<PAGE> 1
As filed with the Securities and Exchange Commission on July 16, 1999
Registration No. 333-
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- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
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SPINNAKER EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
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<S> <C> <C>
DELAWARE 1311 76-0560101
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or organization) Classification Code Number) Identification No.)
</TABLE>
1200 SMITH STREET, SUITE 800
HOUSTON, TEXAS 77002
(713) 759-1770
(Address, including zip code, and telephone number,
including area code, of registrant's principal executive offices)
JAMES M. ALEXANDER
VICE PRESIDENT, CHIEF FINANCIAL OFFICER AND SECRETARY
SPINNAKER EXPLORATION COMPANY
1200 SMITH STREET, SUITE 800
HOUSTON, TEXAS 77002
(713) 759-1770
(Name, address, including zip code, and telephone number,
including area code, of agent for service)
Copies to:
<TABLE>
<S> <C>
SCOTT N. WULFE WALTER J. SMITH
VINSON & ELKINS L.L.P. BAKER & BOTTS, L.L.P.
2300 FIRST CITY TOWER 3000 ONE SHELL PLAZA
1001 FANNIN 910 LOUISIANA
HOUSTON, TEXAS 77002 HOUSTON, TEXAS 77002
(713) 758-2222 (713) 229-1234
</TABLE>
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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this registration statement becomes effective.
If any of the securities registered on this form are being offered on a
delayed or continuous basis pursuant to Rule 415 under the Securities Act, check
the following box. [ ]
If this form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, check the following box and
list the Securities Act registration statement number of the earlier effective
registration statement for the same offering. [ ]
If this form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If this form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
CALCULATION OF REGISTRATION FEE
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PROPOSED MAXIMUM
TITLE OF EACH CLASS OF AGGREGATE AMOUNT OF
SECURITIES TO BE REGISTERED OFFERING PRICE(1) REGISTRATION FEE
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<S> <C> <C>
Common Stock, par value $.01 per share.............. $125,000,000 $34,750
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(1) Estimated solely for purposes of calculating the registration fee pursuant
to Rule 457(o) under the Securities Act of 1933.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
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<PAGE> 2
The information in this prospectus is not complete and may be changed. We may
not sell these securities until the registration statement filed with the
Securities and Exchange Commission is effective. This prospectus is not an offer
to sell these securities and is not soliciting an offer to buy these securities
in any state where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED JULY 16, 1999
SHARES
[LOGO]
SPINNAKER EXPLORATION COMPANY
COMMON STOCK
---------------------
Prior to this offering, there has been no public market for our common
stock. The initial public offering price of the common stock is expected to be
between $ and $ per share. We have applied to list our common stock
on The Nasdaq Stock Market's National Market under the symbol "SPNX."
The underwriters have an option to purchase a maximum of
additional shares to cover over-allotments of shares.
INVESTING IN OUR COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE
11.
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<CAPTION>
UNDERWRITING
PRICE TO DISCOUNTS AND PROCEEDS TO
PUBLIC COMMISSIONS SPINNAKER
-------- ------------- -----------
<S> <C> <C> <C>
Per Share................................. $ $ $
Total..................................... $ $ $
</TABLE>
Delivery of the shares of common stock will be made on or about
, 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 , 1999.
<PAGE> 3
[Map of the onshore U.S. gulf coast and U.S. Gulf of Mexico showing the
location of our existing leasehold interests, our discoveries, our wells
currently drilling and the coverage area of the 3-D seismic data to which we
have licenses.]
2
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TABLE OF CONTENTS
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PAGE
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PROSPECTUS SUMMARY.................... 4
RISK FACTORS.......................... 11
CAUTIONARY STATEMENT ABOUT
FORWARD-LOOKING STATEMENTS.......... 21
USE OF PROCEEDS....................... 22
DIVIDEND POLICY....................... 22
DILUTION.............................. 23
CAPITALIZATION........................ 24
SELECTED CONSOLIDATED FINANCIAL
DATA................................ 25
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS....................... 27
BUSINESS AND PROPERTIES............... 32
MANAGEMENT............................ 49
CERTAIN TRANSACTIONS.................. 54
</TABLE>
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PAGE
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SECURITY OWNERSHIP OF MANAGEMENT AND
CERTAIN BENEFICIAL HOLDERS.......... 55
DESCRIPTION OF CAPITAL STOCK.......... 57
SHARES ELIGIBLE FOR FUTURE SALE....... 60
UNDERWRITING.......................... 61
NOTICE TO CANADIAN RESIDENTS.......... 63
LEGAL MATTERS......................... 64
EXPERTS............................... 64
WHERE YOU CAN FIND MORE INFORMATION... 64
GLOSSARY OF NATURAL GAS AND OIL
TERMS............................... 65
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS.......................... F-1
REPORT OF INDEPENDENT PETROLEUM
ENGINEERS........................... A-1
</TABLE>
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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, 1999 (25 DAYS AFTER COMMENCEMENT OF THIS OFFERING), 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
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PROSPECTUS SUMMARY
This summary highlights selected information from this prospectus, but does
not contain all information that may be important to you. This prospectus
includes specific terms of this offering, information about our business and
financial data. We encourage you to read this prospectus in its entirety before
making an investment decision. Unless otherwise indicated, this prospectus
reflects 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 65 of
this prospectus.
In this prospectus, we refer to Spinnaker Exploration Company and its
predecessor and subsidiaries as "Spinnaker," "we" or "our company." We refer to
Petroleum Geo-Services ASA and its affiliates as "PGS" and to Warburg, Pincus
Ventures, L.P. and its affiliates as "Warburg." Both of these entities are
principal stockholders of our company. References in this prospectus to the Gulf
of Mexico mean the U.S. Gulf of Mexico.
ABOUT SPINNAKER
Spinnaker is an independent energy company engaged in the exploration,
development and production of natural gas and oil in the Gulf of Mexico. We
currently have licenses to approximately 4,700 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 PGS. This database covers
an area of approximately 23 million acres, which we believe is one of the
largest recent vintage 3-D seismic databases licensed to any independent
exploration and production company in the Gulf of Mexico. 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, PGS and Warburg formed our company in December
1996. PGS, a leader in acquiring 3-D seismic data, received most of its equity
ownership in our company 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 PGS and through
acquisitions of 3-D seismic data from other seismic data vendors.
Since our inception, we have participated in drilling 24 exploratory wells
in the Gulf of Mexico, with 16 of these wells being completed as discoveries. At
December 31, 1998, our net proved reserves were estimated at approximately 53.8
Bcfe (95% of which was natural gas) representing an increase of approximately
300% over our 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 June 30, 1999. We currently have an interest in
approximately 120 lease blocks in the Gulf of Mexico, within which we have
identified approximately 49 exploratory prospects and 23 leads. We have budgeted
to drill 20 of these prospects during the remainder of 1999 and 2000. Based on
3-D seismic analysis, we also have identified over 100 additional leads on
blocks where we currently have no leasehold interest that may result in
additional prospects. Our capital expenditure budget for 1999 and 2000 includes
approximately $170 million for exploration, development and leasehold
acquisitions, of which we have spent $31.0 million through May 31, 1999.
4
<PAGE> 6
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
- 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 our licenses to 3-D seismic data from PGS 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 our company.
As our company 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.
5
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SUSTAIN A BALANCED, DIVERSIFIED EXPLORATION EFFORT. We believe that our
exploration approach results in portfolio balance and diversity among:
- shallow water (under 600 feet) and deep water prospects;
- shallow drilling depth (under 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 cost for 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 our company 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.
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
are summarized below.
GARDEN BANKS 367 (DULCIMER). Dulcimer is located approximately 128 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 January
1998 and encountered 124 net feet of pay. As of December 31, 1998, this
discovery accounted for approximately 24% of the present value of future net
cash flows from our proved reserves. Production from this discovery began in
March 1999. We believe that no other wells will need to be drilled to fully
produce the reserves. As of May 31, 1999, we had incurred capital expenditures
of $19.1 million on this discovery.
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 December 31, 1998, this discovery accounted for approximately
19% of the present value of future net cash flows from our proved reserves. We
believe that the cost to commence production, including all facilities and
completions, will be approximately $8.2 million, net to our company. We expect
production from this discovery to begin in the second half of 1999. We believe
that no other wells will need to be drilled to fully produce the reserves. As of
May 31, 1999, we had incurred capital expenditures of $4.2 million on 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 August
1997 and encountered 149 net feet of pay. As of December 31, 1998, this
discovery accounted for approximately 19% 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 reserves. As of May 31, 1999, we had incurred capital expenditures
of $4.4 million on this discovery.
MISSISSIPPI CANYON 496 (ZIA). Zia is located approximately 36 miles off the
Louisiana coast in approximately 1,700 feet of water. We participated as
non-operator with a 12 1/2% working interest in
6
<PAGE> 8
drilling this discovery. The discovery well was drilled to a total measured
depth of 21,900 feet in November 1998 and encountered 217 net feet of pay. A
second well is planned by the second quarter of 2000. We believe that the future
cost to commence production, including all facilities and completions, will be
approximately $16.6 million, net to our company. We expect production from this
discovery to begin in 2001. As of May 31, 1999, we had incurred capital
expenditures of $6.1 million on this discovery.
WEST CAMERON 39. West Cameron 39 is located approximately seven miles off
the Louisiana coast in approximately 32 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 13,700
feet in May 1999 and encountered 256 net feet of pay. The #3 well was drilled to
a total measured depth of 12,000 feet in May 1999 and encountered 48 net feet of
pay. As of December 31, 1998, the #1 well accounted for approximately 7% 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 the future cost
to commence production from the #2 and #3 wells, including all facilities and
completions, will be approximately $1.2 million, net to our company. We believe
that no other wells will need to be drilled to fully produce the reserves. As of
May 31, 1999, we had incurred capital expenditures of $5.0 million on the #1
well and $2.5 million on the #2 and #3 wells combined.
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.
THE OFFERING
Common stock offered by
Spinnaker................ shares
Common stock to be
outstanding after this
offering................. 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
- ---------------
(1) Excludes 1,312,625 shares of common stock issuable on exercise of
outstanding options at a weighted average exercise price of $18.95 per
share.
7
<PAGE> 9
SUMMARY CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA(1))
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 THREE MONTHS ENDED
1996) THROUGH DECEMBER 31, MARCH 31,
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 $ 249 $ 1,839
--------- --------- --------- --------- ---------
Operating expenses:
Lease operating expenses.............................. -- 72 474 68 240
Depreciation, depletion and amortization -- natural
gas and oil properties.............................. -- 68 2,738 104 1,617
Depreciation and amortization -- other................ 10 349 437 62 47
Impairment of natural gas and oil properties.......... -- -- 2,642 -- --
General and administrative............................ 318 1,965 3,809 1,030 1,128
--------- --------- --------- --------- ---------
Total operating expenses........................ 328 2,454 10,100 1,264 3,032
--------- --------- --------- --------- ---------
Loss from operations.................................... (328) (2,253) (6,802) (1,015) (1,193)
--------- --------- --------- --------- ---------
Other income (expense):
Interest income....................................... -- 91 221 56 46
Interest expense...................................... -- -- (516) -- (874)
Capitalized interest.................................. -- -- 237 -- 407
--------- --------- --------- --------- ---------
Loss before income taxes................................ (328) (2,162) (6,860) (959) (1,614)
Income tax provision.................................. -- -- -- -- --
--------- --------- --------- --------- ---------
Loss before cumulative effect of change in accounting
principle............................................. (328) (2,162) (6,860) (959) (1,614)
Cumulative effect of change in accounting
principle(2).......................................... -- -- -- -- (395)
--------- --------- --------- --------- ---------
Net loss................................................ $ (328) $ (2,162) $ (6,860) $ (959) $ (2,009)
========= ========= ========= ========= =========
Accrual of dividends on preferred stock................. (16) (1,326) (7,094) (895) (2,493)
--------- --------- --------- --------- ---------
Net loss available to common stockholders............... $ (344) $ (3,488) $ (13,954) $ (1,854) $ (4,502)
========= ========= ========= ========= =========
Basic and diluted loss per common share:
Loss before cumulative effect of change in accounting
principle........................................... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.01)
Cumulative effect of change in accounting
principle(2)........................................ -- -- -- -- (0.19)
--------- --------- --------- --------- ---------
Net loss per common share............................. $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.20)
========= ========= ========= ========= =========
Weighted average number of common shares outstanding --
basic and diluted..................................... 1,980,000 1,980,000 2,029,510 2,025,900 2,047,350
========= ========= ========= ========= =========
OTHER DATA:
EBITDA(3)............................................... $ (318) $ (1,836) $ (985) $ (849) $ 471
Capital expenditures.................................... $ -- $ 15,578 $ 85,681 $ 17,772 $ 16,385
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31, 1999
--------------------------- ----------------------
AS
1996 1997 1998 ACTUAL ADJUSTED(4)
------ ------- -------- -------- -----------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents................................... $4,578 $ 2,682 $ 2,141 $ 304 $
Current assets.............................................. 4,588 6,348 6,737 10,829
Total assets................................................ 5,241 22,358 102,769 121,982
Short-term debt............................................. -- -- 19,000 47,000 --
Other current liabilities................................... 1,858 2,096 18,378 10,580 10,580
Accrued preferred dividends payable......................... 16 1,383 8,478 10,971 --
Other long-term liabilities................................. -- -- -- 795 795
Total equity................................................ 3,367 18,879 56,913 52,636
</TABLE>
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(1) Our company 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.
(2) Cumulative effect of change in accounting principle represents our adoption
of Statement of Position 98-5 (Reporting on the Costs of Start-Up
Activities).
(3) EBITDA means net loss before cumulative effect of change in accounting
principle, income tax provision, capitalized interest, interest expense,
interest income, impairment of natural gas and oil properties, depreciation,
depletion and amortization -- natural gas and oil properties and
depreciation and amortization -- other. EBITDA is not a calculation based
upon generally accepted accounting principles. EBITDA should not be
considered as an alternative to net income or operating income, as an
indicator of the operating performance of Spinnaker, or as an alternative to
operating cash flows as a measure of liquidity. The EBITDA measure presented
in this prospectus may not be comparable to similarly titled measures
reported by other companies due to differences in the components of the
calculation.
