<PAGE>
FILED PURSUANT TO RULE 424(b)(4)
REGISTRATION NO. 333-83093
8,000,000 Shares
[LOGO OF SPINNAKER EXPLORATION APPEARS HERE]
Spinnaker Exploration Company
Common Stock
------------
Prior to this offering, there has been no public market for our common
stock. Our common stock has been approved for listing on The Nasdaq Stock
Market's National Market under the symbol "SPNX."
The underwriters have an option to purchase a maximum of 1,200,000
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.................................. $14.50 $0.91 $13.59
Total...................................... $116,000,000 $7,280,000 $108,720,000
</TABLE>
Delivery of the shares of common stock will be made on or about October 4,
1999.
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
Prudential Securities
Nesbitt Burns Securities Inc.
The date of this prospectus is September 28, 1999.
<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................. 20
Use of Proceeds....................................................... 21
Dividend Policy....................................................... 21
Dilution.............................................................. 22
Capitalization........................................................ 23
Selected Consolidated Financial Data.................................. 24
Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................ 26
Business and Properties............................................... 33
Management............................................................ 50
Certain Transactions.................................................. 57
Page
----
<S> <C>
Security Ownership of Management and Certain Beneficial Holders....... 59
Description of Capital Stock.......................................... 61
Shares Eligible for Future Sale....................................... 65
Underwriting.......................................................... 66
Notice to Canadian Residents.......................................... 68
Legal Matters......................................................... 69
Experts............................................................... 69
Where You Can Find More Information................................... 69
Glossary of Natural Gas and Oil Terms................................. 70
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 prospectus or to
which we have referred you. We have not authorized anyone to provide you with
information that is different. This document may be used only where it is legal
to sell these securities. The information in this prospectus may only be
accurate on the date of this prospectus.
Dealer Prospectus Delivery Obligation
Until October 23, 1999, all dealers that effect transactions in these
securities, whether or not participating in this offering, may be required to
deliver a prospectus. This is in addition to the dealer's obligation to deliver
a prospectus when acting as an underwriter and with respect to unsold
allotments or subscriptions.
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, the information
contained in this prospectus gives effect to the two-for-one common stock split
effective September 1, 1999. Also, 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 70 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 licenses to approximately 5,700 blocks of
mostly contiguous, recent vintage 3-D seismic data in the Gulf of Mexico,
including approximately 4,100 blocks from our 3-D seismic data agreement with
Petroleum Geo-Services ASA. This database covers an area of approximately 29
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 that was
generated in the 1990s. We currently have a leasehold interest in approximately
100 of these blocks. We believe that broad regional 3-D seismic analysis allows
us to create a large inventory of high-quality prospects and provides the
opportunity to enhance our exploration success. We also believe our licenses 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 of 3-D seismic data from other seismic data vendors.
Since our inception, we have participated in drilling 26 exploratory wells
in the Gulf of Mexico, with 18 of these wells being completed as discoveries.
As of August 31, 1999, Ryder Scott Company, L.P. estimated our net proved
reserves at approximately 81.1 Bcfe, 83% of which was natural gas, representing
an increase of approximately 500% over our estimated net proved reserves of
13.4 Bcfe at December 31, 1997. Our daily production has increased from
approximately 600 Mcfe at December 31, 1997 to approximately 48,000 Mcfe at
August 31, 1999. Within our current inventory of approximately 100 lease
blocks, we have identified approximately 49 exploratory prospects and 23 leads.
We expect to drill approximately 25 of these prospects during the remainder of
1999 and 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 1999 and
2000 includes approximately $180 million for exploration, development,
leasehold acquisitions and other capital expenditures, of which we have
incurred $36.8 million through June 30, 1999.
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. We have chosen to assemble 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. We also believe our geographic focus provides us with an
excellent
4
<PAGE>
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 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 also
intend to supplement that data with 3-D seismic data acquisitions from other
seismic data vendors. In addition to data acquisitions made directly by us, we
expect to continue to enter into joint ventures with other companies to share
the costs of data acquisitions and associated exploratory drilling.
Employ a rigorous prospect selection process. We leverage 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 10 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. All of our explorationists
have purchased equity in Spinnaker.
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 should
allow us to act as the operator for an increasing number of these prospects,
providing us with more control of costs, 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 one or two 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 continue exploring during periods
of low natural gas and oil prices, we potentially can take advantage of reduced
competition for prospects and lower drilling and other oil field service costs.
5
<PAGE>
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 materially
impaired if Petroleum Geo-Services terminates our data agreement or chooses not
to acquire any further data, our relatively small number of offshore properties
increases our exposure to production problems, reserve estimate inaccuracies
and 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
Since our inception, we have concentrated on the exploration for natural gas
and oil in the Gulf of Mexico. Our most significant exploration discoveries as
of August 31, 1999 are summarized in the table below. Please also read
"Business and Properties--Exploration Activities--Significant Exploration
Discoveries" for a more detailed discussion of these discoveries.
<TABLE>
<CAPTION>
Percent of
Spinnaker Approximate Date Production Spinnaker
Working Water Depth Commenced/ Total Net
Discovery Block Operator Interest (feet) Expected Present Value
--------------- ------------ --------- ----------- ---------------- -------------
<S> <C> <C> <C> <C> <C>
Brazos A-19............. Shell 15% 130 4th Quarter 1999 15%
Garden Banks 367
(Dulcimer)............. Mariner 33 1/3% 1,100 April 1999 14%
South Timbalier 219..... Spinnaker 72 3/4% 150 1st Quarter 2000 12%
East Cameron 152........ Ocean Energy 50% 80 April 1999 10%
South Timbalier 220..... Samedan 33 1/3% 150 August 1998 10%
West Cameron 39......... Spinnaker 60% 30 January 1999 9%
Mississippi Canyon 496
(Zia).................. Shell 12 1/2% 1,800 4th Quarter 2001 7%
High Island 235......... Spinnaker 50% 60 April 1999 6%
Vermilion 375........... Spinnaker 70% 300 2nd Quarter 2000 5%
South Pelto 18.......... Hall-Houston 25% 50 December 1998 5%
West Cameron 522........ Newfield 46% 180 March 1998 4%
</TABLE>
Our Executive Offices
Our principal 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 Spinnaker.. 8,000,000 shares
Common stock to be outstanding
after this offering............... 20,420,384 shares(1)
Use of proceeds.................... We intend to use the net proceeds of this
offering to repay all outstanding
indebtedness under our credit facility and
to fund a portion of our exploration and
development activities.
Proposed Nasdaq National Market
symbol............................ SPNX
</TABLE>
- --------
(1) Excludes 2,673,242 shares of common stock issuable on exercise of
outstanding options at a weighted average exercise price of $9.58 per share
and 633,824 shares of common stock issuable on exercise of options to be
granted on completion of this offering at an exercise price equal to the
initial public offering price.
7
<PAGE>
Summary Consolidated Financial Data
(in thousands, except share and 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>
Period from
Inception
(December 20, Year Ended December Six Months Ended
1996) through 31, June 30,
December 31, -------------------- --------------------
1996 1997 1998 1998 1999
------------- --------- --------- --------- ---------
(unaudited)
<S> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Natural gas and oil
revenues............... $ -- $ 201 $ 3,298 $ 961 $ 9,583
--------- --------- --------- --------- ---------
Expenses:
Lease operating
expenses.............. -- 72 474 331 1,183
Depreciation,
depletion and
amortization--natural
gas and oil
properties............ -- 68 2,738 648 7,619
Depreciation and
amortization--other... 10 349 437 136 98
Impairment of natural
gas and oil
properties............ -- -- 2,642 -- --
General and
administrative........ 318 1,965 3,809 1,959 2,244
Stock appreciation
rights expense........ -- -- -- 904 1,651
--------- --------- --------- --------- ---------
Total expenses....... 328 2,454 10,100 3,978 12,795
--------- --------- --------- --------- ---------
Loss from operations.... (328) (2,253) (6,802) (3,017) (3,212)
--------- --------- --------- --------- ---------
Other income (expense):
Interest income........ -- 91 221 133 85
Interest expense....... -- -- (516) -- (2,007)
Capitalized interest... -- -- 237 -- 634
--------- --------- --------- --------- ---------
Loss before income
taxes.................. (328) (2,162) (6,860) (2,884) (4,500)
Income tax provision... -- -- -- -- --
--------- --------- --------- --------- ---------
Loss before cumulative
effect of change in
accounting principle... (328) (2,162) (6,860) (2,884) (4,500)
Cumulative effect of
change in accounting
principle (1).......... -- -- -- -- (395)
--------- --------- --------- --------- ---------
Net loss................ $ (328) $ (2,162) $ (6,860) $ (2,884) $ (4,895)
========= ========= ========= ========= =========
Accrual of dividends on
preferred stock........ (16) (1,326) (7,094) (2,498) (5,088)
--------- --------- --------- --------- ---------
Net loss available to
common stockholders.... $ (344) $ (3,488) $ (13,954) $ (5,382) $ (9,983)
========= ========= ========= ========= =========
Basic and diluted loss
per common share (2):
Loss before cumulative
effect of change in
accounting
principle............. $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.33)
Cumulative effect of
change in accounting
principle (1)......... -- -- -- -- (0.10)
--------- --------- --------- --------- ---------
Net loss per common
share................. $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.43)
========= ========= ========= ========= =========
Weighted average number
of common shares
outstanding--basic and
diluted (2)............ 3,960,000 3,960,000 4,059,020 4,054,514 4,112,795
========= ========= ========= ========= =========
Other Data:
Adjusted EBITDA (3)..... $ (318) $ (1,836) $ (985) $ (1,329) $ 6,156
Net cash provided by
(used in) operating
activities............. (12) (5,523) (2,776) 241 4,508
Net cash used in
investing activities... -- (15,236) (68,503) (35,515) (47,673)
Net cash provided by
financing activities... 4,590 18,863 70,738 34,000 45,000
Capital expenditures.... -- 15,578 85,681 38,691 33,575
<CAPTION>
December 31, June 30, 1999
---------------------------------- --------------------
As
1996 1997 1998 Actual Adjusted
------------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash and cash
equivalents............ $ 4,578 $ 2,682 $ 2,141 $ 3,976 $ 47,633
Current assets.......... 4,588 6,348 6,737 15,156 58,813
Total assets............ 5,241 22,358 102,769 139,552 183,209
Short-term debt......... -- -- 19,000 64,000 --
Other current
liabilities............ 1,858 2,096 18,378 10,005 10,005
Accrued preferred
dividends payable...... 16 1,383 8,478 13,566 --
Other long-term
liabilities............ -- -- -- -- --
Total equity............ 3,367 18,879 56,913 51,981 173,204
</TABLE>
8
<PAGE>
- --------
(1) 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.
(2) 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.
(3) As used in this prospectus, Adjusted EBITDA means earnings before interest,
income taxes, depreciation, depletion and amortization, impairment 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.
The "As Adjusted" balance sheet data gives effect to the application of the
$107.7 million of estimated net proceeds from the sale of common stock in this
offering and the issuance of shares of common stock to our preferred
stockholders in lieu of payment of accrued cash dividends.
Pro Forma Data
(in thousands, except share and per share data)
The pro forma net loss data presented in the following table gives effect
to:
. the conversion of all outstanding shares of our preferred stock into
common stock as if the conversion had occurred as of the beginning of the
period presented;
. the issuance of shares of common stock to holders of approximately 99.5%
of our preferred stock in lieu of payment of accrued cash dividends as if
the issuance had occurred as of the beginning of the period presented;
and
. the use of a portion of the estimated net proceeds of this offering to
pay all outstanding indebtedness all as if the transaction had occurred
at the beginning of the period presented.
<TABLE>
<CAPTION>
Year Ended Six Months Ended
December 31, 1998 June 30, 1999
----------------- ----------------
<S> <C> <C>
Pro forma net loss......................... $ (6,344) $ (2,888)
========== ==========
Pro forma basic and diluted loss per common
share:
Loss before cumulative effect of change
in accounting principle................. $ (0.45) $ (0.13)
Cumulative effect of change in accounting
principle............................... -- (0.02)
---------- ----------
Pro forma net loss per common share...... $ (0.45) $ (0.15)
========== ==========
Pro forma weighted average number of common
shares outstanding--basic and diluted..... 14,078,089 18,795,459
========== ==========
</TABLE>
9
<PAGE>
Summary Reserve Information
The table below presents our summary reserve information as of August 31,
1999. Estimates of proved reserves are based on the August 31, 1999 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 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 13 of the notes to our
consolidated financial statements.
The present value of future net cash flows attributable to our proved
reserves on a pre-tax basis using prices and costs in effect at August 31,
1999, discounted at 10% per annum, was determined by using the August 31, 1999
prices of $2.83 per MMBtu of natural gas at Henry Hub, Louisiana and $22.11 per
Bbl of oil at the Cushing NYMEX Pricing Hub. If the present value of future net
cash flows were calculated on an after-tax basis, this amount would not change
because of our tax basis in natural gas and oil properties and our net
operating loss carryforwards. Please read note 13 of the notes to our
consolidated financial statements.
<TABLE>
<CAPTION>
As of
August 31,
1999
----------
<S> <C>
Estimated proved reserves:
Natural gas (MMcf)................................................. 67,302
Oil and condensate (MBbls)......................................... 2,307
Total (MMcfe).................................................... 81,144
Proved developed reserves as a percentage of proved reserves......... 46%
Present value (in thousands)......................................... $152,223
</TABLE>
Summary Operating Data
<TABLE>
<CAPTION>
Year Ended Six Months
December Ended June
31, 30,
----------- -----------
1997 1998 1998 1999
----- ----- ----- -----
<S> <C> <C> <C> <C>
Production:
Natural gas (MMcf)................................... 70 1,675 482 4,258
Oil and condensate (MBbls)........................... -- 12 1 49
Total (MMcfe)........................................ 70 1,747 488 4,552
Average sales price per unit:
Natural gas (per Mcf)................................ $2.87 $1.89 $1.97 $2.09
Oil and condensate (per Bbl)......................... 18.51 11.61 13.24 14.70
Total (per Mcfe)..................................... 2.87 1.89 1.97 2.11
Expenses (per Mcfe):
Lease operating expense.............................. $1.03 $0.27 $0.68 $0.26
Depreciation, depletion and amortization--natural gas
and oil properties.................................. 0.97 1.57 1.33 1.67
</TABLE>
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 since our formation, 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 addition, we have incurred losses from operations each
year since our formation. Our failure to achieve or sustain profitability in
the future could adversely affect the market price of our common stock.
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 are less
experienced and have fewer financial resources than many companies in our
industry, we may be at a disadvantage in bidding for exploratory prospects and
producing natural gas and oil properties. Please read "Business and
Properties--Competition" for a description of the competition we face in our
business.
We incurred net losses of $328,000 in 1996, $2.2 million in 1997, $6.9
million in 1998 and $4.9 million in the first six months of 1999. We expect to
incur a loss for the third quarter of 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.
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 and the delivery
of 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
11
<PAGE>
of these expenditures. Poor results from our exploration activities could
affect our future cash flows and results of operations materially and
adversely.
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 or chooses not to
acquire any further data, our ability to find additional reserves could be
materially impaired.
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."
Although we currently have received under our Petroleum Geo-Services data
agreement 3-D seismic data covering approximately 4,100 blocks in the Gulf of
Mexico, we anticipate obtaining additional 3-D seismic data to be acquired or
processed by Petroleum Geo-Services between now and March 31, 2002. However,
there are a number of scenarios under which we might not receive significant
additional data from Petroleum Geo-Services. Our agreement does not require
Petroleum Geo-Services to acquire or process any further data. Petroleum Geo-
Services could elect to substantially reduce or cease activities in the Gulf of
Mexico during the remaining term of our agreement. Among other things, such an
election could result from a change of control of Petroleum Geo-Services or
changes in Petroleum Geo-Services' competitive, financial or technological
status.
Alternatively, Petroleum Geo-Services 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 could also 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 could also 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.
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 our credit facility is
subject to periodic re-determination based in part on changing expectations of
future prices. Lower prices may also reduce the amount of natural gas and oil
that we can economically produce.
