canada must be made in accordance with applicable securities laws
which will vary depending on the relevant jurisdiction, and which may require
resales to be made in accordance with available statutory exemptions or
pursuant to a discretionary exemption granted by the applicable Canadian
securities regulatory authority. Purchasers are advised to seek legal advice
prior to any resale of the common stock.

Representations of Purchasers

Each purchaser of common stock in Canada who receives a purchase
confirmation will be deemed to represent to us and the dealer from whom such
purchase confirmation is received that (i) such purchaser is entitled under
applicable provincial securities laws to purchase such common stock without the
benefit of a prospectus qualified under such securities laws, (ii) where
required by law, that such purchaser is purchasing as principal and not as
agent and (iii) such purchaser has reviewed the text above under "Resale
Restrictions."

Rights of Action (Ontario Purchasers)

The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
Ontario securities law. As a result, Ontario purchasers must rely on other
remedies that may be available, including common law rights of action for
damages or rescission or rights of action under the civil liability provisions
of the U.S. federal securities laws.

Enforcement of Legal Rights

All of the issuer's directors and officers as well as the experts named
herein may be located outside of Canada and, as a result, it may not be
possible for Canadian purchasers to effect service of process within Canada
upon the issuer or such persons. All or a substantial portion of the assets of
the issuer and such persons may be located outside of Canada and, as a result,
it may not be possible to satisfy a judgment against the issuer or such persons
in Canada or to enforce a judgment obtained in Canadian courts against such
issuer or persons outside of Canada.

Notice to British Columbia Residents

A purchaser of common stock to whom the Securities Act (British Columbia)
applies is advised that such purchaser is required to file with the British
Columbia Securities Commission a report within ten days of the sale of any
common stock acquired by such purchaser pursuant to this offering. Such report
must be in the form attached to British Columbia Securities Commission Blanket
Order BOR #95/17, a copy of which may be obtained from us. Only one such report
must be filed in respect of common stock acquired on the same date and under
the same prospectus exemption.

Taxation and Eligibility for Investment

Canadian purchasers of common stock should consult their own legal and tax
advisors with respect to the tax consequences of an investment in the common
stock in their particular circumstances and with respect to the eligibility of
the common stock for investment by the purchaser under relevant Canadian
legislation.

66
<PAGE>

LEGAL MATTERS

The validity of the issuance of the shares of common stock offered by this
prospectus will be passed on for us by Vinson & Elkins L.L.P., Houston, Texas.
Certain legal matters relating to the common stock offered by this prospectus
will be passed on by Baker Botts L.L.P., Houston, Texas, as counsel for the
underwriters. Baker Botts L.L.P. has represented and continues to represent
Petroleum Geo-Services in connection with various matters unrelated to this
offering.

EXPERTS

The audited consolidated financial statements included in this prospectus
and elsewhere in the registration statement have been audited by Arthur
Andersen LLP, independent public accountants, as indicated in their report with
respect thereto, and are included herein in reliance upon the authority of said
firm as experts in accounting and auditing in giving said report.

The estimated reserve evaluations and related calculations of Ryder Scott
Company, L.P., independent petroleum engineering consultants, included in this
prospectus have been included in reliance on the authority of said firm as
experts in petroleum engineering.

WHERE YOU CAN FIND MORE INFORMATION

This prospectus is part of a registration statement we filed with the
Securities and Exchange Commission. This prospectus does not contain all of the
information contained in the registration statement and all of the exhibits and
schedules thereto. For further information about Spinnaker Exploration Company,
please see the complete registration statement. Summaries of agreements or
other documents in this prospectus are not necessarily complete. Please refer
to the exhibits to the registration statement for complete copies of such
documents.

We file annual, quarterly and special reports, proxy statements and other
information with the Securities and Exchange Commission under the Securities
Exchange Act of 1934. You may read and copy any document we file at the
following Securities and Exchange Commission public reference rooms:

450 Fifth Street, N.W. Seven World Trade Center Citicorp Center
Judiciary Plaza Suite 1300 500 West Madison Street
Room 1024 New York, NY 10048 Suite 1400
Washington, D.C. 20549 Chicago, IL 60661

You also may inspect and copy our Securities and Exchange Commission
filings, the complete registration statement and other information at the
offices of the New York Stock Exchange located at 20 Broad Street, 16th Floor,
New York, New York 10005.

You may obtain information on the operation of the public reference room in
Washington, D.C. by calling the Securities and Exchange Commission at 1-800-
SEC-0330.

We file information electronically with the Securities and Exchange
Commission. Our Securities and Exchange Commission filings also are available
from the Securities and Exchange Commission's Internet site at
http://www.sec.gov, which contains reports, proxy and information statements,
and other information regarding issuers that file electronically.

67
<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 prospectus. The meanings of the terms
"proved reserves," "proved developed reserves," "proved developed producing
reserves," "proved developed non-producing reserves" and "proved undeveloped
reserves" are provided in Appendix A to this prospectus.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this
prospectus in reference to 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.

68
<PAGE>

Mcf. Thousand cubic feet of natural gas.

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

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

MMBtu. Million British Thermal Units.

MMcf. Million cubic feet of natural gas.

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

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

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.

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.

69
<PAGE>

SPINNAKER EXPLORATION COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants.................................. F-2
Consolidated Balance Sheets as of December 31, 1998 and 1999 and June 30,
2000 (unaudited)......................................................... F-3
Consolidated Statements of Operations for the years ended December 31,
1997, 1998 and 1999 and for the six months ended June 30, 1999
(unaudited) and 2000 (unaudited)......................................... F-4
Consolidated Statements of Equity for the years ended December 31, 1997,
1998 and 1999 and for the six months ended June 30, 2000 (unaudited)..... F-5
Consolidated Statements of Cash Flows for the years ended December 31,
1997, 1998 and 1999 and for the six months ended June 30, 1999
(unaudited) and 2000 (unaudited)......................................... F-6
Notes to Consolidated Financial Statements................................ F-7
</TABLE>

F-1
<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), as of December 31, 1998 and 1999,
and the related consolidated statements of operations, equity and cash flows
for each of the three years in the period ended December 31, 1999. These
financial statements are the responsibility of Spinnaker Exploration 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 as of December 31, 1998 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.