(4) As adjusted to give effect to the application of the $ 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. Please read "Use of Proceeds."
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SUMMARY RESERVE INFORMATION
<TABLE>
<CAPTION>
AS OF
DECEMBER 31, 1998
-----------------
<S> <C>
Estimated proved reserves(1):
Natural gas (MMcf)........................................ 50,946
Oil and condensate (MBbls)................................ 470
Total (MMcfe)..................................... 53,766
Proved developed reserves as a percentage of proved
reserves.................................................. 61%
Present value (in thousands)(2)............................. $52,109
</TABLE>
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(1) Estimates of proved reserves are based on the December 31, 1998 reserve
report prepared by Ryder Scott Company Petroleum Engineers, 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.
(2) Represents 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
December 31, 1998, discounted at 10% per annum. The present value was
determined by using the December 31, 1998 prices of $1.835 per MMBtu of
natural gas at Henry Hub, Louisiana and $12.05 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 company's net
operating loss carryforwards. Please read note 13 of the notes to our
consolidated financial statements.
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
THREE MONTHS
YEAR ENDED ENDED
DECEMBER 31, MARCH 31,
--------------- ---------------
1997 1998 1998 1999
------ ------ ------ ------
<S> <C> <C> <C> <C>
PRODUCTION:
Natural gas (MMcf)....................................... 70 1,675 142 1,007
Oil and condensate (MBbls)............................... -- 12 -- 11
Total (MMcfe)............................................ 70 1,747 142 1,073
AVERAGE SALES PRICE PER UNIT:
Natural gas (per Mcf).................................... $ 2.87 $ 1.89 $ 1.74 $ 1.70
Oil and condensate (per Bbl)............................. 18.51 11.61 15.12 11.64
Total (per Mcfe)......................................... 2.87 1.89 1.75 1.72
EXPENSES (PER MCFE):
Lease operating expense.................................. $ 1.03 $ 0.27 $ 0.48 $ 0.22
Depreciation, depletion and amortization -- natural gas
and oil properties.................................... 0.97 1.57 0.73 1.51
</TABLE>
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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.
WE HAVE A LIMITED OPERATING HISTORY AND HAVE INCURRED LOSSES FROM OPERATIONS
SINCE OUR FORMATION.
We were formed in December 1996 and, as a result, we have a limited
operating history. 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. You also should
consider our prospects in light of the risks, expenses and difficulties
frequently encountered by other companies in early stages of development.
We incurred net losses of $328,000 in 1996, $2.2 million in 1997, $6.9
million in 1998 and $2.0 million in the first 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 be
certain 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 ARE EXPENSIVE, CANNOT ELIMINATE EXPLORATION RISK AND REQUIRE
EXPERIENCED TECHNICAL PERSONNEL.
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 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. The use of 3-D seismic
data and other technologies also requires greater pre-drilling expenditures than
traditional drilling strategies. We could incur losses as a result of these
expenditures. Poor results from our exploration activities could affect our
future results of operations and financial condition materially and adversely.
Our exploratory drilling success will depend, in part, on our ability to
attract and retain experienced explorationists and other professional personnel.
We currently employ 12 explorationists and engineers and have retained two
engineering consultants and two geophysical consultants, all of whom have Gulf
of Mexico experience. Competition for explorationists and engineers with
experience in the Gulf of Mexico is extremely intense. If we cannot retain these
personnel or attract additional experienced personnel, our ability to compete in
the Gulf of Mexico could be adversely affected.
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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 PGS.
Our success depends heavily on our access to 3-D seismic data. Our primary
source for 3-D seismic data is our data agreement with PGS. If PGS 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 us. PGS may
terminate our data agreement on several grounds, including if a PGS 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 -- PGS Data Agreement -- Termination Events."
Although we currently have licenses under our PGS data agreement to 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
PGS between now and March 31, 2002. However, there are a number of scenarios
under which we might not receive significant additional data from PGS. Our
agreement does not require PGS to acquire or process any further data. PGS 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 PGS or changes in PGS' competitive, financial
or technological status.
Alternatively, PGS 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, PGS could focus on acquiring and processing data on an
exclusive contractual basis and not for sale to multiple customers. In addition,
if PGS were to engage new marketing vendors who would not agree to the terms of
our agreement with PGS, then we would not have access to the data marketed
through those vendors. PGS 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 PGS were to elect to sell the right to enhance and market
its data without retaining a material royalty or similar interest.
Furthermore, marine seismic acquisition technology has been characterized
by rapid technological advancements in recent years and further significant
technological developments could substantially impair our seismic data's value.
NATURAL GAS AND OIL PRICES FLUCTUATE WIDELY, AND LOW PRICES COULD HAVE A
MATERIAL ADVERSE IMPACT ON OUR BUSINESS, PARTICULARLY IF WE DO NOT HEDGE OUR
PRODUCTION.
Prices for natural gas and oil fluctuate widely. For example, natural gas
and oil prices declined significantly in 1998 and, for an extended period of
time, remained substantially below prices obtained in previous years. Among the
factors that can cause this fluctuation are:
- the level of consumer product demand;
- weather conditions;
- 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.
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
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periodic re-determination based on changing expectations of future prices. Lower
prices may reduce the amount of natural gas and oil that we can economically
produce.
To date, we have not engaged in any hedging transactions to reduce the
impact of fluctuations of natural gas and oil prices on our company. 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. While we may
engage in hedging arrangements in the future, we cannot assure you that we will
enter into any hedging transactions or that hedging transactions would
adequately protect us from fluctuations in the prices of natural gas and oil.
RESERVE ESTIMATES ARE INHERENTLY UNCERTAIN, ESPECIALLY WITH RESPECT TO
PROPERTIES WITH LITTLE OR NO PRODUCTION HISTORY, AND DEPEND ON MANY ASSUMPTIONS
THAT MAY TURN OUT TO BE INACCURATE.
The process of estimating natural gas and oil reserves is complex and
inherently uncertain. 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. Natural gas and oil reserve engineering is a
subjective process of estimating accumulations of natural gas and oil that
cannot be measured in an exact manner. Our proved reserve information included
in this prospectus represents only estimates based on reports prepared by our
independent petroleum engineers. Estimates from other engineers might differ
materially from those shown in this prospectus. The accuracy of any reserve
estimate is a function of the quality and quantity of available data,
engineering and geological interpretation and judgment.
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 December 31, 1998, 86% of our
proved reserves were either proved undeveloped or proved non-producing.
Moreover, the producing wells included in our reserve report had produced only
an average of seven months as of December 31, 1998. Because most of our reserve
estimates are not based on a lengthy production history and are calculated using
volumetric analysis, these estimates are inherently less reliable than estimates
based on a lengthy production history. Therefore, we cannot be certain of the
actual volume of recoverable reserves that will be realized from those wells
because our estimates with respect to the proved reserves and level of future
production attributable to these wells are difficult to determine and are based
on limited information.
At December 31, 1998, approximately 39% 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 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.
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As of June 30, 1999, over 80% 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 December 31, 1998, our proved reserves were
located on nine properties in the Gulf of Mexico, with over 70% 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 RISKS ASSOCIATED WITH THE GULF OF MEXICO BECAUSE WE
CURRENTLY EXPLORE AND PRODUCE EXCLUSIVELY IN THAT AREA.
Our operations and financial results 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 those
relating to:
- weather;
- oil field service costs and availability; and
- environmental and other laws and regulations.
In addition, 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 OPERATIONS AND
FINANCIAL CONDITION.
Our future natural gas and oil production depends on our success in finding
or acquiring additional reserves. 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 results of
operations and financial condition will be adversely affected.
WE WROTE-DOWN THE CARRYING VALUE OF OUR PROVED PROPERTIES AS OF YEAR-END 1998 AS
A RESULT OF DECREASES IN NATURAL GAS AND OIL PRICES, AND WE COULD EXPERIENCE
WRITE-DOWNS IN THE FUTURE.
There is a risk that we will be required to write-down the carrying value
of our natural gas and oil properties when natural gas and oil prices are low.
In addition, write-downs may occur if we have:
- downward adjustments to our estimated proved reserves,
- increases in our estimates of development costs, or
- deterioration in our exploration results.
We use the full cost method of accounting to report operations for natural
gas and oil properties. We capitalize the costs to acquire, explore for and
develop natural gas and oil properties. Under full cost accounting rules, the
net capitalized costs of natural gas and oil properties may not exceed a ceiling
limit
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that is based on the present value of estimated future net cash flows from
proved reserves, using constant natural gas and oil prices and a 10% discount
factor. If net capitalized costs of natural gas and oil properties exceed the
ceiling limit, we must charge the amount of this excess to earnings in the
quarter in which the excess occurs. This is called a ceiling limitation
write-down. This charge does not affect cash flow from operating activities, but
it does reduce the book value of our stockholders' equity. We review the
carrying value of our properties quarterly, based on prices in effect as of the
end of each quarter or as of the time of reporting our results. We may not
reverse write-downs even if prices increase in subsequent periods. Primarily
because of a decline in natural gas and oil prices experienced in 1998, we
recognized a non-cash impairment of natural gas and oil properties for the year
ended December 31, 1998 in the amount of $2.6 million using prices as of April
9, 1999. Using December 31, 1998 prices, we would have recognized a non-cash
impairment of natural gas and oil properties of approximately $13.0 million.
THE NATURAL GAS AND OIL BUSINESS INVOLVES MANY OPERATING RISKS THAT CAN CAUSE
SUBSTANTIAL LOSSES. INSURANCE MAY NOT BE ADEQUATE TO PROTECT OUR COMPANY AGAINST
ALL THESE RISKS.
The natural gas and oil business involves a variety of operating risks,
including:
- fires;
- explosions;
- blow-outs and surface cratering;
- uncontrollable flows of underground natural gas, oil and formation water;
- natural disasters;
- pipe or cement failures;
- casing collapses;
- embedded 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.
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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.
EXPLORATION FOR NATURAL GAS AND OIL IN THE DEEP WATERS OF THE GULF OF MEXICO
INVOLVES GREATER RISKS THAN EXPLORATION IN SHALLOWER WATERS.
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 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.
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. 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 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.
WE CANNOT ASSURE YOU THAT WE WILL BE SUCCESSFUL IN ACHIEVING OR MANAGING OUR
GROWTH.
We recently have experienced significant growth by expanding our 3-D
seismic data acquisition and drilling program. Our growth could strain our
financial, technical, operational and administrative resources.
Our future growth will depend on a number of factors, including:
- our ability to obtain interests in new properties;
- our ability to explore and develop existing properties;
- our ability to continue to attract and retain skilled personnel;
- our ability to maintain or enter into new relationships with project
partners and independent contractors;
- our ability to continue to expand our technical, operational and
administrative resources;
- the results of our drilling program;
- commodity prices; and
- access to capital.
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In addition, we have only limited experience with operating and managing
field operations, and we cannot be certain that we will be successful in doing
so in the future. We cannot be sure that we will be successful in achieving or
managing growth or any other aspect of our business strategy.
THE LOSS OF OUR CHIEF EXECUTIVE OFFICER OR OTHER KEY PERSONNEL COULD ADVERSELY
AFFECT US.
We depend to a large extent on the efforts of our President and Chief
Executive Officer, Roger L. Jarvis, and other key personnel. The loss of the
services of Mr. Jarvis or other key personnel could adversely affect us.
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 our company has 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 OUR COMPANY IN ORDER TO COMPETE.
Our industry is subject to rapid and significant advancements in
technology, including the introduction of new products and services using new
technologies. As our competitors use or develop new technologies, we may be
placed at a competitive disadvantage, and competitive pressures may force us to
implement new technologies at a substantial cost. In addition, our competitors
may have greater financial, technical and personnel resources that allow them to
enjoy technological advantages and may in the future allow them to implement new
technologies before we can. We cannot be certain that we will be able to
implement technologies on a timely basis or at a cost that is acceptable to our
company. 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.
ONE CUSTOMER CURRENTLY PURCHASES ALL OF OUR NATURAL GAS PRODUCTION. AS A RESULT,
IF THIS CUSTOMER DEFAULTS ON ITS PAYMENT OBLIGATIONS, WE 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, we would be adversely affected.
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WE ARE SUBJECT TO COMPLEX LAWS AND REGULATIONS, INCLUDING ENVIRONMENTAL
REGULATIONS, THAT CAN 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. While we maintain insurance
coverage for our operations, 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 may in the future enter into hedging arrangements. Hedging arrangements
may 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.
PGS, WARBURG 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 OR PGS COULD DIFFER FROM THOSE OF OTHER STOCKHOLDERS.
On completion of this offering, Warburg, PGS, and our management will
beneficially own approximately % 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 PGS and Warburg
will constitute a majority of our board of directors. Their control of our
company may have the effect of delaying or preventing a change of control of our
company and may adversely affect the voting and other rights of other
stockholders.
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Conflicts of interest could arise in the future between our company, on the
one hand, and Warburg or PGS, on the other hand, concerning, among other things,
potential competitive business activities or business opportunities. Except for
the limited restrictions placed on PGS in our data agreement with PGS, neither
Warburg nor PGS are restricted from competitive natural gas and oil exploration
and production activities or investments. Warburg currently has significant
equity interests in other public and private natural gas and oil companies. The
interest of Warburg or PGS could differ from those of our other stockholders.
FUTURE SALES OF OUR COMMON STOCK MAY DEPRESS OUR STOCK PRICE.
The market price of our common stock could decline due to sales of a large
number of shares of our common stock in the market after this offering or the
perception that such sales could occur. These factors could also make it more
difficult for us to raise funds through offerings of common stock.
On completion of this offering, shares of our common stock will
be outstanding, assuming no exercise of the underwriters' over-allotment option.
Of these shares, the shares to be sold in this offering will be freely
transferable and may be sold without restriction. The remaining shares
are not freely tradeable unless subsequently sold in transactions registered
under the Securities Act or exempt from registration. Our current stockholders
collectively have rights that provide for the registration of the resale of
their shares of common stock at our expense.