Prices for natural gas and oil fluctuate widely. For example, natural gas
and oil prices declined significantly in 1998 and, for an extended period of
time, remained substantially below prices obtained in previous years. Among the
factors that can cause this fluctuation are:
12
<PAGE>
. the level of consumer product demand;
. weather conditions;
. domestic and foreign governmental regulations;
. the price and availability of alternative fuels;
. political conditions in natural gas and oil producing regions;
. the domestic and foreign supply of natural gas and oil;
. the price of foreign imports; and
. overall economic conditions.
Reserve estimates depend on many assumptions that may turn out to be
inaccurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and 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 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 August 31, 1999, 70% 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 August 31, 1999. 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 SEC
requirements, we generally 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
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 August 1999, over 88% of our daily production came from four 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 August 31, 1999, our proved reserves
were located on 15
13
<PAGE>
properties in the Gulf of Mexico, with approximately 50% of our proved reserves
attributable to four of these properties. If the actual reserves associated
with any one of these properties are less than our estimated reserves, our
results of operations and financial condition could be adversely affected.
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;
. increased oil field service costs;
. difficulties securing oil field services; and
. compliance with environmental and other laws and regulations.
Relatively short production periods for Gulf of Mexico properties subject us to
higher reserve replacement needs 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, and as a result, our reserve replacement needs from new prospects
are greater.
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.
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;
14
<PAGE>
. natural disasters;
. pipe or cement failures;
. casing collapses;
. embedded oil field 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 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.
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 intend to 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. For example, near surface geologic conditions
in the deep waters create unique operational challenges. Deep water drilling
and operations also require the application of relatively untested technologies
that involve a higher risk of mechanical failure and generally have
significantly higher drilling and operating costs. Furthermore, the deep waters
of the Gulf of Mexico lack the physical and oil field 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 the risk involved
with these operations.
15
<PAGE>
We cannot control the activities on properties we do not operate.
Other companies operate most 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 upon 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 these properties. Most of our competitors have
substantially greater financial and other resources than us. 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 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
16
<PAGE>
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.
Currently, Columbia Energy Services purchases all of our natural gas
production at current market prices. The terms of our arrangement with Columbia
require Columbia to pay us within 60 to 90 days after we deliver our production
to Columbia. As a result, if Columbia were to default on its payment
obligations to us, 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 adversely affect our
financial condition and results of operations.
Hedging our production may result in losses.
To reduce our exposure to fluctuations in the prices of natural gas and oil,
we have recently begun to enter into hedging arrangements. Hedging arrangements
expose us to risk of financial loss 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.
17
<PAGE>
In addition, these hedging arrangements may limit the benefit we would
receive from increases in the prices for natural gas and oil. Furthermore, 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.
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 63% of
our outstanding shares of common stock, assuming no exercise of the
underwriters' over-allotment option. As a result, these stockholders will 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, on
completion of this offering representatives of Petroleum Geo-Services and
Warburg, Pincus Ventures will constitute a majority of our board of directors.
Their control of Spinnaker may have the effect of delaying or preventing 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. Please read "Shares
Eligible for Future Sale."
On completion of this offering, we will have outstanding 20,420,384 shares
of our common stock, assuming no exercise of the underwriters' over-allotment
option. This includes the 8,000,000 shares we are selling in this offering,
which may be resold in the public market immediately. Of the remaining shares,
12,377,098 shares will become available for resale in the public market after a
period of 180 days after the date of this prospectus, with some exceptions. All
shares of our stock outstanding prior to this offering could be sold following
the 180-day period either in transactions registered under the Securities Act
or exempt from registration. In addition, our current stockholders collectively
have rights that provide for the registration of the resale of their shares of
common stock at our expense. Please read "Certain Transactions" and
"Description of Capital Stock--Registration Rights" for a description of these
registration rights.
Options to purchase approximately 2,673,242 shares of common stock are
currently outstanding, and we anticipate granting additional options to
purchase up to 633,824 shares of common stock to some of our
18
<PAGE>
directors, officers and employees on completion of this offering. After this
offering, we intend to file a registration statement covering the sale of the
common stock issuable upon exercise of those options. The shares received upon
exercise generally will be freely transferable. Please read "Management--1998
Stock Option Plan" and "--1999 Stock Incentive Plan."
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.
Our computer systems and the computer systems of our business partners may not
be Year 2000 compliant, which may cause system failures and disruptions
adversely affecting our operations.
The "Year 2000" issue is a general term used to refer to the business
implications of the arrival of the new millennium. In simple terms, on January
1, 2000, all computer hardware and software systems that use the two-digit year
convention could fail completely or create erroneous data as a result of the
system failing to recognize the two-digit internal date "00" as representing
the Year 2000. Our computer systems and the computer systems of our business
partners may not be Year 2000 compliant, which may cause system failures and
disruptions adversely affecting our operations. Please read "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Year
2000 Compliance."
We cannot assure you that our internal operations do not have any material
issues with respect to Year 2000 compliance. In addition, we may not properly
identify all potential problems or all potentially affected systems or remedy
all problems in our systems. Furthermore, the Year 2000 issue also affects our
customers, the suppliers of our 3-D seismic data, and other third parties with
whom we do business. The failure of any of these entities to become Year 2000
compliant could adversely affect our operations. The most reasonably likely
"worst case" impacts would be:
. impairment of our ability to deliver our production to, or receive
payment from, third parties gathering and/or purchasing our production
from affected facilities;
. impairment of the ability of third-party suppliers or service companies
to provide needed materials or services to our planned or ongoing
operations, necessitating deferral or shut-in of exploration, development
or production operations;
. impairment of our ability to receive and process 3-D seismic data, which
would hinder our ability to generate and drill exploratory prospects; and
. our inability to execute financial transactions with our banks or other
third parties whose systems fail or malfunction.
19
<PAGE>
CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS
Some of the information in this prospectus contains forward-looking
statements. These statements express, or are based on, our expectations about
future events. These include such matters as:
. amount, nature and timing of capital expenditures;
. drilling of wells;
. 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;
. marketing of natural gas and oil; and
. Year 2000 compliance activities.
There are many factors that could cause these forward-looking statements to
be incorrect, including, but not limited to, the risks described under "Risk
Factors" and "Management's Discussion and Analysis of Financial Condition and
Results of Operations." These factors include, among others:
. 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;
. climatic 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;
. Year 2000 compliance actions; and
. general economic conditions.
When you consider these forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this prospectus. Our
forward-looking statements speak only as of the date made.
20
<PAGE>
USE OF PROCEEDS
We estimate that we will receive net proceeds of $107.7 million, or $124.0
million if the underwriters exercise their over-allotment option in full, from
the sale of the 8,000,000 shares of common stock offered by this prospectus,
after deducting underwriting discounts and commissions and estimated offering
expenses.
We intend to use the net proceeds as follows:
. approximately $72.0 million to repay all of our outstanding debt under
our credit facility; and
. approximately $35.7 million to fund a portion of our exploration and
development activities.
Pending use for these purposes, we plan to invest the net proceeds in short-
term investment-grade interest-bearing securities.
Through 2000, we expect to use cash generated from operations to fund the
remaining portion of our exploration and development activities not funded from
the proceeds of this offering.
The weighted average interest rate for outstanding borrowings under our
credit facility as of June 30, 1999 was 5.79%. The credit facility has a
maturity of December 31, 1999. We have used borrowings under our current credit
facility to fund a portion of our exploration and development activities and
for other corporate purposes. Please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations--Liquidity and Capital
Resources--Credit Agreement" for a discussion of our current credit agreement.
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.
21
<PAGE>
DILUTION
The pro forma net tangible book value of our common stock on June 30, 1999
was approximately $5.37 per share of common stock, assuming conversion of all
outstanding shares of our preferred stock into common stock and the issuance of
993,474 shares of common stock to holders of approximately 99.5% of our
preferred stock on completion of this offering in lieu of payment of accrued
cash dividends. Pro forma 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, 1999
would have been approximately $8.58 per share. This represents an immediate and
substantial increase in the net tangible book value of $3.21 per share to
existing stockholders and an immediate dilution, resulting from the difference
between the initial public offering price and the pro forma 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>
Public offering price per share.............................. $14.50
Pro forma net tangible book value per share at June 30,
1999...................................................... 5.37
Increase per share attributable to new investors........... 3.21
----
Pro forma net tangible book value per share after this
offering.................................................... 8.58
------
Dilution per share to new investors.......................... $ 5.92
======
</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 offering
price would increase the dilutive effect to new investors. Please read notes 5
and 6 of the notes to our consolidated financial statements.
The following table sets forth, at June 30, 1999, the number of shares of
common stock purchased from us, assuming the conversion of all shares of our
preferred stock into common stock, the total consideration and average price
per share paid by existing stockholders and by the new investors before
deducting expenses payable by us:
<TABLE>
<CAPTION>
Shares Purchased Total Consideration Average
------------------ -------------------- Price
Number Percent Amount Percent Per Share
---------- ------- ------------ ------- ---------
<S> <C> <C> <C> <C> <C>
Existing stockholders......... 12,187,514 60% $ 93,253,000 45% $ 7.65
New investors................. 8,000,000 40 116,000,000 55 14.50
---------- --- ------------ ---
Total....................... 20,187,514 100% $209,253,000 100%
========== === ============ ===
</TABLE>
If the underwriters' over-allotment option is exercised in full, the number
of shares held by new investors will be increased to 9,200,000, or
approximately 43% of the total number of shares of our common stock, assuming
the conversion of all shares of our preferred stock into common stock.
The information presented in the above tables excludes:
. 206,774 shares of common stock we expect to issue to holders of our
preferred stock on completion of this offering in lieu of payment of
accrued cash dividends for the period commencing July 1, 1999 and ending
October 4, 1999; and
. a total of 26,096 shares of common stock we expect to issue to Warburg,
Pincus Ventures and Petroleum Geo-Services on completion of this offering
for their agreement to guarantee our obligations under our current credit
agreement.
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<PAGE>
CAPITALIZATION
The following table presents our capitalization as of June 30, 1999 on three
bases:
. on an actual basis;
. on a pro forma basis giving effect to:
. the conversion of all outstanding shares of our preferred stock into
common stock on completion of this offering;
. the issuance of shares of common stock to holders of approximately
99.5% of our preferred stock in lieu of payment of accrued cash
dividends on completion of this offering; and
. on a pro forma basis as adjusted to reflect our anticipated use of the
estimated net proceeds of this offering.
The table excludes 206,774 shares of common stock we expect to issue to
holders of our preferred stock on completion of this offering in lieu of
payment of accrued cash dividends for the period commencing July 1, 1999 and
ending October 4, 1999. The table also excludes a total of 26,096 shares of
common stock we expect to issue to Warburg, Pincus Ventures and Petroleum Geo-
Services on completion of this offering for their agreement to guarantee our
obligation under our credit agreement. 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, 1999
--------------------------------
Pro Forma
Actual Pro Forma As Adjusted
-------- --------- -----------
(in thousands)
<S> <C> <C> <C>
Cash and cash equivalents.................... $ 3,976 $ 3,913 $ 47,633
======== ======== ========
Short-term debt.............................. $ 64,000 $ 64,000 $ --
Accrued preferred dividends payable.......... 13,566 -- --
Stockholders' equity:
Preferred stock, $.01 par value, 3,030,920
shares authorized; 3,030,920 shares issued
and outstanding, actual; no shares issued
and outstanding, pro forma and pro forma as
adjusted.................................... 30 -- --
Common stock, $.01 par value, 22,000,000
shares authorized; 5,132,200 shares issued
and outstanding, actual; 12,187,514 shares
issued and outstanding, pro forma;
20,187,514 shares issued and outstanding,
pro forma as adjusted....................... 26 122 202
Additional paid-in capital................... 79,694 93,131 200,771
Accumulated deficit.......................... (27,769) (27,769) (27,769)
-------- -------- --------
Total stockholders' equity................. 51,981 65,484 173,204
-------- -------- --------
Total capitalization..................... $129,547 $129,484 $173,204
======== ======== ========
</TABLE>
23
<PAGE>
SELECTED CONSOLIDATED FINANCIAL DATA
(in thousands, except share and 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>
Period from
Inception
(December 20, Year Ended December Six Months Ended
1996) through 31, June 30,
December 31, -------------------- --------------------
1996 1997 1998 1998 1999
------------- --------- --------- --------- ---------
(unaudited)
<S> <C> <C> <C> <C> <C>
Statement of Operations
Data:
Natural gas and oil
revenues............... $ -- $ 201 $ 3,298 $ 961 $ 9,583
--------- --------- --------- --------- ---------
Expenses:
Lease operating
expenses.............. -- 72 474 331 1,183
Depreciation,
depletion and
amortization--natural
gas and oil
properties............ -- 68 2,738 648 7,619
Depreciation and
amortization--other... 10 349 437 136 98
Impairment of natural
gas and oil
properties............ -- -- 2,642 -- --
General and
administrative........ 318 1,965 3,809 1,959 2,244
Stock appreciation
rights expense........ -- -- -- 904 1,651
--------- --------- --------- --------- ---------
Total expenses....... 328 2,454 10,100 3,978 12,795
--------- --------- --------- --------- ---------
Loss from operations.... (328) (2,253) (6,802) (3,017) (3,212)
--------- --------- --------- --------- ---------
Other income (expense):
Interest income........ -- 91 221 133 85
Interest expense....... -- -- (516) -- (2,007)
Capitalized interest... -- -- 237 -- 634
--------- --------- --------- --------- ---------
Loss before income
taxes.................. (328) (2,162) (6,860) (2,884) (4,500)
Income tax provision -- -- --- -- --
--------- --------- --------- --------- ---------
Loss before cumulative
effect of change in
accounting principle... (328) (2,162) (6,860) (2,884) (4,500)
Cumulative effect of
change in accounting
principle (1).......... -- -- -- -- (395)
--------- --------- --------- --------- ---------
Net loss................ $ (328) $ (2,162) $ (6,860) $ (2,884) $ (4,895)
========= ========= ========= ========= =========
Accrual of dividends on
preferred stock........ (16) (1,326) (7,094) (2,498) (5,088)
--------- --------- --------- --------- ---------
Net loss available to
common stockholders.... $ (344) $ (3,488) $ (13,954) $ (5,382) $ (9,983)
========= ========= ========= ========= =========
Basic and diluted loss
per common share (2):
Loss before cumulative
effect of change in
accounting
principle............. $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.33)
Cumulative effect of
change in accounting
principle (1)......... -- -- -- -- (0.10)
--------- --------- --------- --------- ---------
Net loss per common
share................. $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.43)
========= ========= ========= ========= =========
Weighted average number
of common shares
outstanding--basic and
diluted (2)............ 3,960,000 3,960,000 4,059,020 4,054,514 4,112,795
========= ========= ========= ========= =========
Other Data:
Adjusted EBITDA (3)..... $ (318) $ (1,836) $ (985) $ (1,329) $ 6,156
Net cash provided by
(used in) operating
activities............. (12) (5,523) (2,776) 241 4,508
Net cash used in
investing activities... -- (15,236) (68,503) (35,515) (47,673)
Net cash provided by
financing activities... 4,590 18,863 70,738 34,000 45,000
Capital expenditures.... -- 15,578 85,681 38,691 33,575
<CAPTION>
December 31, June 30,
---------------------------------- --------------------
1996 1997 1998 1998 1999
------------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Balance Sheet Data:
Cash and cash
equivalents............ $ 4,578 $ 2,682 $ 2,141 $ 1,408 $ 3,976
Current assets.......... 4,588 6,348 6,737 4,665 15,156
Total assets............ 5,241 22,358 102,769 58,582 139,552
Short-term debt......... -- -- 19,000 -- 64,000
Other current
liabilities............ 1,858 2,096 18,378 6,300 10,005
Accrued preferred
dividends payable...... 16 1,383 8,478 3,881 13,566
Other long-term
liabilities............ -- -- -- -- --
Total equity............ 3,367 18,879 56,913 48,401 51,981
</TABLE>
24
<PAGE>
- --------
(1) 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.