ARTHUR ANDERSEN LLP

Houston, Texas
February 23, 2000

F-2
<PAGE>

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED BALANCE SHEETS

(In thousands, except share data)

<TABLE>
<CAPTION>
As of
December 31, As of
------------------ June 30,
1998 1999 2000
ASSETS -------- -------- -----------
(Unaudited)
<S> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents.................... $ 2,141 $ 20,452 $ 1,392
Accounts receivable.......................... 3,821 10,795 19,014
Other........................................ 775 879 320
-------- -------- --------
Total current assets....................... 6,737 32,126 20,726

PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost
accounting:
Proved properties........................... 71,091 141,455 200,885
Unproved properties and properties under
development, not being amortized........... 28,383 40,696 47,664
Other........................................ 2,798 3,714 4,703
-------- -------- --------
102,272 185,865 253,252
Less--Accumulated depreciation, depletion and
amortization................................ (6,665) (28,468) (46,788)
-------- -------- --------
Total property and equipment............... 95,607 157,397 206,464

OTHER ASSETS:
Organization costs and other, net............ 425 30 30
-------- -------- --------
Total assets............................... $102,769 $189,553 $227,220
======== ======== ========

<CAPTION>
LIABILITIES AND EQUITY
<S> <C> <C> <C>
CURRENT LIABILITIES:
Accounts payable............................. $ 6,471 $ 4,509 $ 5,535
Accrued liabilities.......................... 11,907 7,942 23,090
Short-term debt.............................. 19,000 -- 12,000
-------- -------- --------
Total current liabilities.................. 37,378 12,451 40,625
ACCRUED PREFERRED DIVIDENDS PAYABLE............ 8,478 -- --
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY:
Preferred stock, $0.01 par value; 10,000,000
shares authorized; 3,030,920, 0 and 0 shares
issued and outstanding at December 31, 1998
and 1999 and June 30, 2000, respectively.... 30 -- --
Common stock, $0.01 par value; 50,000,000
shares authorized; 4,082,200 shares issued
and outstanding at December 31, 1998,
20,426,192 shares issued and 20,404,336
shares outstanding at December 31, 1999 and
20,597,035 shares issued and 20,575,675
shares outstanding at June 30, 2000......... 20 204 206
Additional paid-in capital................... 74,649 203,987 205,151
Accumulated deficit.......................... (17,786) (27,034) (18,709)
Less: Treasury stock, at cost, 0, 21,856 and
21,360 shares at
December 31, 1998 and 1999, and June
30, 2000, respectively................. -- (55) (53)
-------- -------- --------
Total equity............................... 56,913 177,102 186,595
-------- -------- --------
Total liabilities and equity............... $102,769 $189,553 $227,220
======== ======== ========
</TABLE>

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

F-3
<PAGE>

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per unit/share data)

<TABLE>
<CAPTION>
For the Six
For the Year Ended Months Ended
December 31, June 30,
-------------------------- ----------------
1997 1998 1999 1999 2000
------- -------- ------- ------- -------
(Unaudited)
<S> <C> <C> <C> <C> <C>
REVENUES........................... $ 201 $ 3,298 $34,258 $ 9,583 $33,012
EXPENSES:
Lease operating expenses......... 72 474 5,411 1,183 3,875
Depreciation, depletion and
amortization--natural gas and
oil properties.................. 68 2,738 20,788 7,619 17,644
Write-down of natural gas and oil
properties...................... -- 2,642 -- -- --
Depreciation and amortization--
other........................... 349 437 213 98 144
General and administrative....... 1,965 3,809 4,860 2,244 3,100
Stock appreciation rights
expense......................... -- -- 1,651 1,651 --
------- -------- ------- ------- -------
Total expenses................. 2,454 10,100 32,923 12,795 24,763
------- -------- ------- ------- -------
INCOME (LOSS) FROM OPERATIONS...... (2,253) (6,802) 1,335 (3,212) 8,249
OTHER INCOME (EXPENSE):
Interest income.................. 91 221 528 85 313
Interest expense................. -- (516) (3,771) (2,007) (254)
Capitalized interest............. -- 237 966 634 17
------- -------- ------- ------- -------
Total other income (expense)... 91 (58) (2,277) (1,288) 76
------- -------- ------- ------- -------
INCOME (LOSS) BEFORE INCOME TAXES.. (2,162) (6,860) (942) (4,500) 8,325
Income tax provision............. -- -- -- -- --
------- -------- ------- ------- -------
INCOME (LOSS) BEFORE CUMULATIVE
EFFECT OF CHANGE IN ACCOUNTING
PRINCIPLE......................... (2,162) (6,860) (942) (4,500) 8,325
Cumulative effect of change in
accounting principle (Note 2)... -- -- (395) (395) --
------- -------- ------- ------- -------
NET INCOME (LOSS).................. (2,162) (6,860) (1,337) (4,895) 8,325
ACCRUAL OF DIVIDENDS ON PREFERRED
UNITS/STOCK....................... (1,326) (7,094) (7,911) (5,088) --
------- -------- ------- ------- -------
NET INCOME (LOSS) AVAILABLE TO
COMMON UNITHOLDERS/STOCKHOLDERS... $(3,488) $(13,954) $(9,248) $(9,983) $ 8,325
======= ======== ======= ======= =======
BASIC INCOME (LOSS) PER COMMON
UNIT/SHARE:
Income (loss) before cumulative
effect of change in accounting
principle....................... $ (0.88) $ (3.44) $ (1.06) $ (2.33) $ 0.41
Cumulative effect of change in
accounting principle............ -- -- (0.05) (0.10) --
------- -------- ------- ------- -------
NET INCOME (LOSS) PER COMMON
UNIT/SHARE........................ $ (0.88) $ (3.44) $ (1.11) $ (2.43) $ 0.41
======= ======== ======= ======= =======
DILUTED INCOME (LOSS) PER COMMON
UNIT/SHARE:
Income (loss) before cumulative
effect of change in accounting
principle....................... $ (0.88) $ (3.44) $ (1.06) $ (2.33) $ 0.39
Cumulative effect of change in
accounting principle............ -- -- (0.05) (0.10) --
------- -------- ------- ------- -------
NET INCOME (LOSS) PER COMMON
UNIT/SHARE........................ $ (0.88) $ (3.44) $ (1.11) $ (2.43) $ 0.39
======= ======== ======= ======= =======
WEIGHTED AVERAGE NUMBER OF COMMON
UNITS/SHARES OUTSTANDING:
Basic............................ 3,960 4,059 8,355 4,113 20,469
======= ======== ======= ======= =======
Diluted.......................... 3,960 4,059 8,355 4,113 21,539
======= ======== ======= ======= =======
</TABLE>

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

F-4
<PAGE>

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF EQUITY

(In thousands, except units/shares and unit/share dividend data)

<TABLE>
<CAPTION>
Units/Shares Par Value Preferred Additional Unitholder/
---------------------- ---------------- 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, 1996......... 198,921 3,960,000 $ -- $ -- $ 54,480 $ 29 $(50,798) $ (344) $ -- $ 3,367
Net loss........ -- -- -- -- -- -- -- (2,162) -- (2,162)
Preferred unit
dividends ($3.00
per preferred
unit)........... -- -- -- -- -- -- -- (1,326) -- (1,326)
Preferred unit
payments........ 760,000 -- -- -- -- -- 19,000 -- -- 19,000
---------- ---------- ---- ---- -------- -------- -------- -------- ---- --------
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
(unaudited)..... -- -- -- -- -- -- -- 8,325 -- 8,325
Exercise of
stock options
(unaudited)..... -- 170,843 -- 2 -- 1,107 -- -- 2 1,111
Stock
compensation
costs
(unaudited)..... -- -- -- -- -- 57 -- -- -- 57
---------- ---------- ---- ---- -------- -------- -------- -------- ---- --------
Balance, June 30,
2000
(unaudited)...... -- 20,597,035 $ -- $206 $ -- $205,151 $ -- $(18,709) $(53) $186,595
========== ========== ==== ==== ======== ======== ======== ======== ==== ========
</TABLE>