We, Warburg, PGS and our officers and directors have agreed not to offer
for sale, sell or otherwise dispose of any shares of common stock or any
securities convertible into or exercisable or exchangeable for shares of common
stock for a period of 180 days after the date of this prospectus, subject to
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.
Options to purchase approximately 1,312,625 shares of common stock are
currently outstanding, and we anticipate granting additional options to purchase
up to shares of common stock to some of our directors, officers and
employees prior to or immediately after the closing 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.
WE HAVE NOT PAID DIVIDENDS AND DO NOT ANTICIPATE PAYING ANY DIVIDENDS ON OUR
COMMON STOCK IN THE FORESEEABLE FUTURE.
We currently intend to retain any earnings for the future 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 also may be restricted by any loan agreements which we may
enter into from time to time.
OUR CERTIFICATE OF INCORPORATION CONTAINS PROVISIONS THAT COULD DISCOURAGE AN
ACQUISITION OR CHANGE OF CONTROL OF OUR COMPANY.
Our certificate of incorporation authorizes our board of directors to issue
preferred stock without stockholder approval. Provisions of our certificate of
incorporation, such as the provision allowing our board of directors to issue
preferred stock with rights more favorable than our common stock, could make it
more difficult for a third party to acquire control of us, even if that change
of control might be beneficial to stockholders.
THERE HAS NEVER BEEN A PUBLIC MARKET FOR OUR COMMON STOCK, AND OUR STOCK PRICE
MAY FLUCTUATE.
Prior to this offering, there has been no public market for our common
stock. We will negotiate the initial public offering price with the
underwriters. The initial public offering price may not be indicative of
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the price at which the common stock will trade following completion of this
offering. The completion of this offering provides no assurance that an active
trading market for our common stock will develop or, if developed, that it will
be sustained. The market price of our common stock also could be subject to
significant fluctuation and may be influenced by many factors, including
variations in results of operations, fluctuations in natural gas and oil prices,
investor perceptions of us and the natural gas and oil industry and general
economic and other conditions.
INVESTORS IN THIS OFFERING WILL EXPERIENCE IMMEDIATE AND SUBSTANTIAL DILUTION.
The initial public offering price is substantially higher than the pro
forma book value per share of the common stock. Purchasers of common stock in
this offering will experience immediate and substantial dilution in the pro
forma net tangible book value of their stock of $ per share assuming an
initial offering price for our common stock of $ per share.
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. 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. While
we have reviewed publicly available information, if any, we have not further
investigated whether their systems are Year 2000 compliant. In particular, we
have not investigated how the Year 2000 issue will affect the computer systems
controlling the pipelines and distribution facilities with which we directly or
indirectly connect and the availability of 3-D seismic data. The failure of any
of these entities to become Year 2000 compliant could adversely affect us. 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.
20
<PAGE> 22
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
21
<PAGE> 23
date made. Neither we, any person acting on our behalf nor the underwriters
undertakes any obligation to update any forward-looking statements in this
prospectus.
USE OF PROCEEDS
We estimate that we will receive net proceeds of $ million, or $
million if the underwriters exercise their over-allotment option in full, from
the sale of the shares of common stock offered by this prospectus, after
deducting underwriting discounts and commissions and estimated offering
expenses. This estimate assumes a public offering price of $ per share,
which is the mid-point of the offering price range on the cover page of this
prospectus.
We intend to use the net proceeds as follows:
- approximately $ million to repay all of our outstanding debt under
our credit facility; and
- approximately $ 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.
The weighted average interest rate for outstanding borrowings under our
credit facility as of March 31, 1999 was 5.64%. 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 "Certain Transactions -- 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.
22
<PAGE> 24
DILUTION
The pro forma net tangible book value of our common stock on March 31, 1999
was approximately $ per share of common stock, assuming conversion of all
outstanding shares of our preferred stock into common stock. Pro forma net
tangible book value per share is determined by dividing our tangible net worth
(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 March 31, 1999 would have been
approximately $ per share. This represents an immediate and substantial
increase in the net tangible book value of $ per share to existing
stockholders and an immediate dilution (i.e., 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 of $ per share:
<TABLE>
<S> <C>
Assumed public offering price per share..................... $
Pro forma net tangible book value per share at March 31,
1999...................................................
Increase per share attributable to new investors..........
Pro forma net tangible book value per share after this
offering..................................................
----------
Dilution per share to new investors......................... $
==========
</TABLE>
This table excludes all shares of common stock issuable on exercise of
options that will remain outstanding on completion of this offering. Please read
notes 5 and 6 to the notes to our consolidated financial statements. The
exercise of outstanding options with an exercise price less than the offering
price would increase the dilutive effect to new investors.
The following table sets forth, at March 31, 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, but net of the underwriting discounts and
commissions, assuming an initial public offering price of $ per share:
<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONSIDERATION AVERAGE
------------------- --------------------- PRICE PER
NUMBER PERCENT AMOUNT PERCENT SHARE
--------- ------- ----------- ------- ---------
<S> <C> <C> <C> <C> <C>
Existing stockholders.................. 5,084,520 % $75,800,000 % $14.91
New investors..........................
--------- --- ----------- --- ------
Total........................ 100% $ 100%
========= === =========== === ======
</TABLE>
The above table excludes 500,000 shares of our common stock that were
issued to PGS in connection with an amendment to our data agreement with PGS in
June 1999 and 12,500 shares of common stock that, as of June 30, 1999, were
deliverable to Warburg and PGS as consideration for Warburg's and PGS' guarantee
of a portion of our obligations under our credit facility. Please read "Certain
Transactions -- Credit Agreement."
If the underwriters' over-allotment option is exercised in full, the number
of shares held by new investors will be increased to , or
approximately % of the total number of shares of our common stock outstanding
after this offering.
23
<PAGE> 25
CAPITALIZATION
The following table presents our capitalization as of March 31, 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 99.7%
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 at an assumed offering price of
$ per share.
You should read this 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>
MARCH 31, 1999
----------------------------------
PRO FORMA
AS
ACTUAL PRO FORMA ADJUSTED
-------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
Cash and cash equivalents.................................. $ 304 $ 304 $
======== ======== ========
Short-term debt............................................ $ 47,000 $ 47,000 $
Accrued preferred dividends payable........................ 10,971 --
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, 11,000,000 shares authorized;
2,053,600 shares issued and outstanding, actual;
shares issued and outstanding, pro forma;
shares issued and outstanding, pro forma as
adjusted................................................. 20
Additional paid-in capital................................. 74,874
Accumulated deficit........................................ (22,288) (22,321) (22,321)
-------- -------- --------
Total stockholders' equity....................... 52,636
-------- -------- --------
Total capitalization............................. $110,607 $ $
======== ======== ========
</TABLE>
24
<PAGE> 26
SELECTED CONSOLIDATED FINANCIAL DATA
(IN THOUSANDS, EXCEPT SHARE AND PER SHARE DATA(1))
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, THREE MONTHS ENDED
1996) THROUGH YEAR ENDED DECEMBER 31, MARCH 31,
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 $ 249 $ 1,839
--------- --------- --------- --------- ---------
Operating expenses:
Lease operating expenses.............. -- 72 474 68 240
Depreciation, depletion and
amortization -- natural gas and oil
properties......................... -- 68 2,738 104 1,617
Depreciation and
amortization -- other.............. 10 349 437 62 47
Impairment of natural gas and oil
properties......................... -- -- 2,642 -- --
General and administrative............ 318 1,965 3,809 1,030 1,128
--------- --------- --------- --------- ---------
Total operating expenses...... 328 2,454 10,100 1,264 3,032
--------- --------- --------- --------- ---------
Loss from operations.................... (328) (2,253) (6,802) (1,015) (1,193)
--------- --------- --------- --------- ---------
Other income (expense):
Interest income....................... -- 91 221 56 46
Interest expense...................... -- -- (516) -- (874)
Capitalized interest.................. -- -- 237 -- 407
--------- --------- --------- --------- ---------
Loss before income taxes................ (328) (2,162) (6,860) (959) (1,614)
Income tax provision.................. -- -- -- -- --
--------- --------- --------- --------- ---------
Loss before cumulative effect of change
in accounting principle(2)............ (328) (2,162) (6,860) (959) (1,614)
Cumulative effect of change in
accounting principle.................. -- -- -- -- (395)
--------- --------- --------- --------- ---------
Net loss................................ $ (328) $ (2,162) $ (6,860) $ (959) $ (2,009)
========= ========= ========= ========= =========
Accrual of dividends on preferred
stock................................. (16) (1,326) (7,094) (895) (2,493)
--------- --------- --------- --------- ---------
Net loss available to common
stockholders.......................... $ (344) $ (3,488) $ (13,954) $ (1,854) $ (4,502)
========= ========= ========= ========= =========
Basic and diluted loss per common share:
Loss before cumulative effect of
change in accounting principle..... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.01)
Cumulative effect of change in
accounting principle(2)............ -- -- -- -- (0.19)
--------- --------- --------- --------- ---------
Net loss per common share............. $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.20)
========= ========= ========= ========= =========
Weighted average number of common shares
outstanding -- basic and diluted...... 1,980,000 1,980,000 2,029,510 2,025,900 2,047,350
========= ========= ========= ========= =========
OTHER DATA:
EBITDA(3)............................... $ (318) $ (1,836) $ (985) $ (849) $ 471
Capital expenditures.................... $ -- $ 15,578 $ 85,681 $ 17,772 $ 16,385
</TABLE>
25
<PAGE> 27
<TABLE>
<CAPTION>
DECEMBER 31, MARCH 31,
--------------------------- ------------------
1996 1997 1998 1998 1999
------ ------- -------- ------- --------
<S> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Cash and cash equivalents................... $4,578 $ 2,682 $ 2,141 $ 7,263 $ 304
Current assets.............................. 4,588 6,348 6,737 8,928 10,829
Total assets................................ 5,241 22,358 102,769 42,545 121,982
Short-term debt............................. -- 19,000 -- 47,000
Other current liabilities................... 1,858 2,096 18,378 12,242 10,580
Accrued preferred dividends payable......... 16 1,383 8,478 2,278 10,971
Other long-term liabilities................. -- -- -- -- 795
Total equity...................... 3,367 18,879 56,913 28,025 52,636
</TABLE>
- ---------------
(1) Our company 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.
(2) Cumulative effect of change in accounting principle represents our adoption
of Statement of Position 98-5 (Reporting on the Costs of Start-Up
Activities).
(3) EBITDA means net loss before cumulative effect of change in accounting
principle, income tax provision, capitalized interest, interest expense,
interest income, impairment of natural gas and oil properties, depreciation,
depletion and amortization -- natural gas and oil properties and
depreciation, and amortization -- other. EBITDA is not a calculation based
upon generally accepted accounting principles. EBITDA should not be
considered as an alternative to net income or operating income, as an
indicator of the operating performance of Spinnaker, or as an alternative to
operating cash flows as a measure of liquidity. The EBITDA measure presented
in this prospectus may not be comparable to similarly titled measures
reported by other companies due to differences in the components of the
calculation.
26
<PAGE> 28
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
We are 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 24
exploratory wells in the Gulf of Mexico, with 16 of these wells being completed
as discoveries. At December 31, 1998, our net proved reserves were estimated at
approximately 53.8 Bcfe (95% of which was natural gas) representing an
approximately 300% increase over our net proved reserves of 13.4 Bcfe at
December 31, 1997. We currently have an interest in approximately 120 lease
blocks in the Gulf of Mexico, within which we have identified approximately 49
exploratory prospects and 23 leads. We have budgeted to drill 20 of these
prospects during the remainder of 1999 and 2000. Based on 3-D seismic analysis,
we have also identified over 100 additional leads on blocks where we currently
have no leasehold interest 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 $500,000 during the first three 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. 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 in the quarter in which the excess occurs. 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 $4.53 per Bbl of oil from December 31, 1998 to
27
<PAGE> 29
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.
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 our company 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
THREE MONTHS ENDED MARCH 31, 1999 AS COMPARED TO THE THREE MONTHS ENDED MARCH
31, 1998
We had natural gas and oil revenues of $1.8 million for the three months
ended March 31, 1999 as compared to $249,000 for the three months ended March
31, 1998. This increase in revenues was due to production from three new wells
in 1998 and one new well in the first quarter of 1999. The 1998 wells are
located at West Cameron 522, South Timbalier 220 and South Pelto 18. Production
began from the West Cameron 522 well in March 1998, from the South Timbalier 220
well in August 1998 and from the South Pelto 18 well in December 1998. The 1999
well is located at West Cameron 39. Production began from the West Cameron 39
well in January 1999. As a result, our production substantially increased from
142 MMcfe in the first quarter of 1998 to 1,073 MMcfe in the first quarter of
1999. The average price we received for our natural gas production was $1.75 per
Mcf during the three months ended March 31, 1998 as compared to $1.72 per Mcf
during the three months ended March 31, 1999.
Lease operating expenses for the three months ended March 31, 1999 were
$240,000 as compared to $68,000 for the three months ended March 31, 1998. This
increase in lease operating expenses primarily resulted from operating expenses
attributable to properties that commenced production during 1998 and the first
quarter of 1999.
General and administrative expenses for the three months ended March 31,
1999 were approximately $1.1 million as compared to $1.0 million for the three
months ended March 31, 1998. The increase in general and administrative expenses
was due primarily to an increase in personnel during the latter part of 1998 and
the beginning of 1999.
Depreciation, depletion and amortization-natural gas and oil properties for
the three months ended March 31, 1999 was approximately $1.6 million as compared
to $104,000 for the three months ended March 31, 1998. The increase was
attributable to substantial increases in both production and the unit depletion
rate during the three months ended March 31, 1999. Depreciation and
amortization-other remained relatively unchanged for the three months ended
March 31, 1999 from the three months ended March 31, 1998, decreasing from
approximately $62,000 in 1998 to $47,000 in 1999.
Net loss for the three months ended March 31, 1999 was approximately $2.0
million as compared to $959,000 for the three months ended March 31, 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
28
<PAGE> 30
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 from 70 MMcfe in 1997 to 1,747 MMcfe in 1998.