(2) 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.
(3) As used in this prospectus, Adjusted EBITDA means earnings before interest,
income taxes, depreciation, depletion and amortization, impairment 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.
Pro Forma Data
(in thousands, except share and per share data)
The pro forma net loss data presented in the following table gives effect
to:
. the conversion of all outstanding shares of our preferred stock into
common stock as if the conversion had occurred as of the beginning of the
period presented;
. the issuance of shares of common stock to holders of approximately 99.5%
of our preferred stock in lieu of payment of accrued cash dividends as if
the issuance had occurred as of the beginning of the period presented;
and
. the use of a portion of the estimated net proceeds of this offering to
pay all outstanding indebtedness all as if the transaction had occurred
at the beginning of the period presented.
<TABLE>
<CAPTION>
Year Ended Six Months Ended
December 31, 1998 June 30, 1999
----------------- ----------------
<S> <C> <C>
Pro forma net loss......................... $ (6,344) $ (2,888)
========== ==========
Pro forma basic and diluted loss per common
share:
Loss before cumulative effect of change
in accounting principle................. $ (0.45) $ (0.13)
Cumulative effect of change in accounting
principle............................... -- (0.02)
---------- ----------
Pro forma net loss per common share...... $ (0.45) $ (0.15)
========== ==========
Pro forma weighted average number of common
shares outstanding--basic and diluted..... 14,078,089 18,795,459
========== ==========
</TABLE>
25
<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 26
exploratory wells in the Gulf of Mexico, with 18 of these wells being completed
as discoveries. As of August 31, 1999, Ryder Scott estimated our net proved
reserves at approximately 81.1 Bcfe, 83% of which was natural gas, representing
an approximately 500% increase over our net proved reserves of 13.4 Bcfe at
December 31, 1997. We currently have an interest in approximately 100 lease
blocks in the Gulf of Mexico, within which we have identified approximately 49
exploratory prospects and 23 leads. We expect to drill approximately 25 of
these prospects during the remainder of 1999 and 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 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 also 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 and other related general
and administrative costs directly attributable to these activities. We
capitalized general and administrative costs of $1.3 million in 1997, $2.5
million in 1998 and $1.1 million during the first six months of 1999. 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, 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 based on the estimated future net cash flows
from proved natural gas and oil reserves discounted at 10% per annum. If
capitalized costs exceed this limit, we charge the excess to depreciation,
depletion and amortization
26
<PAGE>
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 impairment 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 is primarily the result of the decline in
natural gas prices experienced in 1998. As permitted by applicable SEC 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 from December 31,
1998 to April 9, 1999, and $4.52 per Bbl 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 impairment of natural gas and oil
properties of approximately $13.0 million. At June 30, 1999, we recognized no
impairment of natural gas and oil properties; however, if we had used only June
30, 1999 natural gas and oil prices, we would have recognized a non-cash
impairment of natural gas and oil properties of approximately $1.5 million. As
permitted by applicable SEC rules, we used post-June 30, 1999 price increases
of $0.83 per MMBtu of natural gas and $3.89 per Bbl of oil for June 30, 1999 to
August 23, 1999.
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 such 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, 1999 as Compared to the Six Months Ended June 30,
1998
We had natural gas and oil revenues of $9.6 million for the six months ended
June 30, 1999 as compared to $1.0 million for the six months ended June 30,
1998. This increase in revenues resulted primarily from increased production
attributable to eight new wells which commenced production subsequent to June
30, 1998. Our production substantially increased to 4,552 MMcfe in the first
six months of 1999 from 488 MMcfe in the first six months of 1998. The average
price we received for our natural gas production was $2.09 per Mcf during the
six months ended June 30, 1999 as compared to $1.97 per Mcf during the six
months ended June 30, 1998, which also contributed to our increase in revenues.
Lease operating expenses for the six months ended June 30, 1999 were $1.2
million as compared to $331,000 for the six months ended June 30, 1998. This
increase in lease operating expenses primarily resulted from operating expenses
attributable to properties that commenced production subsequent to June 30,
1998. Lease operating expenses per Mcfe decreased to $0.26 per Mcfe during the
six months ended June 30, 1999 from $0.68 per Mcfe during the six months ended
June 30, 1998.
General and administrative expenses for the six months ended June 30, 1999
were $2.2 million as compared to $2.0 million for the six months ended June 30,
1998. This increase in general and administrative expenses was primarily due to
employment-related costs associated with an increase in personnel subsequent to
June 30, 1998.
Stock appreciation rights expense for the six months ended June 30, 1999 was
$1.7 million as compared to $0.9 million for the six months ended June 30,
1998. Stock appreciation rights expense was based on management's estimate of
the share values of Spinnaker at June 30, 1999 and 1998 and increased primarily
as a result of vesting of the related stock options.
27
<PAGE>
Depreciation, depletion and amortization--natural gas and oil properties for
the six months ended June 30, 1999 was $7.6 million as compared to $648,000 for
the six months ended June 30, 1998. Of the $7.0 million increase, $5.4 million
was attributable to a substantial increase in production and $1.6 million was
due to an increase in the unit depletion rate to $1.67 per Mcfe during the six
months ended June 30, 1999 from $1.33 per Mcfe during the six months ended June
30, 1998. Depreciation and amortization--other decreased to $98,000 for the six
months ended June 30, 1999 from $136,000 for the six months ended June 30,
1998, primarily due to the change in accounting principle related to the write-
off of previously capitalized organization costs.
Net loss for the six months ended June 30, 1999 was $4.9 million as compared
to $2.9 million for the six months ended June 30, 1998. The increase in net
loss was due to the factors described above and our adoption during the first
quarter of 1999 of Statement of Position 98-5, "Reporting on the Costs of
Start-Up Activities," which requires that we expense and not capitalize the
costs for start-up activities and organization costs as incurred. Approximately
$395,000 of this increase is attributable to our adoption of Statement of
Position 98-5.
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, our 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 we received for
our 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 $0.3
million 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--natural gas and oil properties 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.
Additionally, as described above we recognized a non-cash impairment of
natural gas and oil properties of $2.6 million due to a decline in prices
during 1998.
Net loss for the year ended December 31, 1998 was $6.9 million as compared
to $2.2 million for the year ended December 31, 1997. The increase in net loss
was due primarily to the factors described above.
December 20, 1996 (inception) through December 31, 1996
We commenced operations on December 20, 1996 and, through December 31, 1996,
had no natural gas and oil revenues or lease operating expenses. We had
$318,000 of general and administrative expenses relating primarily to start-up
costs.
Liquidity and Capital Resources
We have funded our activities primarily with the proceeds from private
placements of our equity securities and borrowings under our credit facility.
From inception through June 30, 1999, we raised an aggregate of approximately
$75 million from sales of our equity securities. In addition, from inception
through June 30, 1999, we borrowed an aggregate of $64 million.
28
<PAGE>
From inception through June 30, 1999, we incurred capital expenditures
totaling approximately $139.1 million, including $4.3 million of non-cash
activity. Of these expenditures, $61.4 million were for exploration, $39.0
million were for development, $35.6 million were for leasehold acquisitions and
$3.1 million for other capital expenditures.
We have experienced and expect to continue to experience substantial working
capital requirements and at June 30, 1999 had a working capital deficit of
approximately $58.8 million, primarily due to our active exploration and
development programs. While we believe that the net proceeds from this
offering, our cash flow from operations and borrowings under either our current
credit facility or a replacement facility should allow us to implement our
present business strategy during 1999 and 2000, additional financing may be
required in the future to fund our growth and exploration and development
programs. In the event these capital resources are not available to us, we may
have to curtail our exploration and other activities or sell some of our assets
on an untimely or unfavorable basis.
We have budgeted to spend approximately $180 million during 1999 and 2000
for exploration, development, leasehold acquisitions and other capital
expenditures. During the first six months of 1999, we incurred capital
expenditures of $36.8 million, including $3.2 million of non-cash expenditures.
Of these expenditures, we incurred $7.7 million for exploration, $13.5 million
for development, $15.3 million for leasehold acquisitions and $0.3 million for
other capital expenditures.
Our budget includes development costs that are contingent on the success of
future exploratory drilling. We do not anticipate that our budgeted leasehold
acquisition activities will include the acquisition of producing properties. We
do not anticipate any significant abandonment or dismantlement costs through
2000. 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 industry owners and the prices of
oil field goods and services. We anticipate that these capital expenditures
will be funded through net proceeds from this offering and cash flows from our
operations.
We intend to use cash flows from operations to fund a portion of our future
acquisition, exploration and development activities. Net cash provided by (used
in) operating activities was $4.5 million for the six months ended June 30,
1999, ($2.8 million) for 1998 and ($5.5 million) for 1997. Net cash flow used
in operating activities in 1997 and 1998 was generally attributable to our
limited production during the periods. The fact that operating activities in
the first half of 1999 no longer used net cash but provided net cash was
generally attributable to increasing levels of production in that period. As of
August 31, 1999, we produced approximately 48 MMcfe per day as compared to
average production of 4.8 MMcfe per day in 1998 and 0.6 MMcfe per day in 1997.
Our cash flow from operations will depend on the prices of natural gas and oil
and on our ability to increase production through our exploration and
development drilling program.
Hedging Transactions
We currently sell most of our natural gas and oil production under price
sensitive or market price contracts. To reduce our exposure to fluctuations in
natural gas and oil prices, we have recently begun to enter into hedging
arrangements. However, these contracts also limit the benefits we would realize
if prices increase.
Through August 31, 1999, Spinnaker had entered into the following collar
arrangements covering the period beginning October 1, 1999. 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>
10/1/99-12/31/99... 25,000 $2.93 $3.14 500 $20.23 $22.26
1/1/00-3/31/00..... 25,000 2.86 3.06 500 19.28 21.35
4/1/00-6/30/00..... 25,000 2.40 2.60 500 18.48 20.58
7/1/00-9/30/00..... 25,000 2.36 2.57 500 17.90 20.01
</TABLE>
29
<PAGE>
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. (formerly NationsBank, N.A.) each of which is an affiliate of one
of the underwriters for this offering. Simultaneously with the completion of
this offering, we will repay all outstanding borrowings under the credit
facility, which were $72.0 million as of September 27, 1999. We intend to
replace this credit facility following the completion of this offering with a
credit facility not in excess of $25 million which is not expected to be
guaranteed by any of our stockholders. Bank of Montreal has provided us with a
preliminary commitment for this new facility.
The credit agreement is secured by substantially all of our assets,
including our interests in our natural gas and oil properties, and in part
supported by guarantees of Petroleum Geo-Services and Warburg, Pincus Ventures,
our principal stockholders. The initial stockholder guarantee for the credit
agreement was $75.0 million, split evenly between Petroleum Geo-Services and
Warburg, Pincus Ventures. On a semi-annual basis, our proved reserves are
required to be evaluated to redetermine the borrowing base.
The credit agreement is comprised of three tranches, each with a specified
interest rate. The weighted average interest rate for the Petroleum Geo-
Services and Warburg, Pincus Ventures tranches for the year ended December 31,
1998 was 5.7%, and the weighted average interest rate for the borrowing base
tranche for the year ended December 31, 1998 was 8.2%. The overall weighted
average interest rate for borrowings outstanding under the credit agreement for
the year ended December 31, 1998 was 6.5%. At June 30, 1999, borrowings
outstanding under the credit agreement were $64.0 million, of which $59.0
million was guaranteed by Petroleum Geo-Services and Warburg, Pincus Ventures.
The credit agreement matures on December 31, 1999.
We are obligated to pay Warburg, Pincus Ventures and Petroleum Geo-Services
a fee for their agreeing to guarantee our obligations under the credit
agreement equal to two percent per year of the total amount they have offered
to guarantee, currently $75.0 million, whether this amount is outstanding or
not, and payable in shares of our common stock valued for purposes of the
agreement at $15.00 per share. The guarantees will terminate on the completion
of this offering. We will then be allowed to borrow only up to our borrowing
base, which is currently $10.0 million.
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;
. we may not incur any liens upon our properties or assets other than
permitted liens securing indebtedness of up to $1 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
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, and sales
of interests in natural gas and oil properties not included in the
borrowing base in an aggregate amount not to exceed $4 million;
. 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 our consolidated tangible net worth as of the end of
each fiscal quarter is not less than the sum of $40 million plus 50% of
our adjusted consolidated net income for each fiscal quarter,
30
<PAGE>
if positive, and zero percent if negative, determined on a cumulative
basis, for the period beginning September 30, 1998 and ending on the last
day of the most recent fiscal quarter plus 75% of the net proceeds of
equity and equity capital contributions from sponsors received after the
closing date;
. we must ensure that the ratio of EBITDA, as defined, to our consolidated
interest expense is not less than 2.5 to 1.0 for any period of four
consecutive fiscal quarters ending on or subsequent to June 30, 1999; 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.
Year 2000 Compliance
The "Year 2000" issue is a general term used to refer to the business
implications of the arrival of the new millennium. In simple terms, on January
1, 2000, all computer hardware and software systems that use the two-digit year
convention could fail completely or create erroneous data as a result of the
system failing to recognize the two digit internal date "00" as representing
the Year 2000.
State of Readiness
We were formed recently and are engaged solely in the exploration,
development and production of natural gas and oil. Our computer hardware and
software systems were recently acquired. Based upon our analysis, evaluations
and written communications from vendors and licensors of our financial and
seismic interpretation software, we do not believe that any equipment or
programming modifications are necessary and that all these systems are or are
expected to be Year 2000 compliant. Additionally, we have assessed other less
critical information technology systems and we believe them to be compliant. We
do not believe that the risks of system malfunction resulting from the
interrelationship of our systems with those of customers, suppliers and
contractors are significant.
The Year 2000 issue affects our customers, the suppliers of our 3-D seismic
data, and other third parties with whom we do business. We are currently
investigating how the Year 2000 issue will affect computer systems controlling
pipelines and distribution facilities with which we directly or indirectly
connect and the availability of 3-D seismic data. We either have received or
are in the process of receiving written documentation from these third parties
regarding their Year 2000 readiness and issues. We have also reviewed publicly
available information, if any, as to whether their systems are Year 2000
compliant.
We expect to complete our Year 2000 assessments by September 30, 1999;
however, we plan to continue reviewing the Year 2000 issue on an on-going basis
throughout 1999.
Costs to Address Year 2000 Issues
Costs directly related to assessing Year 2000 issues through June 30, 1999
are less than $100,000 and have been expensed. We do not expect to incur
significant additional costs related to Year 2000 compliance during the
remainder of 1999. These estimated costs are based on management's best
estimates; however, there is no guarantee that these estimates will be
achieved, and actual results could differ materially from those anticipated.
Year 2000 Risk Factors
We cannot assure you that our internal operations do not have any material
issues with respect to Year 2000 compliance. In addition, we may not properly
identify all potential problems or all potentially affected systems or remedy
all problems in our systems. We have no means of ensuring that third parties
will be Year 2000 ready. The inability of third parties to complete their Year
2000 resolution process in a timely fashion
31
<PAGE>
could materially impact our results of operations and cash flows. The effect of
non-compliance by third parties is not determinable. The most reasonably likely
"worst case" impacts would be:
. impairment of our ability to deliver our production to, or receive
payment from, third parties gathering and/or purchasing our production
from affected facilities;
. impairment of the ability of third-party suppliers or service companies
to provide needed materials or services to our planned or ongoing
operations, necessitating deferral or shut-in of exploration, development
or production operations;
. impairment of our ability to receive and process 3-D seismic data, which
would hinder our ability to generate and drill exploratory prospects; and
. our inability to execute financial transactions with our banks or other
third parties whose systems fail or malfunction.
Contingency Plans
We have investigated alternatives to our computer hardware and software and
have determined that no commercially reasonable alternatives exist. Therefore,
we have been unable to develop a contingency plan other than working with our
computer hardware and software vendors to remedy any Year 2000-related problems
as quickly as possible.