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

F-5
<PAGE>

SPINNAKER EXPLORATION COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

<TABLE>
<CAPTION>
For the Six
For the Year Ended Months Ended
December 31, June 30,
---------------------------- -----------------
1997 1998 1999 1999 2000
-------- -------- -------- ------- --------
(Unaudited)
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING
ACTIVITIES:
Net income (loss)........... $ (2,162) $ (6,860) $ (1,337) $(4,895) $ 8,325
Adjustments to reconcile net
income (loss) to net cash
provided by (used in)
operating activities:
Depreciation, depletion
and amortization......... 417 3,175 21,001 7,717 17,788
Write-down of natural gas
and oil properties....... -- 2,642 -- -- --
Stock appreciation rights
expense.................. -- -- 1,651 1,651 --
Cumulative effect of
change in accounting
principle................ -- -- 395 395 --
Change in components of
working capital:
Accounts receivable....... (3,593) (218) (6,974) (6,870) (8,219)
Accounts payable and
accrued liabilities...... (63) (896) (636) 5,725 4,158
Other current assets and
other.................... (122) (619) 805 785 616
-------- -------- -------- ------- --------
Net cash provided by
(used in) operating
activities............. (5,523) (2,776) 14,905 4,508 22,668
CASH FLOWS FROM INVESTING
ACTIVITIES:
Oil and gas properties...... (13,638) (84,823) (78,894) (33,265) (67,248)
Change in property related
payables................... 342 17,178 (5,291) (14,098) 12,016
Purchases of other property
and equipment.............. (1,940) (858) (916) (310) (989)
Proceeds from sale of
pipeline................... -- -- -- -- 1,382
-------- -------- -------- ------- --------
Net cash used in
investing activities... (15,236) (68,503) (85,101) (47,673) (54,839)

CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from borrowings.... -- 19,000 53,000 45,000 12,000
Payments on borrowings...... -- -- (72,000) -- --
Proceeds from issuance of
common stock............... -- -- 108,720 -- --
Common stock issuance
costs...................... -- -- (1,109) -- --
Preferred stock dividends... -- -- (78) -- --
Proceeds from exercise of
stock options.............. -- -- 29 -- 1,111
Acquisition of treasury
stock...................... -- -- (55) -- --
Proceeds from issuance of
preferred stock, net....... -- 51,738 -- -- --
Preferred unit subscription
payments, net.............. 18,863 -- -- -- --
-------- -------- -------- ------- --------
Net cash provided by
financing activities... 18,863 70,738 88,507 45,000 13,111
-------- -------- -------- ------- --------
NET INCREASE (DECREASE) IN
CASH AND CASH EQUIVALENTS.... (1,896) (541) 18,311 1,835 (19,060)
CASH AND CASH EQUIVALENTS,
beginning of period.......... 4,578 2,682 2,141 2,141 20,452
-------- -------- -------- ------- --------
CASH AND CASH EQUIVALENTS, end
of period.................... $ 2,682 $ 2,141 $ 20,452 $ 3,976 $ 1,392
======== ======== ======== ======= ========
SUPPLEMENTAL CASH FLOW
DISCLOSURES:
Cash paid for interest, net
of amounts capitalized..... $ -- $ 84 $ 2,591 $ 1,196 $ 69
Cash paid for income taxes.. -- -- -- -- --

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 2,900 --
</TABLE>

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

F-6
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization, Nature of Operations and Formation:

Organization and Nature of Operations

Spinnaker Exploration Company, L.L.C. ("Spinnaker"), a Delaware limited
liability company, was formed on December 20, 1996, and is engaged in the
exploration, development and production of natural gas and oil properties in
the U.S. Gulf of Mexico. 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").

Formation

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 151,746 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. 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. See Note 4. Management purchased 160,000 Common Units and agreed
to subscriptions on Preferred Units of up to $798,000 at $25.00 per unit of
which 2,352 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.
Upon completion of the formation, beneficial ownership of the Common Units was
71%, 25% and 4% for PGS, Warburg, and management, respectively. 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 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 ("Spinnaker" or the "Company"). As a
part of the change in entity, SEHI was issued an additional 97,200 shares of
Common Stock.

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,

F-7
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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.

2. Summary of Significant Accounting Policies:

General

The accompanying consolidated financial statements of Spinnaker Exploration
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").

Interim Financial Data

The unaudited consolidated financial statements as of June 30, 2000, and for
the six-month periods ended June 30, 1999 and 2000, and all related footnote
information for these periods have been prepared on the same basis as the
audited financial statements and, in the opinion of management, include all
adjustments, consisting of normal recurring adjustments, necessary for a fair
presentation of financial position, results of operations and cash flows in
accordance with accounting principles generally accepted in the United States
and pursuant to the rules and regulations of 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 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.

Other Current Assets

Other current assets includes debt financing costs of $465,000 and $242,000
at December 31, 1998 and 1999, respectively, related to the $85 million and $25
million credit agreements, which are amortized to interest expense over the
term of the related credit agreements. Amortization included in interest
expense was $116,000 and $576,000 for the years ended December 31, 1998 and
1999, respectively. See Note 3.

F-8
<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 finding 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 $1.3 million, $2.5
million and $2.5 million of internal costs in 1997, 1998 and 1999,
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 depreciation, depletion and
amortization ("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%, 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 periodically assessed for possible impairments or reduction in value. If a
reduction in value has occurred, costs being amortized are increased. Of the
$40.7 million of net unproved property costs at December 31, 1999 excluded from
the amortizable base, $5.7 million, $22.7 million and $12.3 million were
incurred in 1997, 1998 and 1999, 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.

F-9
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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 each of the years ended December 31, 1997 and 1998, was $126,000 and
$132,000, respectively.

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 Other assets and over-deliveries are included in Other liabilities.

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. Accordingly, no recognition has been given to income taxes in the
accompanying 1997 financial statements.

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 Notes 1 and 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
units/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 Hedging Activities

The Company's financial instruments consist of cash and cash equivalents,
receivables, payables and debt. The carrying amount of cash and cash
equivalents, receivables, payables and debt approximates fair value because of
the short-term nature of these items.

F-10
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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
approximately $751,000 of net hedging income during 1999. The Company's
costless collars mature monthly through October 2000. The estimated fair value
of the open collar arrangements in place at December 31, 1999 was an unrealized
gain of approximately $968,000.

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 Company's 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, oil and
natural gas liquids. 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 crude 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
since formation, 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. Spinnaker
is also dependent upon the continued success of an exploratory drilling program
and its ability to realize value from its Data Agreement. See Note 4.

New Accounting Policies

In June 1998, the FASB 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.
The SFAS 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 gains 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--

F-11
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

An Amendment of FASB Statement No. 133" extended implementation to fiscal
years beginning after June 15, 2000. Early adoption is permitted. The Company
believes SFAS No. 133 will not have a significant impact on the consolidated
financial statements.