This increased production more than offset the decrease in the average price we
received for our natural gas production from $2.87 per Mcf for 1997 to $1.89 per
Mcf for 1998.
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 in personnel during the latter part of 1997 and
during 1998 and to increases in legal and accounting services related to the
conversion of our company 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. The increase was
attributable to a substantial increase in production and in the unit depletion
rate during 1998. Depreciation and amortization-other increased from $349,000 in
1997 to $437,000 in 1998. 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 March 31, 1999, we raised an aggregate of $75.8 million
from sales of our equity securities. In addition, from inception through March
31, 1999, we borrowed an aggregate of approximately $47 million.
From inception through March 31, 1999, we incurred capital expenditures
totaling approximately $115.9 million for the acquisition, exploration and
development of our natural gas and oil properties. Of these expenditures, $58.2
million were for exploration, $37.3 million were for development and $20.4
million were for leasehold acquisitions.
We have experienced and expect to continue to experience substantial
working capital requirements and at March 31, 1999 had a working capital deficit
of approximately $46.8 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 our credit 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 $170 million during 1999 and 2000
for exploration, development and leasehold acquisitions. During the first three
months of 1999, we spent $3.1 million for exploration, $11.7 million for
development and $1.6 million for leasehold acquisitions.
29
<PAGE> 31
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 principally through net proceeds from this offering, cash flows from
our operations and borrowings under a credit facility.
In September 1998, we entered into an $85.0 million credit facility with
Credit Suisse First Boston, New York Branch, Bank of Montreal and Bank of
America, N.A. (formerly NationsBank, N.A.). Simultaneously with the completion
of this offering, we will repay all outstanding borrowings under the credit
facility, which were approximately $64.0 million as of June 30, 1999. Please
read "Certain Transactions -- Credit Agreement." We intend to replace this
credit facility in connection with the completion of this offering.
We also 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 $0.5 million for the three months ended March
31, 1999, ($2.7 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 quarter of 1999 no longer used net cash but provided net cash was
generally attributable to increasing levels of production in that period. As of
June 30, 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. Although we currently do not engage in any hedging activities, we may
in the future engage in hedging activities to reduce our exposure to
fluctuations in the prices for natural gas and oil.
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.
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, and we have been informed that all
these systems are or are expected to be Year 2000 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.
However, 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. We
have reviewed publicly available information, if any, of our material customers,
suppliers, including the suppliers of our 3-D seismic data, and contractors as
to whether their systems are Year 2000 compliant. While we have reviewed
publicly available information, we have not further investigated whether their
systems are Year 2000 compliant. In particular, we have not investigated how the
Year 2000 issue will affect the computer systems controlling the pipelines and
distribution facilities with which we directly or indirectly connect and the
availability of 3-
30
<PAGE> 32
D seismic data. The failure of any of these entities to become Year 2000
compliant could adversely affect us. 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.
We plan to continue reviewing the Year 2000 issue on an on-going basis
internally and with suppliers, customers and contractors.
31
<PAGE> 33
BUSINESS AND PROPERTIES
OVERVIEW
Spinnaker is an independent energy company engaged in the exploration,
development and production of natural gas and oil in the Gulf of Mexico. We
currently have licenses to approximately 4,700 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 PGS. This database covers
an area of approximately 23 million acres, which we believe is one of the
largest recent vintage 3-D seismic databases licensed to any independent
exploration and production company in the Gulf of Mexico. 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, PGS and Warburg formed our company in December
1996. PGS, a leader in acquiring 3-D seismic data, received most of its equity
ownership in our company 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 PGS and through
acquisitions of 3-D seismic data from other seismic data vendors.
Since our inception, we have participated in drilling 24 exploratory wells
in the Gulf of Mexico, with 16 of these wells being completed as discoveries. At
December 31, 1998, our net proved reserves were estimated at approximately 53.8
Bcfe (95% of which was natural gas) representing an increase of approximately
300% over our 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 June 30, 1999. We currently have an interest in
approximately 120 lease blocks in the Gulf of Mexico, within which we have
identified approximately 49 exploratory prospects and 23 leads. We have budgeted
to drill 20 of these prospects during the remainder of 1999 and 2000. Based on
3-D seismic analysis, we also have identified over 100 additional leads on
blocks where we currently have no leasehold interest that may result in
additional prospects. Our capital expenditure budget for 1999 and 2000 includes
approximately $170 million for exploration, development and leasehold
acquisitions, of which we have spent $31.0 million through May 31, 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 our licenses to 3-D seismic data from PGS 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 our company.
As our company 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 (under 600 feet) and deep water prospects;
- shallow drilling depth (under 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 cost for 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 our company 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."
PGS DATA AGREEMENT
We originally entered into our data agreement with PGS 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 500,000 shares of common stock to PGS. 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 PGS' 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 PGS 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 PGS retains a material royalty or similar interest in that data.
As part of its business activities, PGS acquires both proprietary and
multi-client marine seismic data. When PGS acquires proprietary data, it does so
on an exclusive contractual basis for its customers. In this case, PGS simply
provides acquisition services. When PGS acquires multi-client data, however, PGS
owns the data itself and licenses the possession and use of this data to the
industry at large. We are entitled to receive only multi-client data from PGS.
Standard data is the basic 3-D, time-migrated seismic data, and dragged
array and vertical cable data as now provided as the standard product to PGS'
3-D seismic survey customers. Enhanced data is data created through additional
computer processing of PGS' standard data. Enhanced data includes processed data
referred to as pre-stack depth migrated data and pre-stack time migrated data.
As of June 30, 1999, we had received approximately 4,100 blocks of standard data
and had received no blocks of enhanced data under our PGS agreement.
PGS 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 PGS 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.
PGS 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 PGS. Material
modifications of our rights resulting from these agreements are noted below. If
PGS enters into a marketing agreement with a new party, then PGS has agreed to
use good faith efforts to obtain the consent of the new party to our rights
under our agreement with PGS. If PGS does not obtain the consent of this new
party, however, then we may not be entitled to the future data of PGS
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that is marketed by that party. A majority of the data we have received is
subject to agreements with marketing vendors.
PGS is not obligated under our agreement to acquire any further data of any
kind. However, PGS 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 not
removed from our premises and must be held in confidence by those
individuals.
Our agreement with PGS provides that our rights to use data are perpetual
subject to the termination provisions discussed below. However, most of our
related agreements with PGS' marketing vendors provide that our rights terminate
automatically after 25 years. The data we receive under the PGS agreement
remains the property of PGS 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. 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. 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 PGS or one of PGS' 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 assign our rights under our agreement with PGS, 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 PGS competitor. A PGS competitor
is a company that provides 3-D marine seismic data in the Gulf of Mexico as a
significant part of its business or an affiliate of such company. If the
successor to our business or assets is not a PGS major customer, then that
successor may in turn transfer the rights under our agreement with PGS to a
successor of all of its business or assets as long as that successor is not a
PGS competitor. A PGS major customer is a customer that has purchased from PGS
products and services at least equal to 7.5% of PGS' 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, some of our agreements with PGS' marketing vendors
provide that we may not assign our rights to PGS data marketed by that vendor
without the consent of that vendor.
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TERMINATION EVENTS
PGS 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 PGS competitor acquires control of us or our principal subsidiary;
- a PGS major customer acquires control of us or our principal subsidiary
after another PGS 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 PGS;
- we unknowingly breach one of these provisions of the agreement, the
breach results in significant damages to PGS 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
PGS 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 PGS as a single
survey in exchange for interests in any natural gas or oil property or oil and
gas company. This restriction terminates on March 31, 2002.
ADDITIONAL SERVICES
Under our data agreement with PGS, we have access to 3-D seismic data until
March 31, 2003 through the proprietary high technology data archival and
retrieval system of PGS Data Management Inc., a subsidiary of PGS.
In addition, we have agreed to purchase approximately $2,000,000 of seismic
related services from PGS prior to December 31, 2002. We paid to PGS $45,500 in
1997 and $78,000 in 1998 for seismic related services.
LIMITATION OF LIABILITY
The aggregate liability of PGS under the agreement for all claims made by
us is limited to $45,000,000. Our liability for claims made against us by PGS
under the agreement is not limited.
USE OF COMPUTER-AIDED EXPLORATION TECHNOLOGY
Computer-aided exploration is the process of using a computer workstation
and common database to accumulate and analyze seismic, production and other data
regarding a geographic area. In general, computer-aided exploration involves
accumulating various 2-D and 3-D seismic data with respect to a potential
drilling location and correlating that data with historical well control and
production data from similar properties. The available data is then analyzed
using computer software and modeling techniques to project the likely geologic
setting of a potential drilling location and potential locations of undiscovered
natural gas and oil reserves. This 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.
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We have invested extensively in the advanced computer hardware and software
necessary for 3-D seismic exploration. We currently have 11 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 PGS that allows very
rapid loading on our in-house storage. We believe that we may be one of only a
few companies of any size to have this capability in the industry. 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 PGS agreement, we have licenses 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 our company 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.
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 PGS. 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
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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
GARDEN BANKS 367 (DULCIMER). Dulcimer is located approximately 128 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 January
1998 and encountered 124 net feet of pay. As of December 31, 1998, this
discovery accounted for approximately 24% of the present value of future net
cash flows from our proved reserves. Production from this discovery began in
March 1999. We believe that no other wells will need to be drilled to fully
produce the reserves. As of May 31, 1999, we had incurred capital expenditures
of $19.1 million on this discovery.
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 December 31, 1998, this discovery accounted for approximately
19% of the present value of future net cash flows from our proved reserves. We
believe that the cost to commence production, including all facilities and
completions, will be approximately $8.2 million, net to our company. We expect
production from this discovery to begin in the second half of 1999. We believe
that no other wells will need to be drilled to fully produce the reserves. As of
May 31, 1999, we had incurred capital expenditures of $4.2 million on 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 August
1997 and encountered 149 net feet of pay. As of December 31, 1998, this
discovery accounted for approximately 19% 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 reserves. As of May 31, 1999, we had incurred capital expenditures
of $4.4 million on this discovery.
MISSISSIPPI CANYON 496 (ZIA). Zia is located approximately 36 miles off the
Louisiana coast in approximately 1,700 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 21,900 feet in November
1998 and encountered 217 net feet of pay. A second well is planned by the second
quarter of 2000. We believe that the future cost to commence production,
including all facilities and completions, will be approximately $16.6 million,
net to our company. We expect production from this discovery to begin in 2001.
As of May 31, 1999, we had incurred capital expenditures of $6.1 million on this
discovery.
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WEST CAMERON 39. West Cameron 39 is located approximately seven miles off
the Louisiana coast in approximately 32 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 13,700 feet in May 1999 and encountered 256 net feet of pay. The # 3
well was drilled to a total measured depth of 12,000 feet in May 1999 and
encountered 48 net feet of pay. As of December 31, 1998, the # 1 well accounted
for approximately 7% 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 the future cost to commence production from the # 2 and
# 3 wells, including all facilities and completions, will be approximately $1.2
million, net to our company. We believe that no other wells will need to be
drilled to fully produce the reserves. As of May 31, 1999, we had incurred
capital expenditures of $5.0 million on the # 1 well and $2.5 million on the # 2
and # 3 wells combined.
SOUTH PELTO 18. South Pelto 18 is located approximately 14 miles off the
Louisiana coast in approximately 47 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 18,100 feet in June 1998
and encountered 145 net feet of pay. As of December 31, 1998, this discovery
accounted for approximately 9% of the present value of future net cash flows
from our proved reserves. We are currently evaluating the need for a development
well for this prospect. Production from this discovery began in December 1998.
As of May 31, 1999, we had incurred capital expenditures of $2.7 million on this
discovery.
HIGH ISLAND 235. The High Island 235 # 1 well is located approximately 23
miles off the Texas coast in approximately 55 feet of water. We participated as
operator with a 50% working interest in drilling this discovery. The well was
drilled to a total measured depth of 15,400 feet in February 1999 and
encountered 118 net feet of pay. As of December 31, 1998, this discovery
accounted for approximately 9% of the present value of future net cash flows
from our proved reserves. Production from this discovery began in April 1998. We
believe that no other wells will need to be drilled to fully produce the
reserves. As of May 31, 1999, we had incurred capital expenditures of $8.0
million on this discovery.
EAST CAMERON 152. The East Cameron # 1 well is located approximately 43
miles off the Louisiana coast in approximately 70 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 7,300 feet in December
1998 and encountered 74 Net feet of pay. As of December 31, 1998, 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 June 1999. We
believe that no other wells will need to be drilled to fully produce the
reserves. As of May 31, 1999, we had incurred capital expenditures of $4.3
million on this discovery.
OTHER DISCOVERIES. In 1997, we participated in the successful drilling of
an additional three exploratory wells. As of December 31, 1998, these
discoveries accounted for approximately 7% of the present value of future net
cash flows from our proved reserves. The cost of drilling these wells, including
completion and facility costs expended through May 31, 1999, was $9.4 million,
net to our company.
In 1998, we participated in the successful drilling of an additional two
exploratory wells which had not been assigned proved reserves as of December 31,
1998. In 1999, we also participated in the successful drilling of an exploratory
well.
PLANNED EXPLORATION PROSPECTS
We have a current inventory of 20 exploration prospects for 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 six of these prospects, and we have a 36.2% average working
interest in the overall inventory. We typically have participated in prospects
with industry partners to share the up-front costs associated
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with our exploration activities, to mitigate our exploration risk and to
increase the number of prospects in which we can participate.
Although we have budgeted 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 December 31, 1998 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 owned by our company. 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.
<TABLE>
<CAPTION>
PROVED RESERVES(1)
---------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Natural gas (MMcf).......................................... 30,806 20,140 50,946
Oil and condensate (MBbls).................................. 318 152 470
Total proved reserves (MMcfe)..................... 32,714 21,052 53,766
Present value(2)............................................ $34,723 $17,386 $52,109
</TABLE>
- ---------------
(1) The reserve report prepared by Ryder Scott as of December 31, 1998 does not
include reserves for two wells completed as of December 31, 1998 and three
wells completed since December 31, 1998. Please read "-- Drilling Activity."