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BUSINESS AND PROPERTIES
Overview
Spinnaker 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 licenses to approximately 5,700 blocks of mostly contiguous,
recent vintage 3-D seismic data in the Gulf of Mexico. This includes
approximately 4,100 blocks of 3-D seismic data under our agreement with
Petroleum Geo-Services ASA and 1,000 blocks of 3-D seismic data we acquired in
September 1999 from another provider of 3-D seismic data. Each of our material
licenses has a duration of at least 25 years. Our 3-D seismic database covers
an area of approximately 29 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 currently have a leasehold
interest in approximately 100 of these blocks. We believe that broad regional
3-D seismic analysis allows us to create a large inventory of high-quality
prospects and provides the opportunity to enhance our exploration success. We
also believe our licenses 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 of 3-D seismic data from other seismic data vendors.
Since our inception, we have participated in drilling 26 exploratory wells
in the Gulf of Mexico, with 18 of these wells being completed as discoveries.
As of August 31, 1999, Ryder Scott estimated our net proved reserves at
approximately 81.1 Bcfe, 83% of which was natural gas, representing an increase
of approximately 500% over our estimated net proved reserves of 13.4 Bcfe at
December 31, 1997. Our daily production has increased from approximately 600
Mcfe at December 31, 1997 to approximately 48,000 Mcfe at August 31, 1999.
Within our current inventory of approximately 100 lease blocks, we have
identified approximately 49 exploratory prospects and 23 leads. We expect to
drill approximately 25 of these prospects during the remainder of 1999 and
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 1999 and
2000 includes approximately $180 million for exploration, development,
leasehold acquisitions and other capital expenditures, of which we have
incurred $36.8 million through June 30, 1999.
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 chosen to assemble 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
. Open access to acreage
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. Substantial existing oil field 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.
Maintain a large database of 3-D seismic data. We believe our large database
of 3-D seismic data allows us to generate 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 also
intend to supplement that data with 3-D seismic data acquisitions from other
seismic data vendors. In addition to data acquisitions made directly by us, we
expect to continue to enter into joint ventures with other companies to share
the costs of data acquisitions and associated exploratory drilling.
Employ a rigorous prospect selection process. We leverage 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 10 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. All of our explorationists
have purchased equity in Spinnaker.
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 should
allow us to act as the operator for an increasing number of these prospects,
providing us with more control of costs, 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 one or two 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 continue
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exploring during periods of low natural gas and oil prices, we potentially can
take advantage of reduced competition for prospects and lower drilling and
other oil field service costs.
Plan of Operations
For information regarding our proposed plan of operations through the year
2000, please read "Use of Proceeds," "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Liquidity and Capital Resources"
and "Business and Properties--Overview."
Petroleum Geo-Services Data Agreement
We originally entered into our data agreement with Petroleum Geo-Services as
of December 20, 1996. 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. The agreement has been included as an exhibit
to the registration statement of which this prospectus is a part. The following
summary of this agreement discusses material provisions of this agreement and
is qualified by reference to such exhibit which we incorporate in this
prospectus by reference.
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. We are entitled to data 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. 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 transferred 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 and pre-stack time migrated data. As of August 31, 1999, we
had received approximately 4,100 blocks of standard data and had received 42
blocks of enhanced data under our Petroleum Geo-Services agreement.
Petroleum Geo-Services has begun acquiring 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 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
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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.
Petroleum Geo-Services is not obligated under our agreement to acquire any
further data of any kind. However, Petroleum Geo-Services is in the process of
acquiring approximately 200 blocks of multi-client standard data in the Gulf of
Mexico that will be covered by the agreement.
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 with 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
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customer that has purchased from Petroleum Geo-Services products and services
at least equal to 7.5% 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 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.
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 $2,000,000 of seismic related services from
Petroleum Geo-Services prior to December 31, 2002. We paid to Petroleum Geo-
Services $45,500 in 1997, $78,000 in 1998 and $39,000 in the first six months
of 1999 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 $45,000,000. Our liability for claims made
against us by Petroleum Geo-Services under the agreement is not limited.
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Use of Computer-Aided Exploration Technology
Computer-aided exploration is the process of using a computer workstation
and common database to accumulate and analyze seismic, production and other
data regarding a geographic area. In general, computer-aided exploration
involves accumulating various 2-D and 3-D seismic data with respect to a
potential drilling location and correlating that data with historical well
control and production data from similar properties. The available data is then
analyzed using computer software and modeling techniques to project the likely
geologic setting of a potential drilling location and potential locations of
undiscovered natural gas and oil reserves. This process relies on a comparison
of actual data for the potential drilling location and historical data for the
density and sonic characteristics of different types of rock formations,
hydrocarbons and other subsurface minerals, resulting in a projected three-
dimensional 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 14 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,
third 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
benefitted us when new data sets are made available only a short time prior to
state and federal lease sales.
Joint Ventures with Gulf of Mexico Partners
Early Joint Venture Agreements
We have entered into a number of joint ventures with several companies
operating in the Gulf of Mexico. In our early joint venture agreements, in
return for our access to 3-D seismic data and our exploration expertise, our
joint venture partners provided us with established Gulf of Mexico exploration
and operating track records, as well as capital. Our partners typically acted
as operator, which freed us to concentrate on exploring for new prospects.
Each of our early joint venture agreements established an area of mutual
interest covering blocks in the Gulf of Mexico for the purpose of jointly
evaluating 3-D seismic data, securing leasehold interests, evaluating natural
gas and oil prospects and drilling on those prospects. If either party acquires
an interest in any natural gas and oil lease in the area of mutual interest,
the other party may acquire a specific percentage ownership interest in that
lease. Our percentage ownership interest ranges from 25% to 65%. Our joint
venture partners are entitled to serve as the operator for any acquired lease
that is not operated by a third party.
Through our Petroleum Geo-Services agreement, we have rights to 3-D seismic
data covering substantially all of the areas of mutual interest established by
these joint venture agreements. We have licensed or provided access to this
data to our joint venture partners. In return, our joint venture partners must
reimburse us for a portion of the value of this data.
Six of these agreements are currently active. They will expire between
October 1999 and May 2000.
Recent Joint Venture Agreements
As Spinnaker matures, we intend to enter new joint ventures in order to:
. leverage our 3-D seismic database into access to additional data and new
opportunities;
. share data, risks and expenses; and
. gain access to expertise in water depths greater than 2,000 feet.
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The following is a description of two recent agreements which represent
examples of the first two joint venture benefits described above.
In January 1999, we entered into related participation agreements with two
companies. These agreements establish an identical area of mutual interest
covering approximately 1,000 blocks in the Gulf of Mexico for the purpose of
evaluating 3-D seismic data, securing leases, evaluating natural gas and oil
prospects and drilling on those prospects.
In January 1999, we also entered into an agreement with TGS-NOPEC
Geophysical Company to purchase licensing rights to data covering 435 of the
blocks in the 1,000-block area of mutual interest. We have rights to
approximately 455 additional blocks of data in this area of mutual interest
under our agreement with Petroleum Geo-Services. Each of our participation
agreements provides our joint venture partners with access rights to all our
data covering the area of mutual interest. In return, each of our joint venture
partners has agreed to reimburse us, at 50% each, for our costs to acquire
licensing rights to the data covering the 435 blocks described above.
We are responsible for evaluating the 3-D seismic data and identifying
prospects for exploration, development and production activities within the
area of mutual interest. If we acquire a leasehold interest in any of the
blocks in the area of mutual interest, one of our joint venture partners can
acquire a 25% interest and the other joint venture partner can acquire up to a
25% interest in our leasehold interest. We generally will serve as the operator
of any leases that are not operated by third parties. The parties share
exploration, development and production costs based on their respective
ownership interests.
One of the agreements requires us to allow our joint venture partner to
participate in any leasehold interest that we acquire in the area of mutual
interest, but does not give us a similar right. The other agreement provides
that each party can acquire a specific ownership interest in any leasehold
interest acquired by the other party in the area of mutual interest.
Both of the participation agreements terminate in April 2002, except that
each of our joint venture partners may extend its agreement for one year upon
payment of a $500,000 fee. The agreements also will be extended for a period of
two years for any prospects identified at the end of the term.
Exploration Activities
Significant Exploration Discoveries
Brazos A-19. Brazos A-19 is located approximately 32 miles off the Texas
coast in approximately 130 feet of water. We participated as non-operator with
a 15% working interest in drilling this discovery. The discovery well was
drilled to a total measured depth of 18,800 feet in May 1998 and encountered
150 net feet of pay. As of August 31, 1999, this discovery accounted for
approximately 15% of the present value of future net cash flows from our proved
reserves. We expect production from this discovery to begin in the fourth
quarter of 1999. We believe that no other wells will need to be drilled to
fully produce the proved reserves related to this discovery.
Garden Banks 367 (Dulcimer). Dulcimer is located approximately 159 miles off
the Louisiana coast in approximately 1,100 feet of water. We participated as
non-operator with a 33 1/3% working interest in drilling this discovery. The
discovery well was drilled to a total measured depth of 11,400 feet in February
1998 and encountered 124 net feet of pay. As of August 31, 1999, this discovery
accounted for approximately 14% of the present value of future net cash flows
from our proved reserves. Production from this discovery began in April 1999.
We believe that no other wells will need to be drilled to fully produce the
proved reserves related to this discovery.
South Timbalier 219. South Timbalier 219 is located approximately 52 miles
off the Louisiana coast in approximately 150 feet of water. We participated as
operator with a 72 3/4% working interest in drilling this
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discovery. The discovery well was drilled to a total measured depth of 10,800
feet in August 1999 and encountered 76 net feet of pay. As of August 31, 1999,
this discovery accounted for approximately 12% of the present value of future
net cash flows from our proved reserves. We expect production from this
discovery to begin in the first quarter of 2000. We are currently drilling a
second well to fully produce the proved reserves related to this discovery.
East Cameron 152. East Cameron 152 is located approximately 51 miles off the
Louisiana coast in approximately 80 feet of water. We participated as non-
operator with a 50% working interest in drilling this discovery. The discovery
well was drilled to a total measured depth of 10,000 feet in December 1998 and
encountered 74 net feet of pay. As of August 31, 1999, this discovery accounted
for approximately 10% of the present value of future net cash flows from our
proved reserves. Production from this discovery began in April 1999. We believe
that no other wells will need to be drilled to fully produce the proved
reserves related to this discovery.
South Timbalier 220. South Timbalier 220 is located approximately 40 miles
off the Louisiana coast in approximately 150 feet of water. We participated as
non-operator with a 33 1/3% working interest in drilling this discovery. The
discovery well was drilled to a total measured depth of 14,600 feet in
September 1997 and encountered 149 net feet of pay. As of August 31, 1999, this
discovery accounted for approximately 10% of the present value of future net
cash flows from our proved reserves. Production from this discovery began in
August 1998. We believe that no other wells will need to be drilled to fully
produce the proved reserves related to this discovery.
West Cameron 39. West Cameron 39 is located approximately seven miles off
the Louisiana coast in approximately 30 feet of water. We participated as
operator with a 60% working interest in drilling this discovery. The # 1 well
was drilled to a total measured depth of 11,000 feet in August 1998 and
encountered 140 net feet of pay. The # 2 well was drilled to a total measured
depth of 12,600 feet in March 1999 and encountered 236 net feet of pay. The # 3
well was drilled to a total measured depth of 12,000 feet in May 1999 and
encountered 45 net feet of pay. As of August 31, 1999, the wells accounted for
approximately 9% of the present value of future net cash flows from our proved
reserves. Production from the # 1 well began in January 1999, and we expect
production to commence from the # 2 and # 3 wells in the fourth quarter of
1999. We believe that no other wells will need to be drilled to fully produce
the proved reserves related to this discovery.
Mississippi Canyon 496 (Zia). Zia is located approximately 33 miles off the
Louisiana coast in approximately 1,800 feet of water. We participated as non-
operator with a 12 1/2% working interest in drilling this discovery. The
discovery well was drilled to a total measured depth of 21,800 feet in November
1998 and encountered 217 net feet of pay. As of August 31, 1999, this discovery
accounted for approximately 7% of the present value of future net cash flows
from our proved reserves. A second well is planned by the second quarter of
2000. We expect production from this discovery to begin by the fourth quarter
of 2001.
High Island 235. High Island 235 is located approximately 37 miles off the
Texas coast in approximately 60 feet of water. We participated as operator with
a 50% working interest in drilling this discovery. The discovery well was
drilled to a total measured depth of 15,400 feet in January 1999 and
encountered 125 net feet of pay. As of August 31, 1999, this discovery
accounted for approximately 6% of the present value of future net cash flows
from our proved reserves. Production from this discovery began in April 1999.
We believe that no other wells will need to be drilled to fully produce the
proved reserves related to this discovery.
Vermilion 375. Vermilion 375 is located approximately 87 miles off the
Louisiana coast in approximately 300 feet of water. We participated as operator
with a 70% working interest in drilling this discovery. The discovery well was
drilled to a total measured depth of 10,500 feet in June 1999 and encountered
284 net feet of pay. As of August 31, 1999, this discovery accounted for
approximately 5% of the present value of future net cash flows from our proved
reserves. We expect production from this discovery to begin by the second
quarter of 2000. We believe that no other wells will need to be drilled to
fully produce the proved reserves related to this discovery.
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South Pelto 18. South Pelto 18 is located approximately 14 miles off the
Louisiana coast in approximately 50 feet of water. We participated as non-
operator with a 25% working interest in drilling this discovery. The discovery
well was drilled to a total measured depth of 17,100 feet in June 1998 and
encountered 145 net feet of pay. As of August 31, 1999, this discovery
accounted for approximately 5% of the present value of future net cash flows
from our proved reserves. Production from this discovery began in December
1998. We are currently evaluating the need for a development well for this
discovery.
West Cameron 522. West Cameron 522 is located approximately 90 miles off the
Louisiana coast in approximately 180 feet of water. We participated as non-
operator with a 46% working interest in drilling this discovery. The #1 well
was drilled to a total measured depth of 10,500 feet in February 1997 and
encountered 136 net feet of pay. The #2 well was drilled to a total measured
depth of 11,300 feet in January 1998 and encountered 74 net feet of pay. As of
August 31, 1999, the wells accounted for approximately 4% of the present value
of future net cash flows from our proved reserves. Production from these
discoveries began in March 1998. We believe that no other wells will need to be
drilled to fully produce the proved reserves related to this discovery.
Other Discoveries. From inception through August 31, 1999, we participated
in the successful drilling of an additional three exploratory wells. As of
August 31, 1999, these discoveries accounted for approximately 3% of the
present value of future net cash flows from our proved reserves.
Planned Exploration Prospects
We expect to drill approximately 25 exploration prospects during the
remainder of 1999 and 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 seven 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 present value of our reserves at August 31, 1999 based on a
reserve report prepared by Ryder Scott. Appendix A to this prospectus contains
a letter prepared by Ryder Scott summarizing the reserve report. The present
values, discounted at 10% per annum, of estimated future net cash flows before
income taxes shown in the table are not intended to represent the current
market value of the estimated natural gas and oil reserves Spinnaker owns. For
further information concerning the present value of future net cash flows from
these proved reserves, please read note 13 of the notes to our consolidated
financial statements.
The present value of future net cash flows before income tax as of August
31, 1999 was determined by using the August 31, 1999 prices of $2.83 per MMBtu
of natural gas at Henry Hub, Louisiana and $22.11 per Bbl of oil at the Cushing
NYMEX Pricing Hub.
<TABLE>
<CAPTION>
Proved Reserves
------------------------------
Developed Undeveloped Total
--------- ----------- --------
<S> <C> <C> <C>
Natural gas (MMcf)........................ 34,413 32,889 67,302
Oil and condensate (MBbls)................ 503 1,804 2,307
Total proved reserves (MMcfe)............. 37,433 43,711 81,144
Present value (in thousands).............. $79,735 $72,488 $152,223
</TABLE>
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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 need to 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
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 August 31, 1999, 70% of our
proved reserves were either proved undeveloped or proved 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 August 31, 1999, approximately 54% of our estimated equivalent net 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 SEC requirements, we generally
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.