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. On a semi-annual basis, the
Company's proved reserves were required to be evaluated to re-determine the
borrowing base. If the borrowing base increased, the guarantees were
permanently decreased dollar for dollar. If payments were made under a
guarantee, the balance due to the guarantor was immediately and automatically
converted into equity of the Company at a rate of $15.00 per share.

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% in 1998 and 5.54% in 1999. The weighted average
interest rate for the borrowing base tranche was 8.23% in 1998 and 7.45% in
1999. The overall weighted average interest rate for borrowings outstanding
under the Credit Agreement was 6.54% in 1998 and 5.71% in 1999.

Borrowings outstanding under the Credit Agreement as of October 4, 1999
were $72.0 million, of which $67.0 million was guaranteed by PGS and Warburg.
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, as described below.

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 contained certain covenants and restrictive
provisions, including limitations on the incurrence of additional debt or
liens, the sales of property, the declaration or payment of dividends and the
repurchase or redemption of capital stock, and the maintenance of certain
financial ratios.

On October 4, 1999, with proceeds from the initial public offering, the
Company paid all outstanding borrowings of $72.0 million.

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 $25.0 million Amended and Restated 364-Day Credit Agreement
("Amended Credit Agreement") among the Company, Bank of Montreal and Credit
Suisse First Boston matures on October 26, 2000. The Company may borrow only
up to the borrowing base, which is currently $16.0 million. On a semi-annual
basis, the Company's proved reserves are required to be evaluated to re-
determine the borrowing base. The Amended Credit Agreement contains covenants
and restrictive provisions, including the following limitations, subject to
some exceptions, where the Company:

. may not incur any other indebtedness from borrowings, except for
indebtedness of up to $1.0 million and indebtedness owed to guarantors of
the Amended Credit Agreement;

F-12
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

. may not incur any liens upon properties or assets other than permitted
liens securing indebtedness of up to $1.0 million, pledges or deposits to
secure hedging agreements up to $5.0 million and other liens in the
ordinary course of business;

. may not enter into any amalgamation or merger unless it is the survivor
and no default exists;

. may not dispose of all or substantially all property, business or assets;

. may not dispose of any properties valued in the borrowing base except
obsolete equipment, inventory sold in the ordinary course of business,
some interests in natural gas and oil properties included in the
borrowing base in an aggregate amount not to exceed $500,000 between the
borrowing base determination and non-proved reserves;

. may not make or pay any dividend, distribution or payment in respect of
capital stock nor purchase, redeem, retire, or permit any reduction or
retirement of capital stock;

. must maintain the ratio of consolidated current assets as of the end of
each fiscal quarter to consolidated current liabilities other than debt
under the Amended Credit Agreement as of the end of such fiscal quarter
so that it is not less than 1.00 to 1.00;

. may not enter into any hedging agreement unless the Company meets
specified requirements including limits on the aggregate amounts maturing
in any month under any floor hedging contracts and under any forward
sales transactions.

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 $59,000, $122,000 and $318,000 in 1997, 1998 and 1999,
respectively, and $138,000 in the six months ended June 30, 2000 (unaudited),
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.

F-13
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

On January 6, 1998, concurrent with the formation of Spinco, Spinco
authorized 3,030,920 shares of Preferred Stock with a par value of $.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%
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% 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% 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 compound quarterly would
have increased to an annual rate of 20% after December 31, 2006. At December
31, 1998, accrued dividends on the Preferred Stock were $8.5 million. Dividends
were payable in 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 a seismic data contribution
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.

F-14
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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 $.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.

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. Unit/Stock Option Agreements:

On December 27, 1996, Spinnaker adopted its unit option plan, authorizing
nonqualified options for the benefit of Spinnaker's officers and other key
employees to acquire up to 2,480,000 Common Units, 1,520,000 at $5.00 per
Common Unit and 960,000 at $15.63 per Common Unit. The maximum period for
exercise of an option may not be more than ten years from the date of grant.
Options granted vest and become exercisable in general at dates determined by
the compensation committee, subject to the specific terms of the individual
option agreements.

On January 6, 1998, the unit options in the unit option plan were exchanged
for stock options in Spinco. In connection with the exchange, all benefits,
rights and obligations of the unit options were transferred to the stock
options. In August 1998, the Company authorized additional options for the
benefit of Spinnaker's officers and other key employees to acquire up to 3,040
shares of Common Stock at $5.00 per share and 356,920 shares of Common Stock at
$15.63 per share.

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 zero for 1997 and 1998,
respectively, and $150,000 for 1999. 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
loss available to common unitholders/stockholders and loss per common
unit/share would have been as follows (in thousands, except per share amounts):

<TABLE>
<CAPTION>
For the Year Ended
December 31,
---------------------------
1997 1998 1999
------- -------- --------
<S> <C> <C> <C>
Pro forma net loss available to common
unitholders/stockholders........................ $(3,517) $(14,172) $(10,950)
======= ======== ========
Pro forma net loss per basic and diluted common
unit/share...................................... $ (0.89) $ (3.49) $ (1.31)
======= ======== ========
</TABLE>

F-15
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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 weighted average assumptions for grants in 1997, 1998 and 1999
which, among others, include the following:

<TABLE>
<CAPTION>
For the Year Ended December
31,
-----------------------------
1997 1998 1999
----- ----------- -----------
<S> <C> <C> <C>
Risk-free interest rate........................... 6.89% 4.96%-5.96% 4.67%-6.08%
Volatility factor................................. 0% 0% 54.8%
Dividend yield.................................... 0% 0% 0%
Expected life of the options (years).............. 10 10 4.5
</TABLE>

Presented below is a summary of stock option activity.

<TABLE>
<CAPTION>
Number of Weighted
Shares Average
Under Exercise Price
Option Per Share
--------- --------------
<S> <C> <C>
Outstanding options at December 31, 1996.............. 1,388,800 $ 9.12
Granted............................................. 809,200 9.09
---------
Outstanding options at December 31, 1997.............. 2,198,000 9.10
Granted............................................. 328,880 9.13
---------
Outstanding options at December 31, 1998.............. 2,526,880 9.11
Granted............................................. 866,574 14.74
Exercised........................................... (5,872) 4.97
Canceled............................................ (4,608) 9.29
---------
Outstanding options at December 31, 1999.............. 3,382,974 $10.56
=========
Exercisable, December 31,
1997................................................ 717,360 $ 9.11
1998................................................ 1,222,736 $ 9.11
1999................................................ 1,919,019 $ 9.62
</TABLE>

At December 31, 1999, the following options were outstanding and exercisable
and had the indicated weighted average remaining contractual lives:
<TABLE>
<CAPTION>
Outstanding Exercisable
------------------------- ------------------------
Weighted
Weighted Weighted Range of Average
Average Average Exercise Remaining
Number of Exercise Price Number of Exercise Price Prices Per Contractual
Options Per Share Options Per Share Share Life (Years)
--------- -------------- --------- -------------- -------------- ------------
<S> <C> <C> <C> <C> <C>
1,536,400 $ 4.96 1,067,528 $ 4.98 $ 2.50--$ 5.00 7.2
1,846,574 $15.21 851,491 $15.44 $14.50--$15.63 8.4
</TABLE>

Stock option grants vest ratably over four years, with 20% vesting on the
date of grant and 20% vesting in each of the succeeding four years. Stock
options vest fully in the event of a change in control of the Company.