(2) The present value of future net cash flows before income tax as of December
31, 1998 was determined by using the December 31, 1998 prices of $1.835 per
MMBtu of natural gas at Henry Hub, Louisiana and $12.05 per Bbl of oil at
the Cushing NYMEX Pricing Hub.
The process of estimating natural gas and oil reserves is complex and
inherently uncertain. 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. Natural gas and oil reserve engineering is a
subjective process of estimating accumulations of natural gas and oil that
cannot be measured in an exact manner. Our proved reserve information included
in this prospectus represents only estimates based on reports prepared by our
independent petroleum engineers. Estimates from other engineers might differ
materially from those shown in this prospectus. The accuracy of any reserve
estimate is a function of the quality and quantity of available data,
engineering and geological interpretation and judgment.
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 December 31, 1998, 86% of our
proved reserves were either proved undeveloped or proved non-producing.
Moreover, the producing wells included in our reserve report had produced only
an average of seven months as of December 31, 1998. Because most of our reserve
estimates are not based on a lengthy production history and are calculated using
volumetric analysis, these estimates are inherently less reliable than estimates
based on a lengthy production history.
40
<PAGE> 42
Therefore, we cannot be certain of the actual volume of recoverable reserves
that will be realized from those wells because our estimates with respect to the
proved reserves and level of future production attributable to these wells are
difficult to determine and are based on limited information.
At December 31, 1998, approximately 39% 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>
THREE MONTHS
YEAR ENDED ENDED
DECEMBER 31, MARCH 31,
--------------- ---------------
1997 1998 1998 1999
------ ------ ------ ------
<S> <C> <C> <C> <C>
PRODUCTION:
Natural gas (MMcf)....................................... 70 1,675 142 1,007
Oil and condensate (MBbls)............................... -- 12 -- 11
Total (MMcfe)............................................ 70 1,747 142 1,073
AVERAGE SALES PRICE PER UNIT:
Natural gas (per Mcf).................................... $ 2.87 $ 1.89 $ 1.74 $ 1.70
Oil and condensate (per Bbl)............................. 18.51 11.61 15.12 11.64
Total (per Mcfe)......................................... 2.87 1.89 1.75 1.72
EXPENSES (PER MCFE):
Lease operating expense.................................. $ 1.03 $ 0.27 $ 0.48 $ 0.22
Depreciation, depletion and amortization -- natural gas
and oil properties.................................... 0.97 1.57 0.73 1.51
</TABLE>
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>
THREE MONTHS
YEAR ENDED ENDED
DECEMBER 31, MARCH 31,
----------------- ------------
1997 1998 1999
------- ------- ------------
(IN THOUSANDS)
<S> <C> <C> <C>
Acquisition costs:
Unproved properties....................................... $ 4,458 $15,791 $ 1,983
Proved properties......................................... -- -- --
Exploration................................................. 7,116 46,620 2,677
Development................................................. 2,422 23,067 11,777
------- ------- -------
Total costs incurred.............................. $13,996 $85,478 $16,437
======= ======= =======
</TABLE>
41
<PAGE> 43
DRILLING ACTIVITY
The following table shows our drilling activity for the years ended
December 31, 1997 and 1998 and the three months ended March 31, 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>
THREE
MONTHS
ENDED
MARCH 31,
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 1 0.6
Nonproductive........................................ -- -- 6 2.3 -- --
-- --- -- --- -- ---
Total........................................ 4 1.5 15 5.2 1 0.6
== === == === == ===
Development Wells:
Productive........................................... -- -- -- -- -- --
Nonproductive........................................ -- -- -- -- -- --
-- --- -- --- -- ---
Total........................................ -- -- -- -- -- --
== === == === == ===
== === == === == ===
</TABLE>
Since March 31, 1999, we have drilled two gross (1.3 net) productive
exploratory wells and two gross (1.0 net) nonproductive exploratory wells.
PRODUCTIVE WELLS
The following table sets forth the number of productive natural gas and oil
wells in which we owned an interest as of March 31, 1999:
<TABLE>
<CAPTION>
TOTAL
PRODUCTIVE
WELLS
-----------
GROSS NET
----- ---
<S> <C> <C>
Natural gas................................................. 13 4.9
Oil......................................................... 1 0.1
-- ---
Total............................................. 14 5.0
</TABLE>
Productive wells consist of producing wells and wells capable of
production, including natural gas wells awaiting pipeline connections to
commence deliveries and oil wells awaiting connection to production facilities.
ACREAGE DATA
The following table presents information regarding our developed and
undeveloped lease acreage as of March 31, 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.................... 28,260 6,750 221,410 88,648 249,670 95,398
Offshore Texas........................ 23,040 1,302 97,920 32,851 120,960 34,153
Texas State Waters.................... 1,200 300 27,866 12,809 29,066 13,109
------ ------ ------- ------- ------- -------
Total....................... 52,500 8,352 347,196 134,308 399,696 142,660
====== ====== ======= ======= ======= =======
</TABLE>
42
<PAGE> 44
The table does not include leases covering 18,843 gross acres (7,530 net)
acquired between March 31, 1999 and May 31, 1999. 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 the deep 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. 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, we 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.
To date, we have not engaged in any hedging transactions to reduce the
impact of fluctuations of natural gas and oil prices on our company. However, to
reduce our exposure to fluctuations in the prices for natural gas and oil, we
may in the future enter into hedging arrangements. Hedging arrangements may
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 contractual
obligations; or
- there is a change in the expected differential between the underlying
price in the hedging agreement and actual prices reserved.
In addition, these hedging arrangements may limit the benefit we would
receive from increases in the prices for natural gas and oil.
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<PAGE> 45
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 our company has and have demonstrated the ability to operate
through industry cycles.
REGULATION
FEDERAL REGULATION OF SALES AND TRANSPORTATION OF NATURAL GAS.
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of 1938,
the Natural Gas Policy Act of 1978 and the regulations promulgated thereunder by
the Federal Energy Regulatory Commission. 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 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
44
<PAGE> 46
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
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
45
<PAGE> 47
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. We do not believe that these regulations affect us any
differently than other natural gas producers, gathers 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
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.
46
<PAGE> 48
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;
- 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;
47
<PAGE> 49
- 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 March 31, 1999, we had 29 full-time employees and four consultants,
including geologists, geophysicists and engineers. We believe that our
relationships with our employees are satisfactory. None of our employees are
covered by a collective bargaining agreement. From time to time, we use the
services of independent consultants and contractors to perform various
professional services, particularly in the areas of construction, design,
well-site surveillance, permitting and environmental assessment. Independent
contractors usually perform field and on-site production operation services for
us, including pumping, maintenance, dispatching, inspection and testing.
LEGAL PROCEEDINGS
From time to time, we may be a party to various legal proceedings. We
currently are not a party to any material litigation.
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<PAGE> 50
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
Reidar Michaelsen......................... 55 Director
Bjarte Bruheim............................ 43 Director
Howard H. Newman.......................... 52 Director
Jeffrey A. Harris......................... 43 Director
</TABLE>
The following biographies describe the business experience of our executive
officers and directors.
ROGER L. JARVIS has served as President, Chief Executive Officer and
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.
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 PGS since
1993. He was President of PGS 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 PGS since
March 1993 and was President of PGS Exploration
49
<PAGE> 51
(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, 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.
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 PGS, two members designated by Warburg 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. Following this offering, we will appoint two independent directors.
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;
- 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
50
<PAGE> 52
- 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 outside director in 1998. Following this
offering, directors who are not our employees will receive directors fees to be
determined by the board of directors.
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 (the "named executive officers") for 1998:
1998 SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
ANNUAL
COMPENSATION(1)
------------------
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>
- ---------------
(1) Amounts 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.
STOCK OPTION GRANTS
Since our inception, our named executive officers were granted the
following options:
- Mr. Jarvis was granted options to purchase 304,000 shares at $10.00 per
share and 192,000 shares at $31.25 per share in December 1996;
- Mr. Alexander was granted options to purchase 121,600 shares at $10.00
per share and 76,800 shares at $31.25 per share in December 1996;
- Mr. Hubbard was granted options to purchase 76,000 shares at $10.00 per
share and 48,000 shares at $31.25 per share in April 1997; and
- Mr. Barnes was granted options to purchase 34,200 shares at $10.00 per
share and 21,600 shares at $31.25 per share in April 1997 and 15,000
shares at $31.25 per share in January 1999.
The options granted to each of our named 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. If we terminate Mr. Jarvis or
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<PAGE> 53
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 "-- 1998 Stock Option Plan."
EMPLOYMENT AGREEMENTS
Mr. Jarvis entered into an employment agreement with our company 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 our company 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, 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.
Mr. Alexander entered into an employment agreement with our company
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 our company 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 our company 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 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 1,419,980 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 761,520 shares of common stock
issuable under options authorized under the plan is $10.00 per share, and the
purchase price of an aggregate of 658,460 shares of common stock issuable under
options authorized under the plan is $31.25 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 amended his stock
appreciation rights to take effect after the earlier of a qualified public
offering or his death or permanent disability.
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<PAGE> 54
In the event of certain significant changes in our company, all options
then outstanding generally will become immediately exercisable in full.
Significant changes include:
- any merger, consolidation or other reorganization in which Spinnaker is
not the surviving entity, or which Spinnaker survives, but only as a
subsidiary of an entity;
- any sale, lease or exchange of all or substantially all our assets;
- the dissolution and liquidation of Spinnaker; or
- a change in control of Spinnaker.
This offering does not constitute a significant change in our company under
the plan.
At July 15, 1999, we had outstanding options to purchase a total of
1,312,625 shares of common stock, of which 760,000 are exercisable at $10.00 per
share and 552,625 are exercisable at $31.25 per share. All outstanding options
are currently exercisable for a term of up to 10 years from the date of each
grant.
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<PAGE> 55
CERTAIN TRANSACTIONS
Following is a discussion of certain transactions between us and our
officers, directors and stockholders owning more than 5% of the outstanding
shares of common stock.
REGISTRATION RIGHTS
We, PGS, Warburg and our other stockholders, 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."
PGS DATA AGREEMENT
On December 20, 1996, we entered into the data agreement with PGS. 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 500,000 shares of common stock to PGS. The PGS data
agreement, as amended, is described under "Business -- PGS Data Agreement." In
addition, we paid to PGS $45,500 in 1997 and $78,000 in 1998 for seismic related
services.
INVESTMENTS IN OUR COMPANY
Since our inception, our executive officers, directors and 5% stockholders
have invested cash and other property in our company 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 purchased from us by our
executive officers, directors and 5% stockholders since our inception.
<TABLE>
<CAPTION>
EXECUTIVE OFFICERS, PREFERRED COMMON
DIRECTORS AND 5% STOCKHOLDERS STOCK STOCK
- ----------------------------- --------- ---------
<S> <C> <C>
Warburg, Pincus Ventures, L.P.(1)........................... 2,399,500 500,000
Petroleum Geo-Services ASA(2)............................... 599,500 1,948,600
Roger L. Jarvis(3).......................................... 12,768 67,200
James M. Alexander(4)....................................... 5,107 12,800
William D. Hubbard(5)....................................... 3,192 8,000
Kelly M. Barnes(6).......................................... 1,436 3,600
</TABLE>
- ---------------
(1) Warburg paid us approximately $60 million for the shares listed above.
Excludes 18,750 shares of common stock that are deliverable to Warburg as
consideration for Warburg's agreement to guarantee a portion of our
obligations under our credit facility. Please read "-- Credit Agreement."
Two of our directors, Howard H. Newman and Jeffrey A. Harris, are affiliated
with Warburg. Please see "Security Ownership of Management and Certain
Beneficial Owners" for a description of Messrs. Newman's and Harris'
affiliations with Warburg.
(2) PGS received the shares listed above as consideration for the rights granted
to us under the PGS Data Agreement and for an additional $15 million. Please
read "Business -- PGS Data Agreement" for a description of the PGS Data
Agreement. Excludes 18,750 shares of common stock that are deliverable to
PGS as consideration for PGS' agreement to guarantee a portion of our
obligations under our credit facility. Please read "-- Credit Agreement."
Two of our directors, Reidar Michaelsen and Bjarte Bruheim, are affiliated
with PGS. Please read "-- Security Ownership of Management and Certain
Beneficial Owners" for a description of Messrs. Michaelsen and Bruheim's
affiliations with PGS.
(3) As consideration for the shares listed above, Mr. Jarvis paid us
approximately $70,270 in cash and contributed to our company the intangible
assets owned by him associated with his creation of our company, including
rights to our company's name and related patents, copyrights and goodwill.
Mr. Jarvis has sold 24,400 shares of common stock to employees of our
company.
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<PAGE> 56
(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 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, PGS, 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 a $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 PGS and Warburg,
our principal stockholders. The initial stockholder guarantee for the credit
agreement was $75.0 million, split evenly between PGS and Warburg. On a
semi-annual basis, our proved reserves are required to be evaluated to
redetermine the borrowing base. If the borrowing base increases, the guarantees
are decreased dollar for dollar permanently. Up to 75% of the net proceeds from
the offering must be used to prepay the loans outstanding under the credit
agreement, first to ratably prepay the loans guaranteed by PGS and Warburg until
those loans are paid in full and then to prepay any other loans outstanding
under the credit agreement. The commitments of the tranches guaranteed by PGS
and Warburg will be reduced permanently by the amount prepaid. If payments are
made under a guarantee, the balance due to the guarantor is immediately and
automatically converted to equity in our company.
The credit agreement is comprised of three tranches, each with a specified
interest rate. The weighted average interest rate for the PGS and Warburg
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 PGS and Warburg. The
credit agreement matures on December 31, 1999.
We are obligated to pay Warburg and PGS 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 the amount is outstanding or not, payable in shares of our
common stock valued at $30.00 per share. The guarantees will terminate on the
completion of this offering.
SECURITY OWNERSHIP OF MANAGEMENT
AND CERTAIN BENEFICIAL HOLDERS
The following table presents information regarding beneficial ownership of
our common stock as of June 30, 1999 and as adjusted to reflect the sale of
common stock in this offering 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.
