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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[X]Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 for the fiscal year ended December 31, 1999.
[_]Transition Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the transition period from to .
Commission file number 000-27473
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SPINNAKER EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 76-0560101
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
77002
1200 Smith Street, Suite 800 (Zip Code)
Houston, Texas
(Address of principal executive
offices)
(713) 759-1770
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Name of each exchange on
Title of each class which registered
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Common Stock, $0.01 Par Value The Nasdaq Stock Market
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No[_]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant on March 1, 2000 was approximately
$131,060,000.
The number of shares outstanding of the registrant's Common Stock, par value
$0.01 per share, on March 1, 2000 was 20,409,936.
Parts of the following document are incorporated by reference to Part III of
this Form 10-K Report: Proxy Statement for the registrant's 2000 Annual
Meeting of Stockholders.
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TABLE OF CONTENTS TO FORM 10-K
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PART I
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Item 1.Business.......................................................... 1
Item 2.Properties........................................................ 22
Item 3.Legal Proceedings................................................. 25
Item 4.Submission of Matters to a Vote of Security Holders............... 25
PART II
Item 5.Market for Registrant's Common Equity and Related Stockholder
Matters................................................................. 25
Item 6.Selected Financial Data........................................... 26
Item 7.Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................... 28
Item 7A.Quantitative and Qualitative Disclosures About Market Risk....... 32
Item 8.Financial Statements and Supplementary Data....................... 33
Item 9.Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.................................................... 33
PART III
Item 10.Directors and Executive Officers of the Registrant............... 33
Item 11.Executive Compensation........................................... 33
Item 12.Security Ownership of Certain Beneficial Owners and Management... 33
Item 13.Certain Relationships and Related Transactions................... 33
PART IV
Item 14.Exhibits, Financial Statement Schedules, and Reports on Form
8-K..................................................................... 34
Signatures............................................................... 35
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Forward-Looking Statements and Assumptions
Some of the information in this Annual Report on Form 10-K, including
information incorporated by reference, contains forward-looking statements.
These statements express, or are based on, the Company's expectations about
future events. These include such matters as:
. the Company's financial position;
. business strategy;
. budgets;
. amount, nature and timing of capital expenditures;
. drilling of wells;
. natural gas and oil reserves;
. timing and amount of future production of natural gas and oil;
. operating costs and other expenses;
. cash flow and anticipated liquidity;
. prospect development and property acquisitions; and
. marketing of natural gas and oil.
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" in "Item 1. Business." These factors include, among others:
. the risks associated with exploration;
. the ability to find, acquire, market, develop and produce new properties;
. natural gas and oil price volatility;
. uncertainties in the estimation of proved reserves and in the projection
of future rates of production and timing of development expenditures;
. operating hazards attendant to the natural gas and oil business;
. downhole drilling and completion risks that are generally not recoverable
from third parties or insurance;
. potential mechanical failure or under-performance of significant wells;
. climatic conditions;
. availability and cost of material and equipment;
. delays in anticipated start-up dates;
. actions or inactions of third-party operators of the Company's
properties;
. the ability to find and retain skilled personnel;
. availability of capital;
. the strength and financial resources of competitors;
. regulatory developments;
. environmental risks and;
. general economic conditions.
When you consider these forward-looking statements, you should keep in mind
these risk factors and the other cautionary statements in this Form 10-K. The
forward-looking statements speak only as of the date made.
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PART I
Item 1. Business
Spinnaker Exploration Company has provided definitions for some of the
natural gas and oil industry terms used in this report in the "Glossary of
Natural Gas and Oil Terms" at the end of this Item 1.