Additionally, 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.

F-16
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

7. Earnings Per Unit/Share:

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

<TABLE>
<CAPTION>
For the Six
For the Year Ended Months Ended
December 31, June 30,
-------------------------- ---------------
1997 1998 1999 1999 2000
------- -------- ------- ------- ------
(Unaudited)
<S> <C> <C> <C> <C> <C>
Numerator:
Net income (loss) available to
common unitholders/stockholders... $(3,488) $(13,954) $(9,248) $(9,983) $8,325
======= ======== ======= ======= ======
Denominator:
Basic earnings per unit/share--
weighted average units/shares..... 3,960 4,059 8,355 4,113 20,469
======= ======== ======= ======= ======
Dilutive securities:
Unit/stock options............... -- -- -- -- 1,070
Preferred units/stock............ -- -- -- -- --
------- -------- ------- ------- ------
Dilutive potential common
unit/shares....................... -- -- -- -- 1,070
------- -------- ------- ------- ------
Diluted earnings per unit/share--
adjusted weighted average
units/shares and assumed
conversions....................... 3,960 4,059 8,355 4,113 21,539
======= ======== ======= ======= ======
Net income (loss) per common
unit/share:
Basic:
Income (loss) before cumulative
effect of change in accounting
principle....................... $ (0.88) $ (3.44) $ (1.06) $ (2.33) $ 0.41
Cumulative effect of change in
accounting principle............ -- -- (0.05) (0.10) --
------- -------- ------- ------- ------
Net income (loss) per common
unit/share........................ $ (0.88) $ (3.44) $ (1.11) $ (2.43) $ 0.41
======= ======== ======= ======= ======
Diluted:
Income (loss) before cumulative
effect of change in accounting
principle....................... $ (0.88) $ (3.44) $ (1.06) $ (2.33) $ 0.39
Cumulative effect of change in
accounting principle............ -- -- (0.05) (0.10) --
------- -------- ------- ------- ------
Net income (loss) per common
unit/share........................ $ (0.88) $ (3.44) $ (1.11) $ (2.43) $ 0.39
======= ======== ======= ======= ======
</TABLE>

For purposes of the diluted earnings per unit/share calculation, the
Preferred Units/Stock and unit/stock options are considered anti-dilutive and
are therefore not considered in the above calculation for the years ended
December 31, 1997, 1998 and 1999 and for the six months ended June 30, 1999.

8. Major Customers:

The Company had natural gas and oil sales to one customer accounting for
100% of total natural gas and oil revenues for the years ended December 31,
1997 and 1998, respectively. The Company had natural gas and oil revenues to
two customers, accounting for 68% and 32%, respectively, of total natural gas
and oil revenues for the year ended December 31, 1999.

F-17
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

9. Related-Party Transactions:

As part of the Company's formation, SEHI agreed to transfer limited rights
to 3-D seismic data to Spinnaker in exchange for issuing Common Units to SEHI.
See Note 4. The Common Units were exchanged for shares of Common Stock upon the
formation of Spinco. Additionally, the Company paid to PGS approximately
$59,000, $122,000 and $318,000 in 1997, 1998 and 1999, respectively, and
$138,000 in the six months ended June 30, 2000 (unaudited), for seismic-related
services.

The Data Agreement was amended effective June 30, 1999. In exchange for the
amended rights under the Data Agreement, Spinnaker issued to PGS an additional
1,000,000 shares of Common Stock. 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
operating income as the Company has not established a history of net operating
income. Net operating loss carryforwards of $23.0 million and $3.6 million
expire in 2018 and 2019, respectively.

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

<TABLE>
<CAPTION>
At December 31,
-----------------
1998 1999
-------- -------
<S> <C> <C>
Deferred income tax liabilities:
Basis differences in natural gas and oil
properties........................................ $ 20,193 $ 9,063
Other.............................................. 138 56
-------- -------
Total deferred income tax liabilities............ 20,331 9,119

Deferred income tax assets:
Net operating losses............................... 20,789 9,304
Other.............................................. 274 414
-------- -------
Total deferred income tax assets................. 21,063 9,718
Valuation allowance.................................. (732) (599)
-------- -------
Net deferred income tax assets....................... 20,331 9,119
-------- -------
Net deferred income tax liabilities.................. $ -- $ --
======== =======
</TABLE>

F-18
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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% to
the loss before income taxes is analyzed as below (in thousands):

<TABLE>
<CAPTION>
For the Year
Ended
December 31,
--------------
1998 1999
------- -----
<S> <C> <C>
Federal income tax benefit at statutory rates............ $(2,400) $(468)
Non-deductible compensation expense ..................... -- 558
Increase in non-deductible expenses and other............ -- 43
Increase resulting from change in tax status............. 1,668 --
Valuation allowance...................................... 732 (133)
------- -----
Total provision........................................ $ -- $ --
======= =====
</TABLE>

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.

Seismic Data Agreement

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
$59,000, $122,000 and $318,000 in 1997, 1998 and 1999, respectively, and
$138,000 in the six months ended June 30, 2000 (unaudited), for seismic-related
services.

Employment Contracts

As of December 31, 1997, 1998 and 1999, the Company had employment contracts
with its chief executive officer and chief financial officer which provide for
annual base salaries, bonus compensation and various benefits. The contracts
provide for the continuation of salary and benefits for the greater of the
balance of the respective initial terms of the agreements and one year in the
event the Company terminates the employee prior to the expiration of the
initial term without cause or the employee terminates employment prior to the
expiration of the initial term for good reason. These agreements initially
expire on December 31, 2000, but are subject to automatic annual extensions
unless terminated. Compensation expense pertaining to officers of the Company
is charged to general and administrative expense.

Employee 401(k) Retirement Plan

In July 1998, the Company instituted a 401(k) retirement and profit sharing
plan ("Plan") for its employees. The Plan provides that all qualified employees
may defer the maximum income allowed under current tax law. The Plan covers all
employees at least 21 years of age who have completed at least six months of
service subsequent to employment. The Company may make discretionary
contributions allocated to eligible participants. No discretionary
contributions were made in 1998 and 1999.

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

F-19
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

expenses of the building. Additionally, the leases contain escalation clauses.
Minimum future obligations under non-cancelable operating leases at December
31, 1999 for the following five years are $435,000, $444,000, $190,000, $12,000
and $11,000, respectively.