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<PAGE> 57
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. This table excludes
those shares of common stock to be issued to holders of approximately 99.7% of
our preferred stock in lieu of payment of accrued cash dividends on completion
of this offering.
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP(2)
--------------------------------------------
PERCENT
--------------------------------
BENEFICIAL OWNER(1) SHARES BEFORE OFFERING AFTER OFFERING
- ------------------- --------- --------------- --------------
<S> <C> <C> <C>
Warburg, Pincus Ventures, L.P.(3).................... 2,918,250 52.1%
Petroleum Geo-Services ASA(4)........................ 2,566,850 45.9
Roger L. Jarvis...................................... 353,168 6.0
James M. Alexander................................... 136,947 2.4
William D. Hubbard................................... 85,592 1.5
Kelly M. Barnes...................................... 41,516 *
Reidar Michaelsen(4)................................. 2,566,850 36.9
Bjarte Bruheim(4).................................... 2,566,850 36.9
Howard H. Newman(3).................................. 2,918,250 52.1
Jeffrey A. Harris(3)................................. 2,918,250 52.1
All executive officers and directors as a group (8
persons)........................................... 6,102,323 99.6
</TABLE>
- ---------------
* Represents beneficial ownership of less than 1%.
(1) The address of Warburg and Messrs. Newman and Harris is 466 Lexington
Avenue, 10th Floor, New York, New York 10017. The address of PGS and Messrs.
Michaelsen and Bruheim is Strandvein 50E, P.O. Box 89, N-1325, Lysaker,
Norway.
(2) 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. The shares
owned by Messrs. Jarvis, Alexander, Hubbard and Barnes include 297,600,
119,040, 74,400 and 36,480 shares, respectively, that may be acquired within
60 days through the exercise of stock options.
(3) 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. Messrs. Newman and Harris disclaim
beneficial ownership of the shares owned by Warburg.
(4) The shares are owned directly by PGS or by a wholly owned subsidiary of PGS.
Mr. Michaelsen serves as Chairman of the Board and Chief Executive Officer
and Mr. Bruheim serves as President and Chief Operating Officer of PGS. 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 PGS. Messrs. Michaelsen and Bruheim disclaim beneficial ownership
of the securities owned by PGS.
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<PAGE> 58
DESCRIPTION OF CAPITAL STOCK
Our authorized capital stock consists of 11,000,000 shares of common stock,
par value $.01 per share, and 3,030,920 shares of preferred stock, par value
$.01 per share. As of June 30, 1999, we had outstanding 2,566,100 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 one share of common stock. On completion of this offering, we
will have outstanding 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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<PAGE> 59
REGISTRATION RIGHTS
We, PGS, Warburg and our other stockholders are parties to a registration
rights agreement. That agreement grants PGS and Warburg 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 PGS or Warburg 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 PGS or Warburg
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.
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 our company 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 PGS
and Warburg, 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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<PAGE> 60
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 our company 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,
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
our company for liabilities arising because such individual was an officer or
director of our company 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.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar of our common stock is .
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<PAGE> 61
SHARES ELIGIBLE FOR FUTURE SALE
On completion of this offering, we will have shares of common
stock outstanding, or 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 5,574,803 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 certain 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> 62
UNDERWRITING
Under the terms and subject to the conditions contained in an underwriting
agreement dated, 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......................
Donaldson, Lufkin & Jenrette Securities Corporation.........
Banc of America Securities LLC..............................
Prudential Securities Incorporated..........................
Nesbitt Burns Securities Inc. ..............................
------
Total.............................................
======
</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 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 $ per share. The
underwriters and selling group members may allow a discount of $ 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............................ $ $ $ $
Expenses payable by us..................... $ $ $ $
</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 certain standards.
Accordingly, Donaldson, Lufkin & Jenrette Securities Corporation is assuming 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 will be no higher than the price recommended by
Donaldson,
61
<PAGE> 63
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.
The underwriters decided to participate in the distribution of common stock
in this offering independent of their affiliates who currently are lenders to
our company 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.
We, Warburg, PGS and our officers and directors have agreed not to offer,
sell, contract to sell, announce our intention 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 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 the exercise
of employee stock options outstanding 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.
We have made application to list the shares of common stock 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 will be determined by negotiations between us
and the underwriters. The principal factors considered in determining the
initial public offering price include:
- 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.
- 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 syndicate covering transaction to cover
syndicate short positions.
62
<PAGE> 64
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 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.
63
<PAGE> 65
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.
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 is 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 Petroleum Engineers, 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.
64
<PAGE> 66
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.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mcf. One thousand cubic feet.
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.
65
<PAGE> 67
MMBls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million British Thermal Units.
MMcf. One million cubic feet.
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.
66
<PAGE> 68
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 March 31, 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, 1997 and 1998 and for the
three months ended March 31, 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
three months ended March 31, 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
three months ended March 31, 1998 (unaudited) and 1999
(unaudited)............................................... F-6
Notes to Consolidated Financial Statements.................. F-7
</TABLE>
F-1
<PAGE> 69
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
F-2
<PAGE> 70
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS EXCEPT UNIT/SHARE DATA)
ASSETS
<TABLE>
<CAPTION>
AS OF
AS OF DECEMBER 31, MARCH 31,
------------------ -----------
1997 1998 1999
------- -------- -----------
(UNAUDITED)
<S> <C> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 2,682 $ 2,141 $ 304
Accounts receivable....................................... 3,603 3,821 8,135
Other..................................................... 63 775 2,390
------- -------- --------
Total current assets............................... 6,348 6,737 10,829
------- -------- --------
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting --
Proved properties....................................... 6,452 71,091 85,711
Unproved properties and properties under development,
not being amortized.................................. 7,544 28,383 30,200
Furniture and fixtures.................................... 1,940 2,798 2,921
------- -------- --------
15,936 102,272 118,832
Less -- Accumulated depreciation, depletion and
amortization............................................ (484) (6,665) (8,504)
------- -------- --------
Total property and equipment....................... 15,452 95,607 110,328
------- -------- --------
OTHER ASSETS:
Organization costs and other, net......................... 558 425 825
------- -------- --------
Total assets....................................... $22,358 $102,769 $121,982
======= ======== ========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities.................. $ 2,096 $ 18,378 $ 10,580
Short-term debt........................................... -- 19,000 47,000
------- -------- --------
Total current liabilities.......................... 2,096 37,378 57,580
------- -------- --------
ACCRUED PREFERRED DIVIDENDS PAYABLE......................... 1,383 8,478 10,971
OTHER LONG-TERM LIABILITIES................................. -- -- 795
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
March 31, 1999.......................................... -- 30 30
Common units, without par value; authorized 7,350,720
units; 1,980,000 units outstanding at December 31,
1997.................................................... -- -- --
Common stock, $.01 par value; authorized 11,000,000
shares; 2,041,100 shares and 2,053,600 shares
outstanding at December 31, 1998 and March 31, 1999,
respectively............................................ -- 20 20
Additional paid-in capital................................ 29 74,649 74,874
Accumulated deficit....................................... (3,832) (17,786) (22,288)
------- -------- --------
Total equity....................................... 18,879 56,913 52,636
------- -------- --------
Total liabilities and equity....................... $22,358 $102,769 $121,982
======= ======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE> 71
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS EXCEPT UNIT/SHARE AND PER UNIT/SHARE DATA)
<TABLE>
<CAPTION>
FOR THE PERIOD
FROM INCEPTION FOR THE YEAR ENDED FOR THE THREE MONTHS
(DECEMBER 20, 1996) DECEMBER 31, ENDED MARCH 31,
THROUGH DECEMBER 31, ----------------------- -----------------------
1996 1997 1998 1998 1999
-------------------- ---------- ---------- ---------- ----------
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
REVENUES..................................... $ -- $ 201 $ 3,298 $ 249 $ 1,839
---------- ---------- ---------- ---------- ----------
EXPENSES:
Depreciation, depletion and amortization --
natural gas & oil properties............. -- 68 2,738 104 1,617
Impairment of natural gas & oil
properties............................... -- -- 2,642 -- --
Depreciation and amortization -- other..... 10 349 437 62 47
General and administrative................. 318 1,965 3,809 1,030 1,128
Lease operating expenses................... -- 72 474 68 240
---------- ---------- ---------- ---------- ----------
Total expenses....................... 328 2,454 10,100 1,264 3,032
---------- ---------- ---------- ---------- ----------
LOSS FROM OPERATIONS......................... (328) (2,253) (6,802) (1,015) (1,193)
---------- ---------- ---------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest income............................ -- 91 221 56 46
Interest expense........................... -- -- (516) -- (874)
Capitalized interest....................... -- -- 237 -- 407
---------- ---------- ---------- ---------- ----------
Total other income (expense)......... -- 91 (58) 56 (421)
---------- ---------- ---------- ---------- ----------
LOSS BEFORE INCOME TAXES..................... (328) (2,162) (6,860) (959) (1,614)
Income tax provision....................... -- -- -- -- --
---------- ---------- ---------- ---------- ----------
LOSS BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE............... (328) (2,162) (6,860) (959) (1,614)
Cumulative effect of change in accounting
principle (Note 2)....................... -- -- -- -- (395)
---------- ---------- ---------- ---------- ----------
NET LOSS..................................... (328) (2,162) (6,860) (959) (2,009)
ACCRUAL OF DIVIDENDS ON PREFERRED
UNITS/STOCK................................ (16) (1,326) (7,094) (895) (2,493)
---------- ---------- ---------- ---------- ----------
NET LOSS AVAILABLE TO COMMON
UNITHOLDERS/STOCKHOLDERS................... $ (344) $ (3,488) $ (13,954) $ (1,854) $ (4,502)
========== ========== ========== ========== ==========
BASIC LOSS PER COMMON UNIT/SHARE:
Loss before cumulative effect of change in
accounting principle..................... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.01)
Cumulative effect of change in accounting
principle................................ -- -- -- -- (0.19)
---------- ---------- ---------- ---------- ----------
NET LOSS PER COMMON UNIT/SHARE............... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.20)
========== ========== ========== ========== ==========
DILUTED LOSS PER COMMON UNIT/SHARE:
Loss before cumulative effect of change in
accounting principle..................... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.01)
Cumulative effect of change in accounting
principle................................ -- -- -- -- (0.19)
---------- ---------- ---------- ---------- ----------
NET LOSS PER COMMON UNIT/SHARE:.............. $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.20)
========== ========== ========== ========== ==========
WEIGHTED AVERAGE NUMBER OF COMMON
UNITS/SHARES OUTSTANDING:
Basic...................................... 1,980,000 1,980,000 2,029,510 2,025,900 2,047,350
========== ========== ========== ========== ==========
Diluted.................................... 1,980,000 1,980,000 2,029,510 2,025,900 2,047,350
========== ========== ========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE> 72
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(IN THOUSANDS EXCEPT UNITS/SHARES AND UNIT/SHARE DIVIDEND DATA)
<TABLE>
<CAPTION>
UNITS/SHARES PAR VALUE ADDITIONAL UNITHOLDER/
--------------------- ------------------ PREFERRED UNIT PAID-IN STOCKHOLDER
PREFERRED COMMON PREFERRED COMMON SUBSCRIPTIONS CAPITAL RECEIVABLES
--------- --------- --------- ------ -------------- ---------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
Issuance of preferred and common
units......................... 198,921 1,980,000 $-- $-- $ 54,480 $ 29 $(50,798)
Net loss...................... -- -- -- -- -- -- --
Preferred unit dividends ($3
per preferred unit)........ -- -- -- -- -- -- --
--------- --------- --- --- -------- ------- --------
Balance, December 31, 1996...... 198,921 1,980,000 -- -- 54,480 29 (50,798)
Net loss...................... -- -- -- -- -- -- --
Preferred unit dividends ($3
per preferred unit)........ -- -- -- -- -- -- --
Preferred unit payments....... 760,000 -- -- -- -- -- 19,000
--------- --------- --- --- -------- ------- --------
Balance, December 31, 1997...... 958,921 1,980,000 -- -- 54,480 29 (31,798)
Conversion to Spinnaker
Exploration Company........ -- 48,600 10 20 (54,480) 54,450 --
--------- --------- --- --- -------- ------- --------
958,921 2,028,600 10 20 -- 54,479 (31,798)
Net loss...................... -- -- -- -- -- -- --
Common Stock issuance......... -- 12,500 -- -- 188 --
Preferred stock
subscriptions.............. -- -- -- -- -- 19,982 (19,982)
Preferred stock dividends ($3
per share)................. -- -- -- -- -- -- --
Preferred stock payments...... 2,071,999 -- 20 -- -- -- 51,780
--------- --------- --- --- -------- ------- --------
Balance, December 31, 1998...... 3,030,920 2,041,100 30 20 -- 74,649 --
Net loss (unaudited).......... -- -- -- -- -- -- --
Common Stock issuance
(unaudited)................ -- 12,500 -- -- -- 225 --
Preferred stock dividends ($3
per share) (unaudited)..... -- -- -- -- -- -- --
--------- --------- --- --- -------- ------- --------
Balance, March 31, 1999
(unaudited)................... 3,030,920 2,053,600 $30 $20 $ -- $74,874 $ --
========= ========= === === ======== ======= ========
<CAPTION>
ACCUMULATED
DEFICIT TOTAL
----------- -------
<S> <C> <C>
Issuance of preferred and common
units......................... $ -- $ 3,711
Net loss...................... (328) (328)
Preferred unit dividends ($3
per preferred unit)........ (16) (16)
-------- -------
Balance, December 31, 1996...... (344) 3,367
Net loss...................... (2,162) (2,162)
Preferred unit dividends ($3
per preferred unit)........ (1,326) (1,326)
Preferred unit payments....... -- 19,000
-------- -------
Balance, December 31, 1997...... (3,832) 18,879
Conversion to Spinnaker
Exploration Company........ -- --
-------- -------
(3,832) 18,879
Net loss...................... (6,860) (6,860)
Common Stock issuance......... -- 188
Preferred stock
subscriptions.............. -- --
Preferred stock dividends ($3
per share)................. (7,094) (7,094)
Preferred stock payments...... -- 51,800
-------- -------
Balance, December 31, 1998...... (17,786) 56,913
Net loss (unaudited).......... (2,009) (2,009)
Common Stock issuance
(unaudited)................ -- 225
Preferred stock dividends ($3
per share) (unaudited)..... (2,493) (2,493)
-------- -------
Balance, March 31, 1999
(unaudited)................... $(22,288) $52,636
======== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE> 73
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
<TABLE>
<CAPTION>
FOR THE PERIOD
FROM INCEPTION
(DECEMBER 20, YEAR ENDED THREE MONTHS
1996) THROUGH DECEMBER 31, ENDED MARCH 31,
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) $ (959) $ (2,009)
Adjustments to reconcile net loss to net cash
provided by (used in) operating
activities --
Depletion, depreciation and amortization... 277 417 3,175 166 1,664
Impairment of oil and gas properties....... -- -- 2,642 -- --
Cumulative effect of change in accounting
principle................................ -- -- -- -- 395
Change in components of working capital --
(Increase)/decrease in accounts
receivable............................... (10) (3,593) (218) 2,594 (4,314)
Increase/(decrease) in accounts payable
and accrued liabilities............... 1,858 (63) (896) (1,529) 6,202
Change in other current assets and
other................................. (1,797) (93) (524) (594) (1,390)
------- -------- -------- -------- --------
Net cash provided by (used in)
operating activities................ -- (5,494) (2,681) (322) 548
------- -------- -------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties....................... -- (13,638) (84,823) (17,175) (16,262)
Change in property related payables.......... -- 342 17,178 11,675 (14,000)
Purchase of furniture and fixtures........... -- (1,940) (858) (597) (123)
------- -------- -------- -------- --------
Net cash used in investing
activities.......................... -- (15,236) (68,503) (6,097) (30,385)
------- -------- -------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings..................... -- -- 19,000 -- 28,000
Proceeds from issuance of preferred stock,
net........................................ -- -- 51,643 11,000 --
Preferred unit subscription payments, net.... 4,578 18,834 -- -- --
------- -------- -------- -------- --------
Net cash provided by financing
activities.......................... 4,578 18,834 70,643 11,000 28,000
------- -------- -------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS.................................. 4,578 (1,896) (541) 4,581 (1,837)
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 $ 7,263 $ 304
======= ======== ======== ======== ========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts
capitalized................................ $ -- $ -- $ 84 $ -- $ 152
Cash paid for income taxes................... -- -- -- -- --
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE> 74
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 500,000 common
units (Common Units) at $0.025 per Common Unit and agreed to subscriptions on
preferred units (Preferred Units) of up to $50 million at a price of $25 per
unit. PGS purchased 1,400,000 Common Units at $0.025 per Common Unit and
subscribed for up to $15 million of Preferred Units also at a price of $25 per
unit. Additionally, PGS entered into a seismic data contribution agreement with
Spinnaker dated December 20, 1996, whereby it agreed to transfer to Spinnaker
certain rights to 3-D seismic data (see Note 4). Upon completion of the
formation, beneficial ownership of the voting Common Units was 71 percent, 25
percent and 4 percent for PGS, Warburg, and management, respectively. Spinnaker
accounted for the contribution of the data agreement at PGS' cost, which was
immaterial (see Note 4).