General
Spinnaker Exploration Company ("Spinnaker" or the "Company") is an
independent energy company engaged in the exploration, development and
production of natural gas and oil in the U.S. Gulf of Mexico ("Gulf of
Mexico"). The Company has license rights to approximately 7,000 blocks of
mostly contiguous, recent vintage 3-D seismic data in the Gulf of Mexico,
including approximately 5,300 blocks from its 3-D seismic data agreement
("Data Agreement") with Petroleum Geo-Services ASA ("PGS"). This database
covers an area of approximately 31 million acres, which the Company believes
is one of the largest recent vintage 3-D seismic databases of any independent
exploration and production company in the Gulf of Mexico. The Company
considers recent vintage 3-D seismic data to be data that was generated in the
1990s. The Company has a leasehold interest in approximately 145 tracts
located in Texas state and federal waters. These tracts are of various sizes
and currently total approximately 497,000 gross and 192,000 net acres. The
Company believes that regional 3-D seismic analysis allows it to create a
large inventory of high-quality prospects and provides the opportunity to
enhance its exploration success. The Company also believes the license rights
to large quantities of high-quality seismic data and management and technical
staff are important factors for current and future success.
Spinnaker's chief executive officer, PGS and Warburg, Pincus Ventures, L.P.
("Warburg") formed Spinnaker in December 1996. PGS, a leader in acquiring 3-D
seismic data, received most of its equity ownership in Spinnaker in exchange
for providing the Company 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. The Company plans to continue to grow its inventory of 3-D
seismic data through its Data Agreement with PGS and through acquisitions of
3-D seismic data from other seismic data vendors.
Since inception through December 31, 1999, the Company participated in
drilling 31 exploratory wells in the Gulf of Mexico, with 21 of these wells
being completed as discoveries. As of December 31, 1999, Ryder Scott Company,
L.P. estimated the Company's net proved reserves at approximately 104.5 Bcfe,
86% of which was natural gas, representing an increase of approximately 94%
over estimated net proved reserves of 53.8 Bcfe at December 31, 1998. Daily
production has increased from approximately 8,000 Mcfe at December 31, 1998 to
approximately 53,000 Mcfe at December 31, 1999. Within its current inventory
of approximately 145 leases, the Company has identified approximately 75
exploratory prospects and leads. The Company expects to drill 20 or more of
these prospects during 2000. Based on 3-D seismic analysis on blocks where it
currently has no leasehold interest, the Company also has identified
approximately 150 additional leads that may result in additional prospects.
The capital expenditure budget for 2000 includes approximately $115 million
for exploration, development, leasehold acquisitions and other capital
expenditures.
On September 28, 1999, the Company priced its initial public offering of
8,000,000 shares of common stock, par value $0.01 per share ("Common Stock").
After payment of underwriting discounts and commissions, the Company received
net proceeds of $108.7 million on October 4, 1999. With a portion of the
proceeds, the Company retired all then outstanding debt of $72.0 million. The
Company is using the remaining net proceeds after offering costs to fund
exploration and development activities. In connection with the initial public
offering, the Company converted all outstanding Series A Convertible Preferred
Stock, par value $0.01 per share ("Preferred Stock"), into shares of Common
Stock, and certain shareholders reinvested preferred dividends payable of
$16.3 million into shares of Common Stock.
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Business Strategy
Spinnaker's goals are to expand its reserve base, cash flow and net income
and to generate an attractive return on capital. The Company emphasizes the
following elements in its strategy to achieve these goals:
. Focus on the Gulf of Mexico
. Maintain a large database of 3-D seismic data
. Employ a rigorous prospect selection process
. Emphasize technical expertise
. Sustain a balanced, diversified exploration effort.
Focus on the Gulf of Mexico. Spinnaker has chosen to assemble a large 3-D
seismic database and focus its exploration activities in the Gulf of Mexico
because it believes this area represents one of the most attractive
exploration regions in North America. The Gulf of Mexico has the following
characteristics which make it attractive to exploration and production
companies:
. Prolific exploration and production history
. Open access to acreage
. Substantial existing oilfield service and pipeline 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.
The Company also believes its geographic focus provides an excellent
opportunity to develop and maintain competitive advantages through the
combination of its 3-D seismic database, regional exploration and operating
expertise, and joint venture relationships.
Maintain a large database of 3-D seismic data. Spinnaker believes its large
database of 3-D seismic data allows it to generate high-quality exploratory
prospects. The Company believes the 3-D seismic data received from PGS will
continue to serve as the foundation for its exploration program. The Company
also intends to supplement that data with 3-D seismic data acquisitions from
other seismic data vendors. In addition to data acquisitions made directly by
Spinnaker, the Company expects to continue to enter into joint ventures with
other companies to share the costs of data acquisitions and exploratory
drilling.