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
For the Year Six
Ended December Months
31, Ended
---------------- June 30,
1998 1999 1999
------- ------- --------
(Pro Forma)
<S> <C> <C> <C>
Revenues............................................ $ 3,298 $34,258 $ 9,583
Expenses............................................ 10,100 32,923 12,795
------- ------- -------
Income (loss) from operations....................... (6,802) 1,335 (3,212)
Other income (expense).............................. 458 (269) (258)
------- ------- -------
Income (loss) before income taxes................... (6,344) 1,066 (3,470)
Income tax provision.............................. -- -- --
------- ------- -------
Income (loss) before cumulative effect of change in
accounting principle............................... (6,344) 1,066 (3,470)
Cumulative effect of change in accounting
principle........................................ -- (395) (395)
------- ------- -------
Pro forma net income (loss)......................... $(6,344) $ 671 $(3,865)
======= ======= =======
Pro forma basic income (loss) per common share:
Income (loss) before cumulative effect of change
in accounting principle.......................... $ (0.45) $ 0.05 $ (0.19)
Cumulative effect of change in accounting
principle........................................ -- (0.02) (0.02)
------- ------- -------
Pro forma net income (loss) per common share........ $ (0.45) $ 0.03 $ (0.21)
======= ======= =======
Pro forma diluted income (loss) per common share:
Income (loss) before cumulative effect of change
in accounting principle.......................... $ (0.45) $ 0.05 $ (0.19)
Cumulative effect of change in accounting
principle........................................ -- (0.02) (0.02)
------- ------- -------
Pro forma net income (loss) per common share........ $ (0.45) $ 0.03 $ (0.21)
======= ======= =======
Pro forma weighted average number of common shares
outstanding:
Basic............................................. 14,078 19,274 18,773
======= ======= =======
Diluted........................................... 14,078 19,926 18,773
======= ======= =======
</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

F-20
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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 condensed consolidated statement of operations for the six
months ended June 30, 1999 reflects adjustments of approximately $1.7 million
and $634,000 to eliminate interest expense and capitalized interest as a result
of the retirement of all outstanding debt and $5.1 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 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.

13. Quarterly Financial Data (Unaudited):

Quarterly operating results for the years ended December 31, 1998 and 1999
are summarized as follows (in thousands, except per share amounts):

<TABLE>
<CAPTION>
For the Quarter Ended
----------------------------------------------
March 31, June 30, September 30, December 31,
--------- -------- ------------- ------------
(Unaudited)
<S> <C> <C> <C> <C>
1998:
Revenues....................... $ 249 $ 712 $ 603 $ 1,734
Loss from operations........... (1,015) (2,002) (470) (3,315)
Net loss....................... (959) (1,925) (426) (3,550)
Net loss available to common
stockholders.................. (1,854) (3,528) (2,549) (6,023)
Net loss per basic and diluted
common share.................. $ (0.46) $ (0.87) $ (0.63) $ (1.48)

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) $ (1.48) $ 0.16
</TABLE>

The fourth quarter of 1998 includes a write-down of natural gas and oil
properties of $2.6 million. 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 of the Company's officers' stock option agreements.
See Note 6. The 1998 and first two quarters of 1999 net loss per share amounts
have been retroactively adjusted for the Stock Split.

For purposes of the diluted earnings per share calculation, the Preferred
Stock and stock options are considered anti-dilutive and are therefore not
considered in the net loss per share calculations.

F-21
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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>
For the Year
Ended December 31,
------------------
1998 1999
-------- --------
<S> <C> <C>
Capitalized costs:
Proved properties......... $71,091 $141,455
Unproved properties not
being amortized.......... 28,383 40,696
------- --------
Total................... 99,474 182,151
Accumulated depreciation,
depletion and
amortization............... (5,448) (26,236)
------- --------
Net capitalized costs... $94,026 $155,915
======= ========
</TABLE>

<TABLE>
<CAPTION>
For the Year Ended
December 31,
-----------------------
1997 1998 1999
------- ------- -------
<S> <C> <C> <C>
Property acquisition costs:
Unproved....................................... $ 4,458 $15,791 $13,911
Proved......................................... -- -- --
Exploration costs(a)............................. 7,116 46,620 45,152
Development costs(b)............................. 2,422 23,067 23,614
------- ------- -------
Total costs incurred......................... $13,996 $85,478 $82,677
======= ======= =======
</TABLE>
--------
(a) Includes seismic data acquisitions of $1.4 million, $2.5 million and $10.5
million in 1997, 1998 and 1999, respectively.

(b) Includes costs of completions, platforms, facilities and pipelines
associated with exploratory wells.

Estimates of Proved Natural Gas and Oil Reserves

Proved natural gas and oil reserve quantities at December 31, 1997, 1998 and
1999, 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.

F-22
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

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 summarized below:

<TABLE>
<CAPTION>
Millions of Cubic
Feet of Natural Gas
at December 31,
-----------------------
1997 1998 1999
------ ------ -------
<S> <C> <C> <C>
Proved developed and undeveloped reserves--
Beginning of year.................................... -- 12,607 50,946
Extensions and discoveries......................... 12,677 40,014 43,270
Revisions of previous estimates.................... -- -- 7,776
Production......................................... (70) (1,675) (11,962)
------ ------ -------
End of year.......................................... 12,607 50,946 90,030
====== ====== =======
Proved developed reserves at the end of year........... 5,615 30,806 50,756
====== ====== =======
</TABLE>

<TABLE>
<CAPTION>
Barrels of Oil,
Condensate and Natural
Gas Liquids at
December 31,
---------------------------
1997 1998 1999
------- ------- ---------
<S> <C> <C> <C>
Proved developed and undeveloped reserves--
Beginning of year................................ -- 125,128 470,023
Extensions and discoveries..................... 125,230 356,982 2,039,245
Revisions of previous estimates................ -- -- 82,981
Production..................................... (102) (12,087) (180,417)
------- ------- ---------
End of year...................................... 125,128 470,023 2,411,832
======= ======= =========
Proved developed reserves at the end of year....... 46,122 318,087 384,276
======= ======= =========
</TABLE>

Standardized Measure

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

<TABLE>
<CAPTION>
For the Year Ended
December 31,
---------------------------
1997 1998 1999
------- -------- --------
<S> <C> <C> <C>
Future cash inflows.............................. $31,086 $ 99,436 $275,539
Future operating expenses........................ (1,460) (16,562) (36,396)
Future development costs......................... (6,424) (18,059) (48,717)
------- -------- --------
Future net cash flows............................ 23,202 64,815 190,426
10% annual discount per annum.................... (4,221) (12,706) (38,862)
------- -------- --------
Standardized measure of discounted future net
cash flows (a).................................. $18,981 $ 52,109 $151,564
======= ======== ========
</TABLE>
--------
(a) Net operating loss carryforwards and basis in natural gas and oil
properties have eliminated the requirement for future income taxes.

Future cash flows are computed by applying year-end prices of natural gas
and oil to year-end quantities of proved natural gas and oil reserves. Future
operating expenses and development costs are computed primarily by the
Company's petroleum engineers by estimating the expenditures to be incurred in
developing and producing the proved natural gas and oil reserves at the end of
the year, based on the year-end costs and

F-23
<PAGE>

SPINNAKER EXPLORATION COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)

assuming continuation of existing economic conditions. Future income taxes are
based on year-end statutory rates, adjusted for tax basis and applicable tax
credits. A discount factor of 10% was used to reflect the timing of future net
cash flows. The standardized measure of discounted future net cash flows is not
intended to represent the replacement cost or fair market value of the
Company's natural gas and oil properties. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs, and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.