Change in Reporting Entity
On January 6, 1998, the Investors, other than Warburg, contributed their
respective Preferred Units and Common Units to Spinco Exploration Corp.
(Spinco), a Delaware corporation, 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 48,600 shares of Common Stock.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
General
The accompanying consolidated financial statements of Spinnaker Exploration
Company have been prepared in accordance with 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 March 31, 1999, and
for the three-month periods ended March 31, 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.
F-7
<PAGE> 75
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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, the Company capitalizes all
acquisition, exploration and development costs incurred for the purpose of
finding natural gas and oil reserves, including salaries, benefits and other
internal costs directly attributable to these activities. 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 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.
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.
F-8
<PAGE> 76
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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 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.
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
F-9
<PAGE> 77
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 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
contribution agreement with SEHI (see Note 4).
The Company had working capital deficits at both December 31, 1998 and
March 31, 1999, totaling $30.6 million and $46.8 million, respectively.
Short-term borrowings under the Credit Agreement of $19 million and $47 million
at December 31, 1998 and March 31, 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 $291,000,
and for the period from inception (December 20, 1996) through December 31, 1996,
was $277,000.
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 for the three months ended March 31, 1999 has
reflected 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
F-10
<PAGE> 78
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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
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 $225,000 for the first quarter
of 1999, and have been included in interest expense in the accompanying
statements of operations.
F-11
<PAGE> 79
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 March 31, 1999, borrowings outstanding increased to $47 million
primarily to finance exploration and development activities.
4. SEISMIC DATA:
As part of the Company's formation, SEHI agreed to transfer to Spinnaker
certain rights to 3-D seismic data in exchange for issuing Common Units to SEHI
pursuant to a seismic data contribution agreement dated December 20, 1996 (see
Notes 1 and 5). SEHI's obligation to the Company in connection with the seismic
data contribution agreement is guaranteed by its parent, Petroleum Geo-Services
ASA.
Subsequent Event (Unaudited)
The seismic data contribution agreement has been subsequently 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 agreement, Spinnaker
issued to PGS an additional 500,000 shares of Common Stock. This stock issuance
will be accounted for at PGS' cost, 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 one share 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 $25, subject to adjustments in the
event of stock dividends, stock splits, issuance of shares below the $25
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
F-12
<PAGE> 80
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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 have been fulfilled.
Common Units/Stock
In December 1996, Spinnaker authorized 7,350,720 Common Units, of which
1,980,000 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.
On January 6, 1998, concurrent with the formation of Spinco, Spinco
authorized 7,199,520 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 11,000,000.
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 1,240,000 Common Units, 760,000 at $10 per Common
Unit and 480,000 at $31.25 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 1,520
shares of Common Stock at $10.00 per share and 178,460 shares of Common Stock at
$31.25 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
F-13
<PAGE> 81
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
charged 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 $(6.98) and
$(1.78) 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>
1998 1997 1996
-------------------- -------------------- ------------------
WEIGHTED WEIGHTED WEIGHTED
AVERAGE AVERAGE AVERAGE
SHARES/ EXERCISE EXERCISE EXERCISE
UNITS PRICE UNITS PRICE UNITS PRICE
--------- -------- --------- -------- ------- --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at the beginning of
period......................... 1,097,400 $18.23 694,400 $18.23 -- $ --
Granted........................ 88,920 10.00 247,000 10.00 425,600 10.00
Granted........................ 66,160 31.25 156,000 31.25 268,800 31.25
--------- --------- -------
Outstanding at end of period..... 1,252,480 18.33 1,097,400 18.23 694,400 18.23
========= ========= =======
Exercisable at end of period..... 608,856 18.27 358,360 18.23 138,880 18.23
========= ========= =======
Available for grant.............. 167,500 142,600 545,600
========= ========= =======
</TABLE>
The 1,252,480 options outstanding at December 31,1998, have a weighted
average remaining contractual life of eight years. Of these options as of
December 31, 1998, 694,400 are 60 percent exercisable, 403,000 are 40 percent
exercisable and 155,080 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.
Subsequent Event (Unaudited)
There has been no cumulative compensation expense under this plan through
March 31, 1999; however, based on management's estimate of the share value of
the Company at June 30, 1999, Spinnaker will record a charge of $1.7 million
during the second quarter of 1999.
F-14
<PAGE> 82
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 FOR THE THREE
(DECEMBER 20, FOR THE YEAR MONTHS ENDED
1996) THROUGH ENDED DECEMBER 31 MARCH 31
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) $ (1,854) $ (4,502)
BASIC:
Basic weighted average
units/shares................ 1,980,000 1,980,000 2,029,510 2,025,900 2,047,350
DILUTED:
Basic weighted average
units/shares................ 1,980,000 1,980,000 2,029,510 2,025,900 2,047,350
Dilutive securities: Preferred
Units/Stock................. -- -- -- -- --
---------- ---------- ---------- ---------- ----------
Diluted weighted average
units/shares................ 1,980,000 1,980,000 2,029,510 2,025,900 2,047,350
========== ========== ========== ========== ==========
NET LOSS PER UNIT/SHARE:
BASIC:
Loss before cumulative effect
of change in accounting
principle................... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.01)
Cumulative effect of change in
accounting principle........ -- -- -- -- (0.19)
---------- ---------- ---------- ---------- ----------
Net loss per common unit/share... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.20)
========== ========== ========== ========== ==========
DILUTED:
Loss before cumulative effect
of change in accounting
principle................... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.01)
Cumulative effect of change in
accounting principle........ -- -- -- -- (0.19)
---------- ---------- ---------- ---------- ----------
Net loss per common unit/share... $ (0.17) $ (1.76) $ (6.88) $ (0.92) $ (2.20)
========== ========== ========== ========== ==========
</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.
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
F-15
<PAGE> 83
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
shares of Common Stock upon the formation of Spinco. See also Note 4 concerning
the subsequent 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.
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
F-16
<PAGE> 84
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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.
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.
F-17
<PAGE> 85
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Cost Incurred
Cost 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.
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
Extension 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
====== ======
</TABLE>
F-18
<PAGE> 86
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<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
Extension 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 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.
F-19
<PAGE> 87
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
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 in 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-20
<PAGE> 88
APPENDIX A
March 30, 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 December 31, 1998. 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. December 1998 hydrocarbon prices were
used in the preparation of this report as required by SEC guidelines; however,
actual future prices may vary significantly from December 1998 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 December 31, 1998
<TABLE>
<CAPTION>
PROVED
-------------------------------------------------------
DEVELOPED
--------------------------- TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
----------- ------------- ----------- -----------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate -- Barrels............. 73,520 244,567 151,936 470,023
Gas -- MMCF........................... 7,240 23,566 20,140 50,946
INCOME DATA
Future Gross Revenue.................. $14,415,876 $46,687,767 $38,331,947 $99,435,590
Deductions............................ 2,204,742 16,624,865 15,791,024 34,620,631
----------- ----------- ----------- -----------
Future Net Income (FNI)............... $12,211,134 $30,062,902 $22,540,923 $64,814,959
Discounted FNI @ 10%.................. $10,740,907 $23,981,755 $17,386,496 $52,109,158
</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. Effective September 1, 1998, the Minerals Management Service (MMS) has
ordered that all gas production from federal leases be reported at 14.73 psia as
compared with 15.025 psia as historically used for the Gulf of Mexico. The
reserves reported herein reflect this pressure base change.
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 and condensate
processing and transportation fees which are shown as "other" deductions, and
certain abandonment costs net of salvage. The future net income is before the
deduction of state and federal income taxes and general administrative overhead,
and has not been adjusted for outstanding loans that may exist nor does it
include any adjustment for cash on hand or undistributed income. No attempt was
made to quantify or otherwise account for any accumulated gas production
imbalances that may exist.
A-1
<PAGE> 89
Gas reserves account for approximately 95 percent and liquid hydrocarbon
reserves account for the remaining 5 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 shut-in and behind pipe categories. The various reserve status categories
are defined in the section entitled "Reserve Status Categories" which is
attached with this report.
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by the volumetric
method due to the lack of historical production performance data to date. The
estimates of reserves utilized all pertinent well and 3-D seismic data available
through February 1999. The area of a reservoir was considered as proved based on
the area delineated by drilling and defined by fluid contacts or the lowest
known occurrence of hydrocarbons.
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 December 31, 1998 and these
prices were held constant throughout the life of the properties. These prices
were $1.835 per MMBTU of gas at Henry Hub, Louisiana, and $12.05 per barrel at
the Cushing NYMEX Pricing Hub based on light sweet crude on December 31, 1998.
In accordance with Securities and Exchange Commission guidelines, changes in
liquid and gas prices subsequent to December 31, 1998 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.
A-2
<PAGE> 90
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 and condensate processing and transportation fees are
included in this report as "other" deductions. These costs which are expressed
as a cost per MCF of gas have been adjusted for those properties located in the
federal waters offshore to account for the increase in gas volumes as a result
of revising the reporting pressure base from 15.025 psia to 14.73 psia as
currently required by the MMS. 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 February 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.
A-3
<PAGE> 91
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
PETROLEUM ENGINEERS
/s/ JOHN E. HODGIN
------------------------------------
John E. Hodgin, C.P.G.
Senior Vice President
JEH/sw
Approved:
/s/ RONALD HARRELL
- ------------------------------------
Ronald Harrell, P.E.
President
A-4
<PAGE> 92
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.
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:
A-5
<PAGE> 93
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
reasonable 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.
HYDROCARBON PRICING PARAMETERS
SECURITIES AND EXCHANGE COMMISSION PARAMETERS
OIL AND CONDENSATE
Spinnaker furnished us with oil and condensate prices in effect at December
31, 1998 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 December 31, 1998 were not considered in this
report. Product prices which were actually used for each property reflect
adjustment for gravity, quality, local conditions, and/or distance from market.
GAS
Spinnaker furnished us with gas prices in effect at December 31, 1998.
These prices have been adjusted for those properties located in the federal
waters offshore to account for the increase in gas volumes as a result of
revising the reporting pressure base from 15.025 psia to 14.73 psia as currently
required by the MMS. In addition, the prices used herein have been adjusted for
the BTU content, local conditions, and/or distance from market. In accordance
with SEC guidelines, the future gas prices used in this report make no
allowances for future gas price increases which may occur as a result of
inflation nor do they make any allowance for seasonal variations in gas prices
which may cause future yearly average gas prices to differ somewhat from the
December 31, 1998 gas prices used herein.
A-6
<PAGE> 94
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
The expenses of this offering are estimated to be as follows:
<TABLE>
<S> <C>
Securities and Exchange Commission registration fee......... $34,750
NASD filing fee............................................. 13,000
NASDAQ listing fee.......................................... *
Legal fees and expenses..................................... *
Accounting fees and expenses................................ *
Engineering fees and expenses............................... *
Blue Sky fees and expenses (including legal fees)........... *
Printing expenses........................................... *
Transfer Agent fees......................................... *
Miscellaneous............................................... *
-------
TOTAL............................................. $ *
=======
</TABLE>
- ---------------
* To be provided by amendment.