Employ a rigorous prospect selection process. Spinnaker uses its large
inventory of contiguous areas of 3-D seismic data to select prospects by tying
regional 3-D seismic analysis to actual drilling results. Through this
process, the Company enhances its understanding of the geology before
selecting prospects and increases the probability of accurately identifying
hydrocarbon-bearing zones.
Emphasize technical expertise. Spinnaker's 10 explorationists have an
average of approximately 20 years experience in exploration in the Gulf of
Mexico. In its efforts to attract and retain explorationists, the Company
offers an entrepreneurial culture, an extensive 3-D seismic database, state-
of-the-art computer-aided exploration technology and other technical tools.
All of the explorationists have purchased equity in Spinnaker.
As Spinnaker matures, it is moving towards retaining larger working
interests in prospects located in water depths of less than 2,000 feet. The
combination of larger working interests and its technical expertise should
allow the Company to act as the operator for an increasing number of these
prospects, providing more control of costs, the timing and amount of capital
expenditures, and the selection of technology.
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Sustain a balanced, diversified exploration effort. Spinnaker believes that
its exploration approach results in portfolio balance and diversity among:
. shallow water, or water depths of less than 600 feet, and deep water
prospects;
. shallow drilling depth, or drilling depths of less than 12,000 feet, and
deep drilling depth prospects; and
. lower-risk, lower-potential prospects and higher-risk, higher-potential
prospects.
Spinnaker has used joint ventures to help diversify its exploration
activities. The Company's 3-D seismic data's broad coverage of the Gulf of
Mexico allows it to participate in a variety of geologically diverse
exploration opportunities and create a diversified prospect portfolio. The
Company intends to manage its exposure in deep water exploration activities by
focusing on prospects where commercial feasibility of the prospect can be
evaluated with one or two wells and where it believes 3-D seismic analysis
provides attractive risk/reward benefits. The Company also strives to
diversify its exploration efforts by seeking to limit the budgeted amount of
the dry hole costs of the first exploratory well, including any planned
sidetracks, on any one prospect to less than 10% of the annual capital budget.
The Company believes that maintaining continuity in its exploration activity
during all phases of the commodity price cycles is an important element to
balance and diversification. By positioning the Company to continue exploring
during periods of low natural gas and oil prices, it potentially can take
advantage of reduced competition for prospects and lower drilling and other
oilfield service costs.
PGS Data Agreement
The Company originally entered into the Data Agreement as of December 20,
1996. The Company amended the Data Agreement as of January 6, 1998 when it
converted from a limited liability company to a corporation. The Company
amended the Data Agreement again as of June 30, 1999 to modify the amount,
type and geographic coverage of the data and related information made
available to the Company. In connection with the second amendment, the Company
issued 1,000,000 shares of Common Stock to PGS. The following summary
discusses material provisions of the Data Agreement and is qualified by
reference to the exhibit incorporated by reference in this Form 10-K.
Data Covered by the Data Agreement
Subject to the exceptions discussed below, the Company is entitled to
receive and use all of the standard and enhanced multi-client 3-D seismic data
covering the Gulf of Mexico, including its bays, channels, tributaries,
estuaries and transition zones that PGS acquires or processes for itself prior
to March 31, 2002 or is in the process of acquiring or processing as of that
date. However, PGS is not obligated under its agreement to acquire any further
data of any kind. The Company is also entitled to enhanced data processed by
third parties if PGS retains a material royalty or similar interest in that
data.
As part of its business activities, PGS acquires both proprietary and multi-
client marine seismic data. When PGS acquires proprietary data, it does so on
an exclusive contractual basis for its customers. In this case, PGS simply
provides acquisition services. When PGS acquires multi-client data, however,
it owns the data itself and transfers the possession and use of copies of this
data to the industry at large. The Company is entitled to receive only multi-
client data from PGS.