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>
Year Ended Six Months
December Ended June
31, 30,
----------- -----------
1997 1998 1998 1999
----- ----- ----- -----
<S> <C> <C> <C> <C>
Production:
Natural gas (MMcf)................................... 70 1,675 482 4,258
Oil and condensate (MBbls)........................... -- 12 1 49
Total (MMcfe)........................................ 70 1,747 488 4,552
Average sales price per unit:
Natural gas (per Mcf)................................ $2.87 $1.89 $1.97 $2.09
Oil and condensate (per Bbl)......................... 18.51 11.61 13.24 14.70
Total (per Mcfe)..................................... 2.87 1.89 1.97 2.11
Expenses (per Mcfe):
Lease operating expense.............................. $1.03 $0.27 $0.68 $0.26
Depreciation, depletion and amortization--natural gas
and oil properties.................................. 0.97 1.57 1.33 1.67
</TABLE>
42
<PAGE>
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>
Year Ended
December 31, Six Months
--------------- Ended June
1997 1998 30, 1999
------- ------- ----------
(in thousands)
<S> <C> <C> <C>
Acquisition costs:
Unproved properties.......................... $ 4,458 $15,791 $15,349
Proved properties............................ -- -- --
Exploration.................................... 7,116 46,620 7,676
Development.................................... 2,422 23,067 13,502
------- ------- -------
Total costs incurred........................... $13,996 $85,478 $36,527
======= ======= =======
</TABLE>
Drilling Activity
The following table shows our drilling activity for the years ended December
31, 1997 and 1998 and the six months ended June 30, 1999. 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>
Six
Months
Ended
June 30,
1997 1998 1999
--------- --------- ---------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
<S> <C> <C> <C> <C> <C> <C>
Exploratory Wells:
Productive................................ 4 1.5 9 2.9 3 2.0
Nonproductive............................. -- -- 6 2.3 2 1.0
--- --- --- --- --- ---
Total................................... 4 1.5 15 5.2 5 3.0
=== === === === === ===
Development Wells:
Productive................................ -- -- -- -- -- --
Nonproductive............................. -- -- -- -- -- --
--- --- --- --- --- ---
Total................................... -- -- -- -- -- --
=== === === === === ===
</TABLE>
Since June 30, 1999, we have drilled two gross (1.4 net) productive
exploratory wells and no nonproductive exploratory wells. We have drilled one
gross (1.0 net) exploratory well which has been temporarily abandoned. As of
September 27, 1999, we were drilling four gross (1.5 net) 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, 1999:
<TABLE>
<CAPTION>
Total
Productive
Wells
------------
Gross Net
------ -----
<S> <C> <C>
Natural gas.................................................. 15 6.3
Oil.......................................................... 1 0.1
----- -----
Total...................................................... 16 6.4
===== =====
</TABLE>
Productive wells consist of producing wells and wells capable of production,
including natural gas wells awaiting pipeline connections to commence
deliveries and oil wells awaiting connection to production facilities.
43
<PAGE>
Acreage Data
The following table presents information regarding our developed and
undeveloped lease acreage as of June 30, 1999. 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................ 34,020 16,047 217,969 75,626 251,989 91,673
Offshore Texas.................... 23,040 6,966 115,200 40,090 138,240 47,056
Texas State Waters................ 1,200 300 27,866 11,553 29,066 11,853
------ ------ ------- ------- ------- -------
Total........................... 58,260 23,313 361,035 127,269 419,295 150,582
====== ====== ======= ======= ======= =======
</TABLE>
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 10 years if located in deeper
waters of the Gulf of Mexico.
Marketing
Most of our natural gas and oil production is sold by our operators 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 currently are not 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 year ended December 31, 1998, sales to
Cokinos Energy Corporation were 100% of our natural gas and oil revenues.
Currently, all of our natural gas production is sold at current market prices
to Columbia Energy Services. Columbia generally is not required to pay us for
our production until 60 to 90 days after we deliver the production. As a
result, if Columbia were to default on its payment obligations to us for our
production, 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 Columbia or any other customer would adversely
affect our ability to market our production.
44
<PAGE>
To reduce our exposure to fluctuations in the prices of natural gas and oil,
we have recently begun to enter into hedging arrangements. Hedging arrangements
expose us to risk of financial loss 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.
In addition, these hedging arrangements may 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 hedging
transactions. For further information concerning our hedging transactions,
please read "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Liquidity and Capital Resources--Hedging Transactions."
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. 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. In
1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed
all remaining Natural Gas Act and Natural Gas Policy Act price and non-price
controls affecting producer sales of natural gas effective January 1, 1993.
Congress could, however, reenact 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 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
45
<PAGE>
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 has recently begun a broad
review of its transportation regulations, including how its regulations operate
in conjunction with state proposals for retail natural gas marketing
restructuring, whether to eliminate cost-of-service based rates for short-term
transportation, whether to allocate all short-term capacity on the basis of
competitive auctions, and whether changes to its long-term transportation
service policies may be appropriate to avoid a market bias toward short-term
contracts. We cannot predict what 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.
Commencing in May 1994, the Federal Energy Regulatory Commission issued a
series of orders that, among other matters, slightly narrowed its statutory
tests for establishing gathering status and reaffirmed that, except in
situations in which the gatherer acts in concert with an interstate pipeline
affiliate to frustrate the Federal Energy Regulatory Commission's
transportation policies, it does not have pervasive jurisdiction over natural
gas gathering facilities and services, and that such facilities and services
located in state jurisdictions are most properly regulated by state
authorities. This Federal Energy Regulatory Commission action may further
encourage regulatory scrutiny of natural gas gathering by state agencies. We do
not believe that we will be affected by the Federal Energy Regulatory
Commission's new gathering policy any differently than other natural gas
producers, gatherers and marketers.
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 are 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
46
<PAGE>
obtained in all cases. We currently have two supplemental bonds in place. 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 has recently issued a notice of proposed
rulemaking in which it proposes to amend its regulations governing the
calculation of royalties and the valuation of crude oil produced from federal
leases. This proposed rule would modify the valuation procedures for both
arm's-length and non-arm's-length crude oil transactions, establish a new form
for collecting value differential data, and amend the valuation procedure for
the sale of federal royalty oil. We cannot predict what action the Minerals
Management Service will take on this matter. We believe that these rules, if
adopted as proposed, 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. Effective as of January 1, 1995, the Federal Energy Regulatory
Commission implemented regulations establishing an indexing system for
transportation rates for oil that could increase the cost of transporting oil
to the purchaser. Other factors being equal, this order may tend to increase
transportation costs or reduce wellhead prices for crude oil. However, we do
not believe that these regulations affect us any differently than other natural
gas producers, gatherers and marketers.
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 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 million in other damages. Few defenses exist
to the liability imposed by the Oil Pollution Act.
The Oil Pollution Act also requires a responsible party to submit proof of
its financial responsibility 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 requires parties
responsible for offshore facilities to provide financial assurance in the
amount of $35 million to cover potential Oil Pollution Act liabilities. This
amount can be increased up to $150 million if a study by the Minerals
Management Service
47
<PAGE>
indicates that an amount higher than $35 million should be required. On August
11, 1998, the Minerals Management Service adopted a rule implementing these Oil
Pollution Act financial responsibility requirements. We are in compliance with
this new rule.
The Oil Pollution Act 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
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on some classes of
persons that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator of
the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances
released into the environment.
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. Implementation of 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;
48
<PAGE>
. 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 oil field 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 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 August 31, 1999, we had 32 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.
49
<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......... 45 Chairman, President, Chief Executive Officer and Director
James M. Alexander...... 47 Vice President, Chief Financial Officer and Secretary
William D. Hubbard...... 55 Vice President--Exploration
Kelly M. Barnes......... 45 Vice President--Land
L. Scott Broussard...... 41 Vice President--Drilling and Production
Jeffrey C. Zaruba....... 35 Treasurer
Reidar Michaelsen....... 55 Director
Bjarte Bruheim.......... 43 Director
Howard H. Newman........ 52 Director
Jeffrey A. Harris....... 43 Director
Michael E. McMahon...... 51 Director Appointee
</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
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.
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 1997, 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.
L. Scott Broussard has served as Vice President--Drilling and Production of
Spinnaker since August 1999 after joining the Company 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
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.
50
<PAGE>
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.
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.
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.
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
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, RenaissanceRe Holdings, Ltd.,
Cox Insurance Holdings, Plc, Eagle Family Foods Holdings, Inc., and several
private companies, including Encore Acquisition Partners, Inc.
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, Knoll, Inc. and several privately held
companies, including Lariat Petroleum, Inc.
Michael E. McMahon was appointed as a director of Spinnaker in July 1999
effective on completion of this offering. 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.
Our board of directors currently has five members. Our stockholders have
entered into an agreement to elect our board of directors, electing two members
designated by Petroleum Geo-Services, two members designated by Warburg, Pincus
Ventures and one member designated by our chief executive officer. This
agreement will terminate on completion of this offering. 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. We have appointed
Mr. McMahon to our board of directors effective on completion of this offering.
In addition, we intend to appoint an additional independent director after
completion of this offering, at which time our board of directors would consist
of seven members.
51
<PAGE>
Committees of the Board of Directors
Our board of directors has established an audit committee and a compensation
committee.
Audit Committee
The audit committee currently consists of Messrs. Michaelsen, Bruheim,
Newman and Harris. The audit committee is responsible for:
. recommending the selection of our independent accountants;
. reviewing and approving the scope of our independent accountants' audit
activity and extent of non-audit services;
. reviewing with management and the independent accountants the adequacy of
our basic accounting systems and the effectiveness of our internal audit
plan and activities;
. reviewing our financial statements with management and the independent
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. Michaelsen,
Bruheim, Newman and Harris. This committee's responsibilities include:
. administering and granting awards under our 1998 Stock Option Plan and
1999 Stock Incentive 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.
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. Prior to July 1998, compensation matters were addressed by our
entire board of directors, on which Mr. Jarvis serves. Mr. Jarvis purchased
shares of our common stock and preferred stock in 1996, 1997 and 1998. Mr.
Jarvis also is a party to an agreement pursuant to which we granted him
registration rights for those shares. For a description of these transactions,
please read "Certain Transactions."
Compensation of Directors
We paid no compensation to any non-employee director in 1998. Following this
offering, non-employee directors unaffiliated with Warburg, Pincus Ventures or
Petroleum Geo-Services are expected to receive director fees of $18,000 per
year. In addition, these directors also will be awarded options to purchase
4,000 shares of common stock per year, granted quarterly with an exercise price
equal to the closing price at the end of each quarter.
52
<PAGE>
Executive Compensation
The following table sets forth information regarding the compensation of our
Chief Executive Officer, and each of our three other most highly compensated
executive officers for 1998. 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% of the total annual salary and bonus reported for each
executive officer:
1998 Summary Compensation Table
<TABLE>
<CAPTION>
Annual
Compensation
----------------
Name and Principal Position Salary Bonus
--------------------------- -------- -------
<S> <C> <C>
Roger L. Jarvis, Chairman, President and Chief Executive
Officer..................................................... $265,000 $91,498
James M. Alexander, Vice President, Chief Financial Officer
and Secretary............................................... 184,000 67,342
William D. Hubbard, Vice President--Exploration.............. 175,000 56,042
Kelly M. Barnes, Vice President--Land........................ 118,000 37,789
</TABLE>
Each of the bonus amounts shown in the table was awarded by the board of
directors after consideration of the performance of each of the officers and
bonuses paid to similarly-situated executives of companies of comparable size
in the natural gas and oil industry.
Stock Option Grants
Since our inception, our four most highly compensated executive officers
were granted the following options:
. Mr. Jarvis was granted options to purchase 608,000 shares at $5.00 per
share and 384,000 shares at $15.63 per share in December 1996;
. Mr. Alexander was granted options to purchase 243,200 shares at $5.00 per
share and 153,600 shares at $15.63 per share in December 1996;
. Mr. Hubbard was granted options to purchase 152,000 shares at $5.00 per
share and 96,000 shares at $15.63 per share in April 1997; and
. Mr. Barnes was granted options to purchase 68,400 shares at $5.00 per
share and 43,200 shares at $15.63 per share in April 1997 and 30,000
shares at $15.63 per share in January 1999.
The options granted to each of our four most highly compensated executive
officers vest 20% on the grant date and 20% on each anniversary of the grant
date.
In addition, if Mr. Jarvis or Mr. Alexander terminates his employment with
us for good reason, all of the options granted to him will become immediately
exercisable. Good reasons for termination include:
. an unremedied material breach of the employment agreement by Spinnaker;
. relocation of Spinnaker's executive offices outside the Houston, Texas
metropolitan area; and
. in the case of Mr. Alexander, the termination by Mr. Jarvis of his own
employment.
If we terminate Mr. Jarvis or Mr. Alexander without cause, he may exercise
the number of options to which he would otherwise be entitled under the vesting
schedule of the options described above plus an additional 20%. For other
general terms of these options, please read "Management--1998 Stock Option
Plan."
On completion of this offering, options to purchase the following number of
shares at the initial public offering price are expected to be granted to our
four most highly compensated executive officers: 244,529 to Mr. Jarvis; 95,898
to Mr. Alexander; 59,960 to Mr. Hubbard; and 33,593 to Mr. Barnes.
53
<PAGE>
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.
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,
and 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 as discussed above under "--Stock Option Grants",
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, 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 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, 1999, 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;
54
<PAGE>
. 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.
At August 31, 1999, we had outstanding options to purchase a total of
2,673,242 shares of common stock, of which 1,520,608 are exercisable at $5.00
per share and 1,152,634 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.
55
<PAGE>
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 maximum aggregate number of shares
that may be issued under the plan or to change this 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.
On completion of this offering, options under the 1999 plan to purchase
633,824 shares of common stock will be granted with an exercise price equal to
the initial public offering price. Each of the options will be 20% vested
immediately on grant and will generally vest an additional 20% on each
anniversary of the grant date.
1999 Employee Stock Purchase Plan
Our board of directors adopted our 1999 Employee Stock Purchase Plan, and
our stockholders approved this plan, in September 1999. A total of 100,000
shares of common stock has been reserved for issuance under the purchase plan
plus annual increases equal to the lesser of 25,000 shares or a lesser amount
determined by our board of directors. Participants may purchase common stock
through payroll deductions of up to 15% of the participant's compensation,
subject to some limits. The price of stock purchased under the purchase plan is
85% of the lower of the fair market value of the common stock at the beginning
of each applicable offering period and at the end of each purchase period.
56
<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 our other
stockholders, each of whom is a current or former employee of Spinnaker,
together holding 100% of our common stock prior to this offering, 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 $2,000,000 of seismic related services from
Petroleum Geo-Services prior to December 31, 2002. Our purchases of seismic
related services from Petroleum Geo-Services were $45,500 in 1997, $78,000 in
1998, and $39,000 for the six months ended June 30, 1999. 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, our executive officers, directors and 5% stockholders
have invested cash and other property in Spinnaker in exchange for shares of
our preferred stock and our common stock. The following table summarizes the
shares of our common stock and preferred stock acquired from us by our
executive officers, directors and 5% stockholders since our inception.
<TABLE>
<CAPTION>
Preferred Common
Executive Officers, Directors and 5% Stockholders Stock Stock
------------------------------------------------- --------- ---------
<S> <C> <C>
Warburg, Pincus Ventures, L.P. (1).................. 2,399,500 1,037,500
Petroleum Geo-Services ASA (2)...................... 599,500 3,934,700
Roger L. Jarvis (3)................................. 12,706 134,400
James M. Alexander (4).............................. 5,107 25,600
William D. Hubbard (5).............................. 3,192 16,000
Kelly M. Barnes (6)................................. 1,436 7,200
</TABLE>
- --------
(1) Warburg, Pincus Ventures paid us approximately $60 million for the shares
listed above. Excludes 13,048 shares of common stock that are deliverable
to Warburg, Pincus Ventures as consideration for Warburg, Pincus Ventures'
agreement to guarantee a portion of our obligations under our credit
facility for the period commencing July 1, 1999 and ending October 4, 1999.
Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Liquidity and Capital Resources--Credit
Agreement" for a description of our credit facility. Two of our directors,
Howard H. Newman and Jeffrey A. Harris, are affiliated with Warburg, Pincus
Ventures. Please read "Security Ownership of Management and Certain
Beneficial Owners" for a description of Messrs. Newman's and Harris'
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 and for an additional $15 million. Please read "Business and
Properties--Petroleum Geo-Services Data Agreement" for a description of the
Petroleum Geo-Services Data Agreement. Excludes 13,048 shares of common
stock that are deliverable to Petroleum Geo-Services as consideration for
Petroleum Geo-Services' agreement to guarantee a portion of our obligations
under
57
<PAGE>
our credit facility for the period commencing July 1, 1999 and ending
October 4, 1999. Please read "Certain Transactions--Credit Agreement" for a
description of our credit facility. Two of our directors, Reidar Michaelsen
and Bjarte Bruheim, are affiliated with Petroleum Geo-Services. Please read
"Security Ownership of Management and Certain Beneficial Owners" for a
description of Messrs. Michaelsen's and Bruheim'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.
Each share of preferred stock is convertible into two shares of common
stock. Each of the persons named in the table above will convert all of their
shares of preferred stock into shares of common stock upon consummation of our
initial public offering. In addition, Warburg, Pincus Ventures, Petroleum Geo-
Services, Mr. Jarvis and Mr. Alexander have 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. For purposes of
determining the number of shares of common stock that each person will receive
in lieu of the cash dividends, the common stock to be issued to these persons
will be 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. (formerly NationsBank, N.A.) each of which is an affiliate of one
of the underwriters for this offering. Borrowings under the credit agreement
were used to fund exploration and development activities. The credit agreement
is 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. Please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources--Credit Agreement" for a more
detailed description of the credit agreement.
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.
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<PAGE>
SECURITY OWNERSHIP OF MANAGEMENT
AND CERTAIN BENEFICIAL HOLDERS
The following table presents information regarding beneficial ownership of
our common stock as of September 28, 1999 by:
. each person who we know owns beneficially more than 5% of our common
stock;
. each of our directors;
. our chief executive officer and each of our three 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 SEC, shares are deemed to be "beneficially owned" by a
person if he directly or indirectly has or shares the power to vote or dispose
of these shares, whether or not he has any pecuniary interest in these shares,
or if he 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 and Barnes include 595,200,
238,080, 148,800 and 72,960 shares, respectively, that may be acquired within
60 days through the exercise of stock options. The table does not reflect
beneficial ownership of shares issuable upon exercise of stock options expected
to be granted upon completion of this offering. Please note that the address of
Warburg, Pincus Ventures, L.P. and Messrs. Newman and Harris is 466 Lexington
Avenue, 10th Floor, New York, New York 10017, and the address of Petroleum Geo-
Services and Messrs. Michaelsen and Bruheim 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 54.8% 33.3%
Petroleum Geo-Services ASA(2)................ 5,388,743 43.4 26.4
Roger L. Jarvis(3)........................... 711,355 5.5 3.4
James M. Alexander........................... 275,963 2.2 1.3
William D. Hubbard........................... 171,184 1.4 *
Kelly M. Barnes.............................. 83,032 * *
Reidar Michaelsen(2)......................... 5,388,743 43.4 26.4
Bjarte Bruheim(2)............................ 5,388,743 43.4 26.4
Howard H. Newman(1).......................... 6,800,585 54.8 33.3
Jeffrey A. Harris(1)......................... 6,800,585 54.8 33.3
All executive officers and directors as a
group
(10 persons)................................ 13,460,378 99.7 62.6
</TABLE>
- --------
* Represents beneficial ownership of less than 1%.
(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. 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 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.
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<PAGE>
(2) The 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) Mr. Jarvis has granted options to purchase 21,920 shares of common stock
owned by him at $2.50 per share to employees of Spinnaker.
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<PAGE>
DESCRIPTION OF CAPITAL STOCK
Our authorized capital stock consists of 50,000,000 shares of common stock,
par value $.01 per share, and 10,000,000 shares of preferred stock, par value
$.01 per share. As of June 30, 1999, we had outstanding 5,132,200 shares of
common stock and 3,030,920 shares of preferred stock. Immediately prior to
completion of this offering, each outstanding share of our preferred stock will
be converted into two shares of common stock. On completion of this offering,
we will have outstanding 20,420,384 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.
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Registration Rights
We, Petroleum Geo-Services, Warburg, Pincus Ventures and 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 180 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 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 SEC Form S-3.
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. An
underwriter participating in these offerings may limit the number of shares
offered, and the number will be allocated first to us, then to our 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% 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 transaction in which the person becomes an
interested stockholder or the business combination;
. upon completion of the transaction that results in the person becoming an
interested stockholder, the interested stockholder owns at least 85% 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
. following 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 become interested
stockholders before common stock of the company is listed on The Nasdaq Stock
Market's National Market.
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 of directors, including
discouraging takeover attempts that might result in a premium over the market
price for the shares of our common stock.
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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.
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,
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<PAGE>
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 Harris Trust and
Savings Bank.
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<PAGE>
SHARES ELIGIBLE FOR FUTURE SALE
On completion of this offering, we will have 20,420,384 shares of common
stock outstanding, or 21,620,384 shares if the underwriters' over-allotment
option is exercised in full. Of these outstanding shares of common stock, the
shares sold in this offering will be freely tradeable without restriction. Any
shares sold on exercise of the underwriters' over-allotment option also would
be freely tradeable. None of the remaining outstanding shares of common stock
have been registered under the Securities Act, which means that they may be
resold only in transactions registered under the Securities Act or exempt from
registration. However, holders of 12,377,098 shares of the remaining
outstanding common stock have agreed with the underwriters not to sell any of
these shares for a period of 180 days after the date of this prospectus,
subject to some exceptions.
Prior to this offering, there has been no public market for our common
stock. The market price of our common stock could drop because of sales of a
large number of shares in the open market following this offering or the
perception that those sales may occur. These factors also could make it more
difficult for us to raise capital through future offerings of common stock.
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<PAGE>
UNDERWRITING
Under the terms and subject to the conditions contained in an underwriting
agreement dated September 28, 1999, we have agreed to sell to the underwriters
named below the following respective numbers of shares of common stock:
<TABLE>
<CAPTION>
Number
Underwriter of Shares
----------- ---------
<S> <C>
Credit Suisse First Boston Corporation............................. 2,500,000
Donaldson, Lufkin & Jenrette Securities Corporation................ 2,500,000
Banc of America Securities LLC..................................... 1,300,000
Prudential Securities Incorporated................................. 1,300,000
Nesbitt Burns Securities Inc....................................... 400,000
---------
Total............................................................ 8,000,000
=========
</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 1,200,000 additional shares from us at the initial 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 $0.55 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 initial public 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.................. $0.91 $0.91 $7,280,000 $8,372,000
Expenses payable by us.. $0.13 $0.11 $1,000,000 $1,000,000
</TABLE>
The underwriters do not intend to confirm sales to any accounts over which
they exercise discretionary authority.
We intend to use more than 50% 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, Bank of America, N.A. and Bank of Montreal, each an affiliate
of one of the underwriters. Credit Suisse First Boston, New York Branch, is an
affiliate of Credit Suisse First Boston Corporation, Bank of America is an
affiliate of Banc of America Securities LLC and Bank of Montreal is an
affiliate of Nesbitt Burns Securities Inc. 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. This rule provides
generally that if more than 10% of the net proceeds from the sale of common
stock, not including underwriting compensation, is paid to the underwriters or
their affiliates, the initial public offering price of the common stock may not
be higher than that recommended by a "qualified independent underwriter"
meeting specified standards. Accordingly, Donaldson, Lufkin & Jenrette
Securities
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<PAGE>
Corporation has assumed the responsibilities of acting as the qualified
independent underwriter in pricing this offering and conducting due diligence.
The initial public offering price of the shares of common stock is no higher
than the price recommended by Donaldson, Lufkin & Jenrette Securities
Corporation. We have agreed to pay $5,000 to Donaldson, Lufkin & Jenrette
Securities Corporation as compensation for its services as qualified
independent underwriter in this offering.
We currently comply in all material respects with the terms of the credit
agreement we entered into with the affiliates of the underwriters. The
underwriters decided to participate in the distribution of common stock in this
offering independent of their affiliates who currently are lenders to Spinnaker
and who will receive a portion of the net proceeds of this offering. The
lenders affiliated with underwriters in this offering had no involvement in
determining whether or when to sell common stock in this offering or the terms
of this offering. Excluding the proceeds to the lenders affiliated with
underwriters as previously described, the underwriters will not receive any
benefit from this offering other than their 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% 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 180 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.
Our common stock has been approved for listing on The Nasdaq Stock Market's
National Market under the symbol "SPNX."
Before this offering, there has been no public market for our common stock.
The initial public offering price has been determined by negotiations between
us and the underwriters. The principal factors considered in determining the
initial public offering price included:
. the information in this prospectus and available to the underwriters;
. the history of and prospects for the industry in which we compete;
. the ability of our management;
. our past results of operations and the prospects for our future earnings;
. the present state of our development and our current financial condition;
. the general condition of the securities markets at the time of this
offering; and
. the recent market prices of, and the demand for, publicly traded common
stock of generally comparable companies.
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.
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<PAGE>
. 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 transaction or in 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 Nasdaq National Market or otherwise and, if commenced, may be
discontinued at any time.
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
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<PAGE>
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.
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 not related 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 have filed with the
SEC relating to our common stock. As permitted by SEC rules, this prospectus
does not contain all of the information we have included in the registration
statement and the accompanying exhibits and schedules we filed with the SEC.
You may refer to the registration statement, exhibits and schedules for more
information about us and our common stock. You can read and copy the
registration statement, exhibits and schedules at the SEC's Public Reference
Room at 450 Fifth Street, N.W., Washington, D.C. 20549 and at the SEC's
regional offices located at Seven World Trade Center, New York, New York 10048,
and at 500 West Madison Street, Chicago, Illinois 60661. You can obtain
information about the operation of the SEC's Public Reference Room by calling
the SEC at 1-800-SEC-0330. The SEC also maintains an Internet site that
contains reports, proxy and information statements, and other information
regarding issuers that file electronically with the SEC. The address of that
site is http://www.sec.gov.
Following this offering, we will be required to file current reports,
quarterly reports, annual reports, proxy statements and other information with
the SEC. You may read and copy those reports, proxy statement and other
information at the SEC's Public Reference Room and regional offices or through
its Internet site. We intend to furnish our stockholders with annual reports
that will include a description of our operations and audited consolidated
financial statements certified by an independent public accounting firm.
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<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.
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. Mineral Management Services 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 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.
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<PAGE>
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet of natural gas.
Mcfe. One 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. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million British Thermal Units.
MMcf. One million cubic feet of natural gas.
MMcfe. One 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 individual and 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.
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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, 1997 and 1998 and June 30,
1999 (unaudited)........................................................ F-3
Consolidated Statements of Operations for the period from Inception
(December 20, 1996) through December 31, 1996, for the years ended
December 31, 1997and 1998 and for the six months ended June 30, 1998
(unaudited) and 1999 (unaudited)........................................ F-4
Consolidated Statements of Equity for the period from Inception (December
20, 1996) through December 31, 1996, for the years ended December 31,
1997 and 1998 and for the six months ended June 30, 1999 (unaudited).... F-5
Consolidated Statements of Cash Flows for the period from Inception
(December 20, 1996) through December 31, 1996, for the years ended
December 31, 1997 and 1998 and for the six months ended June 30, 1998
(unaudited) and 1999 (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, 1997 and 1998,
and the related consolidated statements of operations, equity and cash flows
for the period from inception (December 20, 1996) through December 31, 1996 and
for each of the two years in the period ended December 31, 1998. 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 generally accepted auditing
standards. 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, 1997 and 1998, and the results of its
operations and its cash flows for the period from inception (December 20, 1996)
through December 31, 1996, and for each of the two years in the period ended
December 31, 1998, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP
Houston, Texas
April 13, 1999 (except with
respect to the Stock Split
discussed in Notes 2 and 5, as
to which the date is
September 1, 1999)
F-2
<PAGE>
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In Thousands Except Unit/Share Data)
<TABLE>
<CAPTION>
As of December
31, As of
----------------- June 30,
1997 1998 1999
------- -------- ----------
ASSETS (Unaudited)
<S> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents...................... $ 2,682 $ 2,141 $ 3,976
Accounts receivable............................ 3,603 3,821 10,691
Other.......................................... 63 775 489
------- -------- --------
Total current assets........................ 6,348 6,737 15,156
------- -------- --------
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost
accounting--
Proved properties............................. 6,452 71,091 104,026
Unproved properties and properties under
development, not being amortized............. 7,544 28,383 31,975
Furniture and fixtures......................... 1,940 2,798 3,108
------- -------- --------
15,936 102,272 139,109
Less--Accumulated depreciation, depletion and
amortization.................................. (484) (6,665) (14,744)
------- -------- --------
Total property and equipment................ 15,452 95,607 124,365
------- -------- --------
OTHER ASSETS:
Organization costs and other, net.............. 558 425 31
------- -------- --------
Total assets................................ $22,358 $102,769 $139,552
======= ======== ========
<CAPTION>
LIABILITIES AND EQUITY
<S> <C> <C> <C>
CURRENT LIABILITIES:
Accounts payable and accrued liabilities....... $ 2,096 $ 18,378 $ 10,005
Short-term debt................................ -- 19,000 64,000
------- -------- --------
Total current liabilities................... 2,096 37,378 74,005
------- -------- --------
ACCRUED PREFERRED DIVIDENDS PAYABLE............. 1,383 8,478 13,566
OTHER LONG-TERM LIABILITIES..................... -- -- --
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY:
Preferred units, without par value; authorized
3,030,720 units; issued 958,921 units at
December 31, 1997; stated value $25 (net of
issuance costs of $1,291)..................... 22,682 -- --
Preferred stock, $.01 par value; authorized
3,030,920 shares; issued 3,030,920 shares at
December 31, 1998 and June 30, 1999........... -- 30 30
Common units, without par value; authorized
14,701,440 units; 3,960,000 units outstanding
at December 31, 1997.......................... -- -- --
Common stock, $.01 par value; authorized
22,000,000 shares; 4,082,200 shares and
5,132,200 shares outstanding at December 31,
1998 and June 30, 1999, respectively.......... -- 20 26
Additional paid-in capital..................... 29 74,649 79,694
Accumulated deficit............................ (3,832) (17,786) (27,769)
------- -------- --------
Total equity................................ 18,879 56,913 51,981
------- -------- --------
Total liabilities and equity................ $22,358 $102,769 $139,552
======= ======== ========
</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 Unit/Share and Per Unit/Share Data)
<TABLE>
<CAPTION>
For the
Period from
Inception
(December 20, For the Year Ended For the Six Months
1996) through December 31, Ended June 30,
December 31, -------------------- --------------------
1996 1997 1998 1998 1999