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Section 145 of the Delaware General Corporation Law ("DGCL") provides that
a corporation may indemnify any person who was or is a party or is threatened to
be made a party to any threatened, pending or completed action, suit or
proceeding whether civil, criminal, administrative or investigative (other than
an action by or in the right of the corporation) by reason of the fact that he
is or was a director, officer, employee or agent of the corporation, or is or
was serving at the request of the corporation as a director, officer, employee
or agent of another corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys' fees), judgments, fines and
amounts paid in settlement actually and reasonably incurred by him in connection
with such action, suit or proceeding if he acted in good faith and in a manner
he reasonably believed to be in or not opposed to the best interests of the
corporation, and, with respect to any criminal action or proceeding, had no
reasonable cause to believe his conduct was unlawful. Section 145 further
provides that a corporation similarly may indemnify any such person serving in
any such capacity who was or is a party or is threatened to be made a party to
any threatened, pending or completed action or suit by or in the right of the
corporation to procure a judgment in its favor by reason of the fact that he is
or was a director, officer, employee or agent of the corporation or is or was
serving at the request of the corporation as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys' fees) actually and reasonably
incurred in connection with the defense or settlement of such action or suit if
he acted in good faith and in a manner he reasonably believed to be in or not
opposed to the best interests of the corporation and except that no
indemnification shall be made in respect of any claim, issue or matter as to
which such person shall have been adjudged to be liable to the corporation
unless and only to the extent that the Delaware Court of Chancery or such other
court in which such action or suit was brought shall determine upon application
that, despite the adjudication of liability but in view of all of the
circumstances of the case, such person is fairly and reasonably entitled to
indemnity for such expenses which the Delaware Court of Chancery or such other
court shall deem proper.
Spinnaker's bylaws provide that indemnification shall be to the fullest
extent permitted by the DGCL for all current or former directors or officers of
Spinnaker.
As permitted by the DGCL, the certificate of incorporation provides that
directors of Spinnaker shall have no personal liability to Spinnaker or its
stockholders for monetary damages for breach of fiduciary duty as a director,
except (1) for any breach of the director's duty of loyalty to Spinnaker or its
II-1
<PAGE> 95
stockholders, (2) for acts or omissions not in good faith or which involve
intentional misconduct or a knowing violation of law, (3) for unlawful payments
of dividends or unlawful stock repurchases or redemptions as provided under
Section 174 of the DGCL or (4) for any transaction from which a director derived
an improper personal benefit.
Howard H. Newman and Jeffrey A. Harris, each directors of Spinnaker and
Managing Directors and members of E.M. Warburg, Pincus & Co., LLC and general
partners of Warburg, Pincus & Co., are indemnified by affiliates of E.M.
Warburg, Pincus & Co., LLC and Warburg, Pincus & Co. against certain liabilities
that they may incur as a result of their serving as a director of Spinnaker.
The Underwriting Agreement that Spinnaker will enter into with respect to
the offer and sale of the common stock covered by this registration statement
will contain certain provisions for the indemnification of directors and
officers of Spinnaker and the underwriters, as applicable, against civil
liabilities under the Securities Act.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES
The Registrant has sold and issued (without payment of any selling
commission to any person) the following securities since January 6, 1998:
(1) On January 16, 1998, we issued 958,921 shares of preferred stock
and 1,980,000 shares of common stock in connection with our conversion from
a limited liability company to a corporation in exchange for, directly or
indirectly, an equal number of preferred and common units of the limited
liability company.
(2) From January 1998 to September 1998, we issued 2,051,969 shares of
preferred stock for $25.00 per share to a total of two accredited
investors.
(3) From January 1998 to September 1998, we issued a total of 20,030
shares of preferred stock for $25.00 per share to a total of 26 of our
employees in exchange for cash and notes.
(4) From December 31, 1998 to June 30, 1999, we issued a total of
37,500 shares of common stock to a total of two accredited investors in
consideration for the guaranteeing of our indebtedness.
(5) On June 30, 1999, we issued 500,000 shares of common stock to one
accredited investor in consideration for entering into an amendment to our
seismic data agreement.
The sale of the above securities described in Item 15 were exempt from
registration under the Securities Act in reliance on Section 4(2) of the
Securities Act.
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<PAGE> 96
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Exhibits:
<TABLE>
<C> <S>
*1.1 -- Form of Underwriting Agreement
*3.1 -- Certificate of Incorporation of Spinnaker, as amended
*3.2 -- Bylaws of Spinnaker
*4.1 -- Specimen Common Stock certificate
*5.1 -- Opinion of Vinson & Elkins L.L.P.
*10.1 -- Second Amended and Restated Data Contribution Agreement
between Petroleum Geo-Services ASA, Seismic Energy
Holdings, Inc., Spinnaker Exploration Company, L.L.C. and
Spinnaker dated June 30, 1999
*10.2 -- 1998 Spinnaker Stock Option Plan
*10.3 -- Stockholders Agreement by and among Spinnaker, Warburg,
PGS, Roger L. Jarvis, James M. Alexander, William D.
Hubbard, Kelly M. Barnes and the other stockholders of
Spinnaker dated as of January 6, 1998 (including the
Registration Rights Agreement as Exhibit A to the
Stockholders Agreement)
*10.4 -- Credit Agreement for an $85 million credit facility
between Spinnaker and Credit Suisse First Boston, Bank of
Montreal and Bank of America dated September 30, 1998
*10.5 -- Employment Agreement between Spinnaker and Roger L.
Jarvis dated December 20, 1996
*10.6 -- Employment between Spinnaker and James M. Alexander dated
December 20, 1996
*10.7 -- Employment Agreement between Spinnaker and William D.
Hubbard dated February 24, 1997
*10.8 -- Employment Agreement between Spinnaker and Kelly M.
Barnes dated February 24, 1997
*21.1 -- List of subsidiaries of Spinnaker
23.1 -- Consent of Arthur Andersen LLP
23.2 -- Consent of Ryder Scott Company, L.P.
*23.3 -- Consent of Vinson & Elkins L.L.P. (contained in Exhibit
5.1 hereto)
24.1 -- Power of Attorney (included on the signature page to this
Registration Statement)
27 -- Financial Data Schedule
</TABLE>
- ---------------
* To be filed by amendment.
(b) Consolidated Financial Statement Schedules:
All schedules are omitted because the required information is inapplicable
or the information is presented in the Consolidated Financial Statements or
related notes.
II-3
<PAGE> 97
ITEM 17. UNDERTAKINGS
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted to directors, officers and controlling persons of the
Registrant pursuant to the foregoing provisions, or otherwise, the Registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Securities Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the Registrant of expenses
incurred or paid by a director, officer or controlling person of the Registrant
in the successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the Registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Securities Act and will be governed by the final
adjudication of such issue.
The undersigned Registrant hereby undertakes to provide to the underwriters
at the closing specified in the underwriting agreement certificates in such
denominations and registered in such names as required by the underwriters to
permit prompt delivery to each purchaser.
The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities
Act, the information omitted from the form of prospectus filed as part of
this Registration Statement in reliance upon Rule 430A and contained in a
form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or
(4) or 497(h) under the Securities Act shall be deemed to be part of this
Registration Statement as of the time it was declared effective.
(2) For purposes of determining any liability under the Securities
Act, each post-effective amendment that contains a form of prospectus shall
be deemed to be a new registration statement relating to the securities
offered therein, and the offering of such securities at that time shall be
deemed to be the initial bona fide offering thereof.
II-4
<PAGE> 98
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, as amended, the
Registrant has duly caused this Registration Statement to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Houston,
State of Texas, on the 16th day of July, 1999.
SPINNAKER EXPLORATION COMPANY
By: /s/ ROGER L. JARVIS
----------------------------------
Roger L. Jarvis
Chairman, President and Chief
Executive Officer
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Roger L. Jarvis and James M. Alexander, or either
of them, his true and lawful attorney-in-fact and agent, with full power of
substitution, for him and in his name, place and stead, in any and all
capacities, to sign any and all amendments (including post-effective amendments)
to this Registration Statement, and any additional registration statements
pursuant to Rule 462(b), and to file the same with all exhibits thereto, and
other documents in connection therewith, with the Securities and Exchange
Commission, granting unto said attorney-in-fact and agent full power and
authority to do and perform each and every act and thing requisite and ratifying
and confirming all that said attorney-in-fact and agent or his substitute or
substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Act of 1933, as amended,
this Registration Statement has been signed below by the following persons in
the capacities and on the 16th day of July, 1999.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<C> <S>
/s/ ROGER L. JARVIS Chairman, President and Chief Executive
- ----------------------------------------------------- Officer and Director (Principal Executive
Roger L. Jarvis Officer)
/s/ JAMES M. ALEXANDER Vice President, Chief Financial Officer and
- ----------------------------------------------------- Secretary (Principal Financial and
James M. Alexander Accounting Officer)
/s/ REIDAR MICHAELSEN Director
- -----------------------------------------------------
Reidar Michaelsen
/s/ BJARTE BRUHEIM Director
- -----------------------------------------------------
Bjarte Bruheim
/s/ HOWARD H. NEWMAN Director
- -----------------------------------------------------
Howard H. Newman
/s/ JEFFREY A. HARRIS Director
- -----------------------------------------------------
Jeffrey A. Harris
</TABLE>
II-5
<PAGE> 99
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
*1.1 -- Form of Underwriting Agreement
*3.1 -- Certificate of Incorporation of Spinnaker, as amended
*3.2 -- Bylaws of Spinnaker
*4.1 -- Specimen Common Stock certificate
*5.1 -- Opinion of Vinson & Elkins L.L.P.
*10.1 -- Second Amended and Restated Data Contribution Agreement
between Petroleum Geo-Services ASA, Seismic Energy
Holdings, Inc., Spinnaker Exploration Company, L.L.C. and
Spinnaker dated June 30, 1999
*10.2 -- 1998 Spinnaker Stock Option Plan
*10.3 -- Stockholders Agreement by and among Spinnaker, Warburg,
PGS, Roger L. Jarvis, James M. Alexander, William D.
Hubbard, Kelly M. Barnes and the other stockholders of
Spinnaker dated as of January 6, 1998 (including the
Registration Rights Agreement as Exhibit A to the
Stockholders Agreement)
*10.4 -- Credit Agreement for an $85 million credit facility
between Spinnaker and Credit Suisse First Boston, Bank of
Montreal and Bank of America dated September 30, 1998
*10.5 -- Employment Agreement between Spinnaker and Roger L.
Jarvis dated December 20, 1996
*10.6 -- Employment between Spinnaker and James M. Alexander dated
December 20, 1996
*10.7 -- Employment Agreement between Spinnaker and William D.
Hubbard dated February 24, 1997
*10.8 -- Employment Agreement between Spinnaker and Kelly M.
Barnes dated February 24, 1997
*21.1 -- List of subsidiaries of Spinnaker
23.1 -- Consent of Arthur Andersen LLP
23.2 -- Consent of Ryder Scott Company, L.P.
*23.3 -- Consent of Vinson & Elkins L.L.P. (contained in Exhibit
5.1 hereto)
24.1 -- Power of Attorney (included on the signature page to this
Registration Statement)
27 -- Financial Data Schedule
</TABLE>
- ---------------
* To be filed by amendment.
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the use of our
report dated April 13, 1999 and to all references to our Firm included in or
made a part of this registration statement.
ARTHUR ANDERSEN LLP
Houston, Texas
July 16, 1999
<PAGE> 1
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to the inclusion of our letter dated March 30, 1999 to
Spinnaker Exploration Company (the "Company") regarding our estimates of proved
reserves, future production and income attributable to certain leasehold
interests of the Company in this Registration Statement on Form S-1 (the
"Registration Statement") of the Company and all references to Ryder Scott
Company and/or the reports prepared by Ryder Scott Company entitled, "Estimated
Future Reserves and Income Attributable to Certain Leasehold Interests SEC Case
as of December 31, for the years 1997 and 1998" in this Registration Statement
and to the reference to our firm as experts in this Registration Statement.
RYDER SCOTT COMPANY, L.P.
July 16, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C> <C>
<PERIOD-TYPE> YEAR 3-MOS
<FISCAL-YEAR-END> DEC-31-1998 DEC-31-1998
<PERIOD-START> JAN-01-1998 JAN-01-1999
<PERIOD-END> DEC-31-1998 MAR-31-1999
<CASH> 2,141 304
<SECURITIES> 0 0
<RECEIVABLES> 3,821 8,135
<ALLOWANCES> 0 0
<INVENTORY> 0 0
<CURRENT-ASSETS> 6,737 10,829
<PP&E> 102,272 118,832
<DEPRECIATION> 6,665 8,504
<TOTAL-ASSETS> 102,769 121,982
<CURRENT-LIABILITIES> 37,378 57,580
<BONDS> 0 0
0 0
30 30
<COMMON> 20 20
<OTHER-SE> 56,863 52,586
<TOTAL-LIABILITY-AND-EQUITY> 121,769 121,982
<SALES> 3,298 1,839
<TOTAL-REVENUES> 3,298 1,839
<CGS> 0 0
<TOTAL-COSTS> 474<F1> 240<F1>
<OTHER-EXPENSES> 9,405<F2> 2,746<F2>
<LOSS-PROVISION> 0 0
<INTEREST-EXPENSE> 279 467
<INCOME-PRETAX> (6,860) (1,614)
<INCOME-TAX> 0 0
<INCOME-CONTINUING> (6,860) (1,614)
<DISCONTINUED> 0 0
<EXTRAORDINARY> 0 0
<CHANGES> 0 (395)
<NET-INCOME> (6,860) (2,009)
<EPS-BASIC> (6.88) (2.20)
<EPS-DILUTED> (6.88) (2.20)
<FN>
<F1>INCLUDES NATURAL GAS AND OIL OPERATING EXPENSES ONLY.
<F2>INCLUDES OTHER OPERATING EXPENSES AND OTHER INCOME.
</FN>
</TABLE>