Standard data is the basic 3-D, time-migrated seismic data, and dragged
array and vertical cable data as now provided as the standard product to PGS'
3-D seismic survey customers. Enhanced data is data created through additional
computer processing of PGS' standard data. Enhanced data includes processed
data referred to as pre-stack depth migrated data, 3-D amplitude versus offset
processing and refined pre-stack time migrated data. The Company has license
rights to approximately 4,400 blocks of standard data and 845 blocks of
enhanced data under the Data Agreement.
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PGS acquires an advanced form of 3-D marine seismic data, sometimes referred
to as multi-component data, that requires the simultaneous recording of
information with instruments located on the ocean floor and instruments
dragged behind a marine seismic vessel. The Company is entitled to select for
its use up to 60 blocks of multi-component data that PGS acquires, if any,
prior to March 31, 2002 or is in the process of acquiring as of that date. The
Company must select multi-component data in groups of blocks which are all
contiguous on at least one side and which include at least five blocks.
PGS markets Gulf of Mexico seismic data through seismic data marketing
vendors. The Company has entered into agreements with some of these marketing
vendors which modify, to some extent, the Company's rights under the Data
Agreement. Material modifications of its rights resulting from these
agreements are noted below. If PGS enters into a marketing agreement with a
new party, then PGS has agreed to use good faith efforts to obtain the consent
of the new party to the Company's rights under the Data Agreement. If PGS does
not obtain the consent of this new party, however, then the Company may not be
entitled to the future data of PGS that is marketed by that party. A majority
of the data the Company has received is subject to agreements with marketing
vendors.
Rights to Use the Data
The Company may use the data received under the Data Agreement as follows:
. for its internal needs, including using the data in connection with the
drilling of wells or the acquiring of interests in natural gas or oil
properties;
. make maps and other work products from the data;
. make the data and work product available to the Company's consultants and
contractors for interpretation, analysis, evaluation, mapping and
additional processing; provided that the data and work product, other
than maps, may not be removed from its premises and must be held in
confidence by those individuals; and
. show data and work products to prospective and existing investors and
participants in farm-outs and exploration or development groups for the
sole purpose of evaluating their participation in such ventures; provided
that the data and work product, other than maps, may not be removed from
its premises and must be held in confidence by those individuals.
The Data Agreement provides that the Company's rights to use data are
perpetual subject to the termination provisions discussed below. However, its
related agreements with PGS' marketing vendors provide that its rights
terminate automatically after 25 years. The data received by the Company under
the Data Agreement remains the property of PGS subject to the rights granted
to the Company in the Data Agreement.
Restrictions on Transfer and Assignment
The Company has the limited right to transfer a copy of standard or enhanced
data to a qualified transferee. A qualified transferee is a party with which
the Company has entered into a joint venture or other contractual arrangement
with respect to the property relating to the copied data. A qualified
transferee must have substantial business interests other than this joint
venture or contractual relationship, must not have been formed to acquire the
copied data and must have executed a customary license agreement with PGS or
one of its vendors. A transfer of a copy of standard data together with the
related enhanced data covering one block counts as the transfer of 1.5 blocks.
The Company may transfer copies only up to an aggregate of 568.6 blocks. The
Company must transfer copies of data in groups of blocks that are contiguous
on at least one side and which include at least 20 blocks.
The Company may assign its rights under the Data Agreement, directly or by
merger, to a successor to all or substantially all of its business or assets
or the business or assets of Spinnaker Exploration Company, L.L.C., the
Company's principal subsidiary, as long as the successor is not a PGS
competitor. A PGS competitor is a
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company that provides 3-D marine seismic data in the Gulf of Mexico as a
significant part of its business or an affiliate of such company. If the
successor to the Company's business or assets is not a PGS major customer,
then that successor may in turn transfer the rights under the Data Agreement
to a successor of all of its business or assets as long as that successor is
not a PGS competitor. A PGS major customer is a customer that has purchased
from PGS products and services at least equal to 7.5% of PGS' prior twelve
months gross receipts for all seismic data sales and related services in the
Gulf of Mexico or an affiliate of that customer. No other transfers of its
rights under the Data Agreement by the Company or its successors are
permitted. In addition, one of the Company's agreements with a PGS marketing
vendor provides that it may not assign its rights to PGS data marketed by that
vendor without the consent of that vendor.