------------- --------- --------- --------- ---------
(Unaudited)
<S> <C> <C> <C> <C> <C>
REVENUES.................. $ -- $ 201 $ 3,298 $ 961 $ 9,583
--------- --------- --------- --------- ---------
EXPENSES:
Depreciation, depletion
and amortization--
natural gas & oil
properties............. -- 68 2,738 648 7,619
Impairment of natural
gas & oil properties... -- -- 2,642 -- --
Depreciation and
amortization--other.... 10 349 437 136 98
General and
administrative......... 318 1,965 3,809 1,959 2,244
Stock appreciation
rights expense......... -- -- -- 904 1,651
Lease operating
expenses............... -- 72 474 331 1,183
--------- --------- --------- --------- ---------
Total expenses........ 328 2,454 10,100 3,978 12,795
--------- --------- --------- --------- ---------
LOSS FROM OPERATIONS...... (328) (2,253) (6,802) (3,017) (3,212)
--------- --------- --------- --------- ---------
OTHER INCOME (EXPENSE):
Interest income......... -- 91 221 133 85
Interest expense........ -- -- (516) -- (2,007)
Capitalized interest.... -- -- 237 -- 634
--------- --------- --------- --------- ---------
Total other income
(expense)............ -- 91 (58) 133 (1,288)
--------- --------- --------- --------- ---------
LOSS BEFORE INCOME TAXES.. (328) (2,162) (6,860) (2,884) (4,500)
Income tax provision.... -- -- -- -- --
--------- --------- --------- --------- ---------
LOSS BEFORE CUMULATIVE
EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE..... (328) (2,162) (6,860) (2,884) (4,500)
Cumulative effect of
change in accounting
principle (Note 2)....... -- -- -- -- (395)
--------- --------- --------- --------- ---------
NET LOSS.................. (328) (2,162) (6,860) (2,884) (4,895)
ACCRUAL OF DIVIDENDS ON
PREFERRED UNITS/STOCK.... (16) (1,326) (7,094) (2,498) (5,088)
--------- --------- --------- --------- ---------
NET LOSS AVAILABLE TO
COMMON
UNITHOLDERS/STOCKHOLDERS.. $ (344) $ (3,488) $ (13,954) $ (5,382) $ (9,983)
========= ========= ========= ========= =========
BASIC LOSS PER COMMON
UNIT/SHARE:
Loss before cumulative
effect of change in
accounting principle... $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.33)
Cumulative effect of
change in accounting
principle.............. -- -- -- -- (0.10)
--------- --------- --------- --------- ---------
NET LOSS PER COMMON
UNIT/SHARE............... $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.43)
========= ========= ========= ========= =========
DILUTED LOSS PER COMMON
UNIT/SHARE
Loss before cumulative
effect of change in
accounting principle... $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.33)
Cumulative effect of
change in accounting
principle.............. -- -- -- -- (0.10)
--------- --------- --------- --------- ---------
NET LOSS PER COMMON
UNIT/SHARE............... $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.43)
========= ========= ========= ========= =========
WEIGHTED AVERAGE NUMBER OF
COMMON UNITS/SHARES
OUTSTANDING:
Basic................... 3,960,000 3,960,000 4,059,020 4,054,514 4,112,795
========= ========= ========= ========= =========
Diluted................. 3,960,000 3,960,000 4,059,020 4,054,514 4,112,795
========= ========= ========= ========= =========
</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
Preferred Common Preferred Common Subscriptions Capital Receivables Deficit Total
--------- --------- --------- ------ ------------- ---------- ----------- ----------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Issuance of preferred
and common units....... 198,921 3,960,000 $-- $-- $54,480 $ 29 $(50,798) $ -- $ 3,711
Net loss.............. -- -- -- -- -- -- -- (328) (328)
Preferred unit
dividends ($3 per
preferred unit)...... -- -- -- -- -- -- -- (16) (16)
--------- --------- --- --- ------- ------- -------- -------- -------
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 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 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 (unaudited).. -- -- -- -- -- -- (4,895) (4,895)
Common Stock issuance
(unaudited).......... -- 1,050,000 -- 6 -- 3,394 -- -- 3,400
Stock appreciation
rights expense
(unaudited).......... -- -- -- -- -- 1,651 -- -- 1,651
Preferred stock
dividends ($3 per
share) (unaudited)... -- -- -- -- -- -- -- (5,088) (5,088)
--------- --------- --- --- ------- ------- -------- -------- -------
Balance, June 30, 1999
(unaudited)............ 3,030,920 5,132,200 $30 $26 $ -- $79,694 $ -- $(27,769) $51,981
========= ========= === === ======= ======= ======== ======== =======
</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
Period from
Inception
(December 20, Year Ended Six Months Ended
1996) through December 31, June 30,
December 31, ------------------ ------------------
1996 1997 1998 1998 1999
------------- -------- -------- -------- --------
(Unaudited)
<S> <C> <C> <C> <C> <C>
CASH FLOWS FROM
OPERATING ACTIVITIES:
Net loss............... $ (328) $ (2,162) $ (6,860) $ (2,884) $ (4,895)
Adjustments to
reconcile net loss to
net cash provided by
(used in) operating
activities--
Depletion,
depreciation and
amortization......... 277 417 3,175 784 7,717
Impairment of oil and
gas properties....... -- -- 2,642 -- --
Stock appreciation
rights expense....... -- -- -- 904 1,651
Cumulative effect of
change in accounting
principle............ -- -- -- -- 395
Change in components
of working capital--
(Increase)/decrease
in accounts
receivable.......... (10) (3,593) (218) 1,970 (6,870)
Increase/(decrease)
in accounts payable
and accrued
liabilities......... 566 (63) (896) 1,028 5,725
Change in other
current assets and
other............... (517) (122) (619) (1,561) 785
------ -------- -------- -------- --------
Net cash provided by
(used in) operating
activities......... (12) (5,523) (2,776) 241 4,508
------ -------- -------- -------- --------
CASH FLOWS FROM
INVESTING ACTIVITIES:
Oil and gas
properties............ -- (13,638) (84,823) (38,067) (33,265)
Change in property
related payables...... -- 342 17,178 3,176 (14,098)
Purchase of furniture
and fixtures.......... -- (1,940) (858) (624) (310)
------ -------- -------- -------- --------
Net cash used in
investing
activities......... -- (15,236) (68,503) (35,515) (47,673)
------ -------- -------- -------- --------
CASH FLOWS FROM
FINANCING ACTIVITIES:
Proceeds from
borrowings............ -- -- 19,000 -- 45,000
Proceeds from issuance
of preferred stock,
net................... -- -- 51,738 34,000 --
Preferred unit
subscription payments,
net................... 4,590 18,863 -- -- --
------ -------- -------- -------- --------
Net cash provided by
financing
activities......... 4,590 18,863 70,738 34,000 45,000
------ -------- -------- -------- --------
NET INCREASE (DECREASE)
IN CASH AND CASH
EQUIVALENTS............ 4,578 (1,896) (541) (1,274) 1,835
CASH AND CASH
EQUIVALENTS, beginning
of period.............. -- 4,578 2,682 2,682 2,141
------ -------- -------- -------- --------
CASH AND CASH
EQUIVALENTS, end of
period................. $4,578 $ 2,682 $ 2,141 $ 1,408 $ 3,976
====== ======== ======== ======== ========
SUPPLEMENTAL CASH FLOW
DISCLOSURES:
Cash paid for interest,
net of amounts
capitalized........... $ -- $ -- $ 84 $ -- $ 1,196
Cash paid for income
taxes................. -- -- -- -- --
</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, Formation and Nature of Operations:
Organization and Nature of Operations
Spinnaker Exploration Company, L.L.C. (Spinnaker), a Delaware limited
liability company, was formed on December 20, 1996, and has been 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 million at a price of $25 per
unit, of which 151,476 Preferred Units were purchased at formation. PGS
purchased 1,000,000 Common Units at $0.0125 per Common Unit and subscribed for
up to $15 million of Preferred Units also at a price of $25 per unit, of which
45,093 Preferred Units were purchased at formation. PGS was only obligated to
purchase an aggregate of $5 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 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 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 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 percent, 25 percent and 4
percent for PGS, Warburg, and management, respectively. Spinnaker accounted for
the contribution of the seismic 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, LLC, 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.
F-7
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
2. Summary of Significant Accounting Policies:
General
The accompanying consolidated financial statements of Spinnaker Exploration
Company have been prepared in accordance with generally accepted accounting
principles 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, 1999, and for
the six-month periods ended June 30, 1998 and 1999, 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 generally accepted accounting principles.
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
As of December 31, 1998, other current assets includes debt financing costs
of $465,000 incurred by the Company related to the $85 million credit agreement
(see Note 3), which are being amortized to interest expense over the term of
the related debt. Amortization included in interest expense for the year ended
December 31, 1998 was $116,000.
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 oil and gas 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.
Employee costs associated with production operations and general corporate
activities are expensed in the period incurred. Exclusive of field-level costs,
Spinnaker capitalized $2.5 million and $1.3 million of internal costs in 1998
and 1997, 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.
Spinnaker 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
F-8
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
discounted at ten percent, plus the lower of cost or fair value of unproved
properties, as adjusted for related income tax effects (the full cost ceiling).
If capitalized costs exceed this limit, the excess is charged to DD&A in the
quarter in which the excess occurs. At December 31, 1998, the Company
recognized a non-cash impairment of natural gas and oil properties in the
amount of $2,642,000 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 is 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 impairment of natural gas
and oil properties in the amount of $12,951,000. The write-down was reduced due
to the increase in natural gas and oil prices from December 31, 1998 through
April 9, 1999. At June 30, 1999, the Company recognized no impairment of
natural gas and oil properties using prices as of August 23, 1999. Using June
30, 1999 prices, the Company would have recognized a non-cash impairment of
natural gas and oil properties in the amount of $1,518,000. The write-down was
unnecessary due to the increase in natural gas and oil prices from June 30,
1999 to August 23, 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 $28,383,000 of net unproved property costs at December 31, 1998
excluded from the amortizable base, $22,670,000 was incurred in 1998 and
$5,713,000 was incurred in 1997. The majority of the costs will be evaluated
over the next two 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.
Furniture and Fixtures
Furniture and fixtures consists of office furniture, computer hardware and
software 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.
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 taxpaying 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 and 1996 financial statements.
Effective January 6, 1998, with the formation of Spinco (see Note 1), the
Company became subject to federal income taxes and began to apply the
provisions of Statement of Financial Accounting Standards (SFAS) No. 109,
"Accounting for Income Taxes" (see Note 10). Under SFAS No. 109, deferred
income taxes are recognized at each year-end for the future tax consequences of
differences between the tax bases of assets and
F-9
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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
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.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles 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.
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 the
F-10
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Company's 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, the
ability to finance growth, and the ability to replace reserves. Spinnaker is
also dependent upon the continued success of an exploratory drilling program
and its ability to realize value from its seismic data agreement with SEHI (see
Note 4).
The Company had working capital deficits at both December 31, 1998 and June
30, 1999, totaling $30.6 million and $58.8 million, respectively. Short-term
borrowings under the Credit Agreement of $19 million and $64 million at
December 31, 1998 and June 30, 1999, respectively, contributed to the deficits.
The Company has historically had significant amounts of net cash used in
operating and investing activities funded through short-term borrowings from
financial institutions and the issuance of Preferred Stock. Management believes
its access to cash through additional borrowings under its Credit Agreement and
operations are sufficient to satisfy the current cash requirements. PGS and
Warburg have guaranteed repayment of the Company's existing bank debt if the
Company's funds are not sufficient for repayment. Any payments under the
guarantees immediately and automatically convert into equity of the Company
(see Note 3).
Organization Costs
As of December 31, 1998 and 1997, other assets include 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, 1998 and 1997,
was $132,000 and $126,000, respectively, and for the period from inception
(December 20, 1996) through December 31, 1996, was $10,000.
On April 3, 1998, the AICPA 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 first quarter 1999 and recorded a charge related to this accounting
change of $395,000 in conjunction with the write-off of previously capitalized
organization costs.
New Accounting Policies
In June 1997, the FASB issued SFAS No.131, "Disclosures about Segment of an
Enterprise and Related Information." This statement requires the reporting of
expanded information of a company's operating segments and expands the
definition of what constitutes an entity's operating segments. This statement
is effective for the year ended December 31, 1998. This statement did not have
an impact on the Company's disclosure as the Company has only one reportable
operating segment as defined by SFAS No. 131.
In June 1997, the FASB issued SFAS No. 130, "Reporting Comprehensive
Income." This statement requires the reporting of comprehensive income which
includes net income plus all other changes in equity during the period not
reflected in net income. This statement is effective for the fiscal year ended
December 31, 1998. The Company had no items of other comprehensive income for
any of the periods presented herein.
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
F-11
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Derivative Instruments and Hedging Activities--Deferral of the Effective Date
of FASB Statement No. 133--An Amendment of FASB Statement No. 133" extended
implementation to fiscal years beginning after June 15, 2000. Early adoption is
permitted. Currently, the Company has not entered into any hedging activities
that would require adoption of SFAS No. 133.
3. Debt:
In September 1998, the Company entered into a $85 million credit agreement
(Credit Agreement) with certain financial institutions. Proceeds from
borrowings under the Credit Agreement are used to fund exploration and
development activities. The Credit Agreement is 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 are $75
million, split evenly between PGS and Warburg. On a semi-annual basis, the
Company's proved reserves are required to be evaluated to redetermine the
borrowing base. If the borrowing base increases, the guarantees are permanently
decreased dollar for dollar. No borrowing base increases have been made to date
by the financial institutions. If payments are made under a guarantee, the
balance due to the guarantor is immediately and automatically converted into
equity of the Company at a rate of $30 per share.
The Credit Agreement is comprised of three tranches, each with a specified
interest rate. The weighted average interest rate for each of the PGS and the
Warburg tranches for December 31, 1998 was 5.67 percent. The weighted average
interest rate for the borrowing base tranche for December 31, 1998 was 8.23
percent. The overall weighted average interest rate for borrowings outstanding
under the Credit Agreement for the year ended December 31, 1998 was 6.54
percent. Borrowings outstanding under the Credit Agreement at December 31, 1998
were $19 million, of which $14 million was guaranteed by PGS and Warburg.
Interest expense for the year ended December 31, 1998, excluding amounts
related to the stock issuances for guarantees, as described below, was
$212,000. The Credit Agreement matures on December 31, 1999.
In consideration for providing guarantees under the Credit Agreement, PGS
and Warburg are entitled to receive, from time to time, Common Stock. Any
related stock issuances are accounted for at the fair value of the guarantees
provided. Such amounts were $187,500 for 1998 and $500,000 for the first six
months of 1999, and have been included in interest expense in the accompanying
statements of operations.
The Credit Agreement contains 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 including the maintenance of certain financial
ratios.
Through June 30, 1999, borrowings outstanding increased to $64 million
primarily to finance exploration and development activities.
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 a seismic data agreement dated December 20, 1996 (see
Notes 1 and 5). The Company also had the ability under this seismic 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 seismic data agreement is guaranteed by its parent,
Petroleum Geo-Services ASA. In addition, we have agreed to purchase $2,000,000
of seismic related services from PGS prior to December 31, 2002. Spinnaker paid
to PGS $45,500 and $78,000 in 1997 and 1998, respectively, and $39,000 in each
of the six-month periods ended June 30, 1998 and 1999, for seismic services
under this agreement.
F-12
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The seismic data agreement was amended effective June 30, 1999. The amended
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 this seismic 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:
Redeemable 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 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
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 million to SEHI, $60 million to Holdings and
$0.8 million to management.
On January 6, 1998, concurrent with the formation of Spinco, Spinco
authorized 3,030,920 shares of Preferred Stock with a par value of $.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 has a liquidation preference of $25 per share plus accrued
dividends. Each share of Preferred Stock is convertible into two shares of
Common Stock subject to certain antidilution 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, can
automatically convert the Preferred Stock into Common Stock if the Common Stock
is sold for not less than 150 percent of the conversion price of $12.50,
subject to adjustments in the event of stock dividends, stock splits, and
issuance of shares below the $12.50 conversion price, etc.
Dividends accrue at the rate of $3 per share (and unpaid dividends compound
quarterly at a rate of 12% per annum) until December 31, 2006, at which time,
the rate decreases to $2 per share per annum thereafter if all dividends for
the then prior periods have been declared and paid in full. Otherwise, the
dividend rate increases to $5 per share per annum and the rate at which the
dividends compound quarterly increases to an annual rate of 20 percent after
December 31, 2006. At December 31, 1998 and 1997, accrued dividends on the
Preferred Stock were $8.5 million and $1.4 million, respectively. Dividends are
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 is currently entitled to one vote per share and is
entitled to vote together with the Common Stock on an as converted basis. The
Preferred Stock may be redeemed by the Company on or after January 21, 2018 at
a redemption price of $25 per share plus any accrued and unpaid dividends
through the redemption date.
The Preferred Stock has 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 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
million as a result of Warburg increasing its Preferred Unit subscriptions by
$10 million and PGS agreeing that it would be obligated to purchase an
aggregate of $15 million of Preferred Stock rather than $5 million.