Changes in Standardized Measure

Changes in the standardized measure of future net cash flows relating to
proved natural gas and oil reserves are summarized below (in thousands):

<TABLE>
<CAPTION>
For the Year Ended
December 31,
--------------------------
1997 1998 1999
------- ------- --------
<S> <C> <C> <C>
Standardized measure, beginning of year............ $ -- $18,981 $ 52,109
Extensions and discoveries, net of related
costs........................................... 19,110 35,952 75,572
Sales of natural gas and oil produced, net of
production costs................................ (129) (2,824) (28,097)
Net changes in prices and production costs....... -- (4,329) 22,869
Change in future development costs............... -- 2,713 (1,957)
Development costs incurred during the period that
reduced future development costs................ -- 2,246 14,494
Revisions of quantity estimates.................. -- -- 13,624
Accretion of discount............................ -- 1,898 5,211
Change in production rates and other............. -- (2,528) (2,261)
------- ------- --------
Standardized measure, end of year.................. $18,981 $52,109 $151,564
======= ======= ========
</TABLE>

Sales of natural gas and oil, net of related operating expenses, are based
on historical pre-tax results. Sales of natural gas and oil properties,
extensions and discoveries, purchases of minerals in place and the changes due
to revisions in standardized variables are reported on a pretax discounted
basis, while the accretion of discount is presented on an after-tax basis.

15. Subsequent Event (Subsequent to the date of the auditor's examination and
unaudited):

On July 20, 2000, the Company entered into a credit agreement whereby TD
Securities (USA) Inc. ("TDSI") and Credit Suisse First Boston ("CSFB") have
agreed to provide the Company with a $75.0 million credit facility (the "New
Credit Facility") with an initial borrowing base of $40.0 million and an
original term of 364 days. The New Credit Facility, which will be used for
repayment of borrowings under the existing credit agreement, general corporate
purposes including working capital purposes and for the acquisition,
exploration, development and production of natural gas and oil properties,
including the acquisition of natural gas and oil interests, will replace the
$25.0 million Amended Credit Agreement scheduled to mature in October 2000. At
June 30, 2000, the Company had outstanding borrowings of $12.0 million under
the Amended Credit Agreement.

F-24
<PAGE>

[RYDER SCOTT COMPANY LOGO]
July 24, 2000

Spinnaker Exploration Company
1200 Smith Street, Suite 800
Houston, Texas 77002

Gentlemen:

At your request, we have prepared an estimate of the proved reserves, future
production, and income attributable to certain leasehold and royalty interests
of Spinnaker Exploration Company (Spinnaker) as of June 30, 2000. The subject
properties are located in the federal waters offshore Louisiana and in the
state and federal waters offshore Texas. The income data were estimated using
the Securities and Exchange Commission (SEC) guidelines for future price and
cost parameters.

The estimated proved reserves and future income amounts presented in this
report are related to hydrocarbon prices. June 30, 2000 hydrocarbon prices were
used in the preparation of this report as required by SEC guidelines; however,
actual future prices may vary significantly from June 30, 2000 prices.
Therefore, volumes of reserves actually recovered and amounts of income
actually received may differ significantly from the estimated quantities
presented in this report. The results of this study are summarized below.

SEC PARAMETERS
Estimated Net Reserves and Income Data
Certain Leasehold and Royalty Interests of
Spinnaker Exploration Company
As of June 30, 2000

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

<TABLE>
<CAPTION>
Proved
----------------------------------------------------
Developed
--------------------------
Producing Non-Producing Undeveloped Total Proved
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
Net Remaining Reserves
Oil/Condensate--
Barrels................ 220,208 116,107 1,925,304 2,261,619
Gas--MMCF............... 31,183 16,930 61,387 109,500
Income Data
Future Gross Revenue.... $148,551,259 $80,878,604 $341,087,081 $570,516,944
Deductions.............. 12,391,633 9,725,236 69,415,582 91,532,451
------------ ----------- ------------ ------------
Future Net Income
(FNI).................. $136,159,626 $71,153,368 $271,671,499 $478,984,493
Discounted FNI @ 10%.... $124,855,680 $58,072,891 $210,051,307 $392,979,878
</TABLE>

Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are sales gas expressed in millions of cubic feet (MMCF) at the
official temperature and pressure bases of the areas in which the gas reserves
are located.

A-1
<PAGE>

The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs, development costs, certain gas, oil and
condensate processing and transportation fees which are shown as "other"
deductions, and certain abandonment costs net of salvage. The future net income
is before the deduction of state and federal income taxes and general
administrative overhead, and has not been adjusted for outstanding loans that
may exist nor does it include any adjustment for cash on hand or undistributed
income. No attempt was made to quantify or otherwise account for any
accumulated gas production imbalances that may exist. Gas reserves account for
approximately 87 percent and liquid hydrocarbon reserves account for the
remaining 13 percent of total future gross revenue from proved reserves.

The discounted future net income shown on the previous page was calculated
using a discount rate of 10 percent per annum compounded monthly. This
discounted future net income should not be construed as our estimate of fair
market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletins. The definitions
of proved reserves is included in the section entitled "Reserve Definitions"
which is attached with this report.

The proved developed non-producing reserves included herein are comprised of
the shut-in and behind pipe categories. The various reserve status categories
are defined in the section entitled "Reserve Status Categories" which is
attached with this report.

Estimates of Reserves

In general, the proved producing reserves included herein were estimated by
performance methods which utilized various extrapolations of historical
production and pressure data available through June 2000; however, certain of
the producing reserves were estimated by the volumetric method in those cases
where there were inadequate historical performance data to establish a
definitive trend and where the use of production performance data as a basis
for the reserve estimates was considered to be inappropriate. The proved non-
producing and undeveloped reserves included herein were estimated by the
volumetric method which utilized all pertinent wells and 3-D seismic data
available through June 2000.

The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.

Future Production Rates

Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. Where applicable the estimated future
production rates were held constant until a decline in ability to produce was
anticipated. An estimated rate of decline was then applied to depletion of the
reserves. For reserves not yet on production, sales were estimated to commence
at an anticipated date furnished by Spinnaker.

The future production rates from the wells and locations included herein may
be more or less than estimated because of changes in market demand or
allowables set by regulatory bodies. Wells or locations which are not currently
producing may start producing earlier or later than anticipated in our
estimates of their future production rates.

A-2
<PAGE>

Hydrocarbon Prices

Spinnaker furnished us with prices in effect at June 30, 2000 and these
prices were held constant throughout the life of the properties. These prices
were $4.369 per MMBTU of gas at Henry Hub, Louisiana, and $32.50 per barrel at
the Cushing NYMEX Pricing Hub based on light sweet crude on June 30, 2000. The
product prices used for each property reflect adjustments to these initial
prices for BTU content, liquid gravity and quality, local conditions, and/or
distance from market. Certain additional gas, oil and condensate processing and
transportation fees are included in this report as costs and are shown as
"other" deductions. In accordance with Securities and Exchange Commission
guidelines, changes in liquid and gas prices subsequent to June 30, 2000 were
not taken into account in this report. Future prices used in this report are
discussed in more detail in the section entitled "Hydrocarbon Pricing
Parameters" which is attached with this report.

Costs

The operating costs for the producing wells included herein were based on
the operating expense reports of Spinnaker since the inception of production.
The estimates of future operating costs furnished by Spinnaker for the non-
producing and undeveloped wells and locations included herein were accepted as
reasonable. The estimates of future operating costs include only those costs
directly applicable to the leases and wells. When applicable, the operating
costs include a portion of general and administrative costs allocated directly
to the leases and wells under terms of operating agreements. No deduction was
made for indirect costs such as general administration and overhead expenses,
loan repayments, interest expenses, and exploration and development prepayments
that are not charged directly to the leases or wells.

Development costs were furnished to us by Spinnaker and are based on
authorizations for expenditure for the proposed work or actual costs for
similar projects. Certain gas, oil and condensate processing and transportation
fees are included in this report as "other" deductions. The estimated net cost
of abandonment after salvage was included for the offshore properties included
herein where abandonment costs net of salvage are significant. The estimates of
the net abandonment costs furnished by Spinnaker were accepted without
independent verification.

Current costs were held constant throughout the life of the properties.

General

The estimates of reserves presented herein were based upon a detailed study
of the properties in which Spinnaker owns an interest; however, we have not
made any field examination of the properties. No consideration was given in
this report to potential environmental liabilities which may exist nor were any
costs included for potential liability to restore and clean up damages, if any,
caused by past operating practices. Spinnaker has informed us that they have
furnished us all of the accounts, records, geological and engineering data, and
reports and other data required for this investigation. The ownership
interests, prices, and other factual data furnished by Spinnaker were accepted
without independent verification. The estimates presented in this report are
based on data available through June 2000.

While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were omitted from consideration in making this evaluation.

A-3
<PAGE>

Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation
is contingent on our estimates of reserves and future income for the subject
properties.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

/s/ John E. Hodgin
-------------------------------------
John E. Hodgin, C.P.G.
Executive Vice President--Geoscience
JEH/plk

Approved:

/s/ Don P. Roesle, P.E.
-------------------------------
Don P. Roesle, P.E.
President and Chief Operating Officer

A-4
<PAGE>

HYDROCARBON PRICING PARAMETERS

Securities and Exchange Commission Parameters

Oil and Condensate

Spinnaker furnished us with oil and condensate prices in effect at June 30,
2000 and these prices were held constant to depletion of the properties. In
accordance with the Securities and Exchange Commission guidelines, changes in
liquid prices subsequent to June 30, 2000 were not considered in this report.
Product prices which were actually used for each property reflect adjustment
for gravity, quality, local conditions, and/or distance from market.

Gas

Spinnaker furnished us with gas prices in effect at June 30, 2000. The
prices used herein have been adjusted for the BTU content, local conditions,
and/or distance from market. In accordance with SEC guidelines, the future gas
prices used in this report make no allowances for future gas price increases
which may occur as a result of inflation nor do they make any allowance for
seasonal variations in gas prices which may cause future yearly average gas
prices to differ somewhat from the June 30, 2000 gas prices used herein.

RESERVE DEFINITIONS

Introduction

Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at
the time of the estimate and the interpretation of these data.

Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage or processing losses if required for financial reporting.

Proved Reserves (SEC Definitions)

Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a)
defines proved reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future conditions.

(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes:

(A) that portion delineated by drilling and defined by gas-oil
and/or oil-water contacts, if any; and

(B) the immediately adjoining portions not yet drilled, but which
can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of
information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.

A-5
<PAGE>

(ii) Reserves which can be produced economically through application of
improved recovery techniques (such as fluid injection) are included in the
"proved" classification when successful testing by a pilot project, or the
operation of an installed program in the reservoir, provides support for
the engineering analysis on which the project or program was based.

(iii) Estimates of proved reserves do not include the following:

(A) oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves";

(B) crude oil, natural gas, and natural gas liquids, the recovery of
which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors;

(D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.

Proved developed oil and gas reserves. Proved developed oil and gas reserves
are reserves that can be expected to be recovered through existing wells with
existing equipment and operating methods. Additional oil and gas expected to be
obtained through the application of fluid injection or other improved recovery
techniques for supplementing the natural forces and mechanisms of primary
recovery should be included as "proved developed reserves" only after testing
by a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.

Proved undeveloped reserves. Proved undeveloped oil and gas reserves are
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. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production
when drilled. Proved reserves for other undrilled units can be claimed only
where it can be demonstrated with certainty that there is continuity of
production from the existing productive formation. Under no circumstances
should estimates for proved undeveloped reserves be attributable to any acreage
for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by
actual tests in the area and in the same reservoir.

Certain Staff Accounting Bulletins published subsequent to the promulgation
of Regulation S-X have dealt with matters relating to the application of
financial accounting and disclosure rules for oil and gas producing activities.
In particular, the following interpretations extracted from Staff Accounting
Bulletins set forth the Commission staff's view on specific questions
pertaining to proved oil and gas reserves.

Economic producibility of estimated proved reserves can be supported to the
satisfaction of the Office of Engineering if geological and engineering data
demonstrate with reasonable certainty that those reserves can be recovered in
future years under existing economic and operating conditions. The relative
importance of the many pieces of geological and engineering data which should
be evaluated when classifying reserves cannot be identified in advance. In
certain instances, proved reserves may be assigned to reservoirs on the basis
of a combination of electrical and other type logs and core analyses which
indicate the reservoirs are analogous to similar reservoirs in the same field
which are producing or have demonstrated the ability to produce on a formation
test. (extracted from SAB-35)

Statements in Staff Accounting Bulletins are not rules or interpretations of
the Commission nor are they published as bearing the Commission's official
approval; they represent interpretations and practices followed by the Division
of Corporation Finance and the Office of the Chief Accountant in administering
the disclosure requirements of the Federal securities laws.

A-6
<PAGE>

RESERVE STATUS CATEGORIES

In accordance with guidelines adopted by the Society of Petroleum Engineers
(SPE) and the World Petroleum Congress (WPC), developed reserves may be sub-
categorized as producing or non-producing.

Producing. Reserves sub-categorized as producing are expected to be
recovered from completion intervals which are open and producing at the time of
the estimate. Improved recovery reserves are considered producing only after
the improved recovery project is in operation.

Non-Producing. Reserves sub-categorized as non-producing include shut-in and
behind pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but which have
not started producing, (2) wells which were shut-in awaiting pipeline
connections or as a result of a market interruption, or (3) wells not capable
of production for mechanical reasons. Behind pipe reserves are expected to be
recovered from zones in existing wells, which will require additional
completion work or future recompletion prior to the start of production.

A-7
<PAGE>

[LOGO OF SPINNAKER EXPLORATION APPEARS HERE]