F-13
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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
million was sold during the first quarter. At December 31, 1997 and 1996,
receivables on the conditional commitments for the sale of Preferred
Units/Stock to the Investors were approximately $31.8 million and $50.8
million, respectively, and are presented as a reduction in equity. At December
31, 1998, all commitments from Investors for Preferred Stock had been
fulfilled.
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.
During 1998, an additional 25,000 shares of Spinnaker common stock were
issued to PGS and Warburg under terms of the Credit Agreement related to the
Guarantor commitments of both parties.
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. 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.
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 will be issued
for each share of Common Stock. Par value will remain unchanged at $0.01 per
share. The number of shares outstanding at June 30, 1999, after giving effect
to the Stock Split, was 5,132,200 (2,566,100 shares outstanding before the
Stock Split). In connection with the Stock Split, the Company amended its
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, no compensation expense was charged
F-14
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
against income for the stock plan for 1998 or 1997. 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 $(14,172,000) and $(3,517,000) and $(3.49) and
$(0.89) in 1998 and 1997, respectively. In 1996, the impact on the net loss was
not material and, therefore, no pro forma disclosure is provided.
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 1998 and 1997 which,
among others, include the following: (a) no dividend yield, (b) risk-free
interest rate ranging from 4.96 to 5.96 percent in 1998 and 6.89 percent in
1997, and (c) expected lives of 10 years.
Presented below is a summary of stock option activity.
<TABLE>
<CAPTION>
1996 1997 1998
------------------ ------------------ ------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Shares/ Exercise
Units Price Units Price Units Price
--------- -------- --------- -------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at the
beginning of period.... -- $ -- 1,388,800 $9.12 2,194,800 $9.12
Granted............... 851,200 5.00 494,000 5.00 177,840 5.00
Granted............... 537,600 15.63 312,000 15.63 132,320 15.63
--------- --------- ---------
Outstanding at end of
period................. 1,388,800 9.12 2,194,800 9.12 2,504,960 9.17
========= ===== ========= ===== ========= =====
Exercisable at end of
period................. 277,760 9.12 716,720 9.12 1,217,712 9.14
========= ===== ========= ===== ========= =====
Available for grant..... 1,091,200 285,200 335,000
========= ========= =========
</TABLE>
The 2,504,960 options outstanding at December 31, 1998, have a weighted
average remaining contractual life of eight years. Of these options as of
December 31, 1998, 1,388,800 are 60 percent exercisable, 806,000 are 40 percent
exercisable and 310,160 are 20 percent exercisable. Stock option grants
generally vest ratably over five years and vest fully in the event of a change
in control of the Company.
Additionally, these options provide that two of the Company's officers may
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/unit value of the
Company, compensation expense of $0, $0, $904,000 and $1,651,000 in 1997, 1998,
and the six months ended June 30, 1998 and 1999, respectively, has been
recorded 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 the two stock option agreements.
F-15
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
7. Earnings Per Share:
Basic and diluted net income (loss) per share is computed based on the
following information (in thousands, except unit, share and per unit/share
amounts):
<TABLE>
<CAPTION>
For the
period from
Inception
(December 20, For the year ended For the Six Months
1996) through December 31, Ended June 30,
December 31, -------------------- --------------------
1996 1997 1998 1998 1999
------------- --------- --------- --------- ---------
(unaudited)
<S> <C> <C> <C> <C> <C>
Net loss available to
common
unitholders/stockholders.. $ (344) $ (3,488) $ (13,954) $ (5,382) $ (9,983)
========= ========= ========= ========= =========
BASIC:
Basic weighted average
units/shares........... 3,960,000 3,960,000 4,059,020 4,054,514 4,112,795
========= ========= ========= ========= =========
DILUTED:
Basic weighted average
units/shares........... 3,960,000 3,960,000 4,059,020 4,054,514 4,112,795
Dilutive securities:
Preferred Units/Stock.. -- -- -- -- --
--------- --------- --------- --------- ---------
Diluted weighted average
units/shares........... 3,960,000 3,960,000 4,059,020 4,054,514 4,112,795
========= ========= ========= ========= =========
NET LOSS PER UNIT/SHARE:
BASIC:
Loss before cumulative
effect of change in
accounting principle... $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.33)
Cumulative effect of
change in accounting
principle.............. -- -- -- -- (0.10)
--------- --------- --------- --------- ---------
Net loss per common
unit/share............... $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.43)
========= ========= ========= ========= =========
DILUTED:
Loss before cumulative
effect of change in
accounting principle... $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.33)
Cumulative effect of
change in accounting
principle.............. -- -- -- -- (0.10)
--------- --------- --------- --------- ---------
Net loss per common
unit/share............... $ (0.09) $ (0.88) $ (3.44) $ (1.33) $ (2.43)
========= ========= ========= ========= =========
</TABLE>
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 above calculation.
8. Major Customers:
The Company had natural gas and oil sales of $3,298,232 (100 percent) and
$201,000 (100 percent) to one customer for the years ended December 31, 1998
and 1997, respectively.
F-16
<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.
The Common Units were exchanged for shares of Common Stock upon the formation
of Spinco. Additionally, Spinnaker paid to PGS $45,500 and $78,000 in 1997 and
1998, respectively, and $39,000 in each of the six-month periods ended June 30,
1998 and 1999 for seismic related services. See also Note 4 concerning the
amendment of the data agreement.
PGS and Warburg, stockholders of the Company, have provided certain
guarantees for the Credit Agreement in an initial amount totaling $75 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 noncash charge to income
of $1,668,000. During 1998, the Company generated additional operating losses
and the related tax benefits offset this amount. No net income tax benefit was
recognized due to the uncertainty of future operating income as the Company has
not established a history of net operating income.
The significant items giving rise to the deferred income tax assets and
liabilities at December 31, 1998, are as follows (in thousands):
<TABLE>
<S> <C>
Deferred income tax assets:
Net operating losses........................................... $20,789
Other.......................................................... 274
-------
Total deferred income tax assets............................. 21,063
Deferred income tax liabilities:
Basis differences in natural gas and oil properties............ (20,193)
Other.......................................................... (138)
-------
Total deferred income tax liabilities........................ (20,331)
-------
Valuation allowance.............................................. (732)
-------
Net deferred tax liabilities..................................... $ --
=======
</TABLE>
The difference between the provision for income taxes and the amount that
would be determined by applying the statutory federal income tax rate to the
loss before income taxes for the year ended December 31, 1998, is analyzed as
below (in thousands):
<TABLE>
<S> <C>
Federal income tax benefit at statutory rates................... $(2,400)
Increase resulting from change in tax status.................... 1,668
Valuation allowance............................................. 732
-------
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.
F-17
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Employment Contracts
As of December 31, 1998 and 1997, 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 respective terms of
the agreements in the event of termination of employment for various reasons,
and whether by the Company or the employee. These agreements 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 against operating income.
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 for fiscal 1998.
Leases
The Company leases administrative offices under noncancellable operating
leases expiring 2002. Certain of the lease agreements require that the Company
pay for utilities, maintenance and other operational expenses of the building.
Additionally, the leases contain escalation clauses. The Company is liable
under noncancellable leases for future minimum lease commitments as follows (in
thousands):
<TABLE>
<S> <C>
1999............................................................... $ 331
2000............................................................... 330
2001............................................................... 326
2002............................................................... 134
------
$1,121
======
</TABLE>
12. Noncash Investing and Financing Activities:
In 1996, SEHI's capital account was credited for approximately $361,000 of
consideration for prior unreimbursed expenditures incurred in the formation of
the Company, of which $216,000 was expensed during 1996 with the remainder to
be amortized over a period of five years. In 1998, in conjunction with the
formation of Spinco, the remaining amount of the unreimbursed expenditures was
expensed. Additionally, in 1996, management was granted an allowance of
$250,000 to be credited to its capital account for prior unreimbursed out-of-
pocket expenses and uncompensated time spent for the benefit of the Company.
Through 1998, the entire amount of the allowance has been credited to
management's capital account as additional capital contributions were
requested. At December 31, 1998, 1997 and 1996, approximately $62,000, $137,000
and $51,000, respectively, in noncash contributions were expensed.
In connection with the amendment of the seismic data agreement on June 30,
1999, Spinnaker issued to PGS 1,000,000 shares of Common Stock. This
transaction has been accounted for at PGS' cost of $2.9 million.
F-18
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
13. 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.
As of and for the period from inception (December 20, 1996) through December
31, 1996, the Company had no natural gas and oil reserves.
Costs Incurred
Costs incurred in natural gas and oil property acquisition, exploration and
development activities are summarized below (in thousands):
<TABLE>
<CAPTION>
For the year
ended
December 31,
---------------
1997 1998
------- -------
<S> <C> <C>
Property acquisition costs --
Unproved............................................... $ 4,458 $15,791
Proved................................................. -- --
Exploration costs........................................ 7,116 46,620
Development costs........................................ 2,422 23,067
------- -------
Total costs incurred................................. $13,996 $85,478
======= =======
</TABLE>
Natural Gas and Oil Reserves
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.
Proved natural gas and oil reserve quantities at December 31, 1997 and 1998,
and the related discounted future net cash flows before income taxes are based
on estimates prepared by Ryder Scott Company, independent petroleum engineers.
Such estimates have been prepared in accordance with guidelines established by
the Commission.
F-19
<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
------- -------
<S> <C> <C>
Proved developed and undeveloped reserves--
Beginning of year....................................... -- 12,607
Extensions and discoveries.............................. 12,677 40,014
Production.............................................. (70) (1,675)
------- -------
End of year............................................. 12,607 50,946
======= =======
Proved developed reserves at the end of year............ 5,615 30,806
======= =======
<CAPTION>
Barrels of Oil,
Condensate, and
Natural Gas
Liquids at
December 31,
----------------
1997 1998
------- -------
<S> <C> <C>
Proved developed and undeveloped reserves--
Beginning of year....................................... -- 125,128
Extensions and discoveries.............................. 125,230 356,982
Production.............................................. (102) (12,087)
------- -------
End of year............................................. 125,128 470,023
======= =======
Proved developed reserves at the end of year............ 46,122 318,087
======= =======
</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
------- -------
<S> <C> <C>
Future cash inflows............................. $31,086 $99,436
Future operating expenses....................... (1,460) (16,562)
Future development costs........................ (6,424) (18,059)
------- -------
Future net cash flows........................... 23,202 64,815
10% annual discount per annum................... (4,221) (12,706)
------- -------
Standardized measure of discounted future net
cash flows..................................... $18,981 (1) $52,109 (1)
======= =======
</TABLE>
- --------
(1) 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 Company's proved natural gas and oil reserves at
the end of the year, based on the year-end
F-20
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
costs and 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 percent 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.
Change 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
------- -------
<S> <C> <C>
Standardized measure, beginning of year..................... $ -- $18,981
Extensions and discoveries, net of related costs............ 19,110 35,952
Sales of natural gas and oil produced, net of production
costs...................................................... (129) (2,824)
Net changes in prices and production costs.................. -- (4,329)
Change in future development costs.......................... -- 2,713
Development costs incurred during the period that reduced
future development costs................................... -- 2,246
Accretion of discount....................................... -- 1,898
Change in production rates and other........................ -- (2,528)
------- -------
Standardized measure, end of year........................... $18,981 $52,109
======= =======
</TABLE>
Sales of natural gas and oil, net of natural gas and oil operating expenses,
are based on historical pretax 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.
F-21
<PAGE>
[RYDER SCOTT COMPANY LETTERHEAD APPEARS HERE]
September 10, 1999
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 interests of Spinnaker
Exploration Company (Spinnaker) as of August 31, 1999. 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. August 1999 hydrocarbon prices were
used in the preparation of this report as required by SEC guidelines; however,
actual future prices may vary significantly from August 1999 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 Interests of
Spinnaker Exploration Company
As of August 31, 1999
<TABLE>
<CAPTION>
Proved
---------------------------------------------------
Developed
-------------------------
Producing Non-Producing Undeveloped Total Proved
----------- ------------- ------------ ------------
<S> <C> <C> <C> <C>
Net Remaining Reserves
Oil/Condensate--Barrels... 395,967 107,440 1,803,582 2,306,989
Gas--MMCF................. 22,080 12,333 32,889 67,302
Income Data
Future Gross Revenue...... $74,212,541 $38,224,260 $132,460,361 $244,897,162
Deductions................ 10,101,713 8,059,937 38,356,087 56,517,737
----------- ----------- ------------ ------------
Future Net Income (FNI)... $64,110,828 $30,164,323 $ 94,104,274 $188,379,425
Discounted FNI @ 10%...... $57,583,316 $22,151,944 $ 72,487,620 $152,222,880
</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.
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
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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 80 percent and liquid hydrocarbon reserves
account for the remaining 20 percent of total future gross revenue from proved
reserves.
The discounted future net income shown above 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 definition
of proved reserves is included in the section entitled "Definitions of
Reserves" which is attached with this report.
The proved developed non-producing reserves included herein are comprised of
the behind pipe category. 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 August 1999; 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 behind
pipe and undeveloped reserves included herein were estimated by the volumetric
method which utilized all pertinent wells and 3-D seismic data available
through August 1999.
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.
Hydrocarbon Prices
Spinnaker furnished us with prices in effect at August 31, 1999 and these
prices were held constant throughout the life of the properties. These prices
were $2.825 per MMBTU of gas at Henry Hub, Louisiana,
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and $22.11 per barrel at the Cushing NYMEX Pricing Hub based on light sweet
crude on August 31, 1999. 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 August 31, 1999 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 cost 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 August 1999.
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 increase or decrease from existing levels, such changes were
omitted from consideration in making this evaluation.
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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.
Senior Vice President
JEH/sw
Approved:
/s/ Ronald Harrell
- -------------------------------
Ronald Harrell, P.E.
President
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DEFINITIONS OF RESERVES
PROVED RESERVES (SEC DEFINITION)
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from
known reservoirs under existing 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
escalation based on future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. In certain instances,
proved reserves are assigned on the basis of a combination of core analysis and
electrical and other type logs which indicate the reservoirs are analogous to
reservoirs in the same field which are producing or have demonstrated the
ability to produce on a formation test. The area of a reservoir considered
proved includes (1) that portion delineated by drilling and defined by fluid
contacts, if any, and (2) the adjoining portions not yet drilled that can be
reasonably judged as economically productive on the basis of available
geological and engineering data. In the absence of data on fluid contacts, the
lowest known structural occurrence of hydrocarbons controls the lower proved
limit of the reservoir.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) 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, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Proved natural gas reserves are comprised of non-associated, associated and
dissolved gas. An appropriate reduction in gas reserves has been made for the
expected removal of natural gas liquids, for lease and plant fuel, and for the
exclusion of non-hydrocarbon gases if they occur in significant quantities and
are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage.
Proved reserves are estimates of hydrocarbons to be recovered from a given
date forward. They may be revised as hydrocarbons are produced and additional
data become available.
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RESERVE STATUS CATEGORIES (SEC)
Reserve status categories define the development and producing status of
wells and/or reservoirs.
Proved Developed
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.
Developed reserves may be subcategorized as producing or non-producing using
the SPE/WPC Definitions:
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.
Proved Undeveloped
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. Estimates for proved undeveloped reserves are
attributable to any acreage for which an application of fluid injection or
other improved technique is contemplated, only when such techniques have been
proved effective by actual tests in the area and in the same reservoir.
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HYDROCARBON PRICING PARAMETERS
Securities and Exchange Commission Parameters
Oil and Condensate
Spinnaker furnished us with oil and condensate prices in effect at August
31, 1999 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 August 31, 1999 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. Certain
additional oil and condensate processing and transportation fees are included
in this report as costs and are shown as "other" deductions.
Gas
Spinnaker furnished us with gas prices in effect at August 31, 1999. The
prices which were actually used for each property reflect adjustment for the
BTU content, local conditions, and/or distance from market. Certain additional
gas processing and transportation fees are included in this report as costs and
are shown as "other" deductions. 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 August 31, 1999 gas prices used
herein.
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