Termination Events
PGS may terminate substantially all of the Company's rights under the Data
Agreement by giving notice after any of the following events:
. the Company transfers data or its rights under the Data Agreement in
violation of the Data Agreement;
. a PGS competitor acquires control of the Company or its principal
subsidiary;
. a PGS major customer acquires control of the Company or its principal
subsidiary after another PGS major customer has previously acquired
control of the Company or its principal subsidiary;
. the Company knowingly breaches one of the provisions of the Data
Agreement relating to the use, transfer or disclosure of the data and the
breach results in significant damages to PGS;
. the Company unknowingly breaches one of these provisions of the Data
Agreement, the breach results in significant damages to PGS and the
Company fails to diligently prevent a subsequent breach after it receives
notice of the first breach;
. the Company commits a material breach of one of the other provisions of
the Data Agreement and fails to remedy the breach within 90 days after
notice to the Company; or
. the Company commences a voluntary bankruptcy or similar proceeding, or an
involuntary bankruptcy or similar proceeding is commenced against the
Company and remains un-dismissed for 30 days.
Non-Compete
PGS has agreed that it will not disclose data covering the majority of the
blocks in any survey in the Gulf of Mexico that is marketed by PGS as a single
survey in exchange for interests in any natural gas or oil property or natural
gas and oil company. This restriction terminates on March 31, 2002.
Additional Services
Under the Data Agreement, the Company has access to 3-D seismic data to
March 31, 2003 through the proprietary high technology data archival and
retrieval system of PGS Data Management Inc., a subsidiary of PGS.
The Company has agreed to purchase $2,000,000 of seismic-related services
from PGS prior to December 31, 2002. The Company paid to PGS approximately
$59,000, $122,000 and $318,000 in 1997, 1998 and 1999, respectively, for
seismic-related services.
Limitation of Liability
The aggregate liability of PGS under the Data Agreement for all claims made
by the Company is limited to $45,000,000. The Company's liability for claims
made against it by PGS under the Data Agreement is not limited.
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Use of Computer-Aided Exploration Technology
Computer-aided exploration is the process of using a computer workstation
and common database to accumulate and analyze seismic, production and other
data regarding a geographic area. In general, computer-aided exploration
involves accumulating various 2-D and 3-D seismic data with respect to a
potential drilling location and correlating that data with historical well
control and production data from similar properties. The available data is
then analyzed using computer software and modeling techniques to project the
likely geologic setting of a potential drilling location and potential
locations of undiscovered natural gas and oil reserves. This process relies on
a comparison of actual data for the potential drilling location and historical
data for the density and sonic characteristics of different types of rock
formations, hydrocarbons and other subsurface minerals, resulting in a
projected three-dimensional image of the subsurface. This modeling is
performed through the use of advanced interactive computer workstations and
various combinations of available computer software developed solely for this
application.
The Company has invested extensively in the advanced computer hardware and
software necessary for 3-D seismic exploration. The Company currently has 15
workstations in-house to analyze seismic data. The Company's explorationists
can access a diverse software tool kit including modeling, mapping, well path
description, time slice analysis, pre- and post-stack seismic processing,
synthetic generation, fluid replacement studies and seismic attribute
analyses. Additionally, the Company has invested in direct-link
telecommunications technology that provides disk-to-disk downloading of data
volumes directly from PGS that allows very rapid loading on the Company's in-
house storage. This capability has benefited the Company when new data sets
are made available only a short time prior to state and federal lease sales.
Joint Ventures with Gulf of Mexico Partners
Early Joint Venture Agreements
The Company has entered into a number of joint ventures with several
companies operating in the Gulf of Mexico. In early joint venture agreements,
in return for access to 3-D seismic data and exploration expertise, joint
venture partners provided the Company with established Gulf of Mexico
exploration and operating track records, as well as capital. The joint venture
partners typically acted as operator, which freed the Company to concentrate
on exploring for new prospects.
Each of the 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. The Company's percentage ownership interest ranges from 25% to
65%. The joint venture partners are entitled to serve as the operator for any
acquired lease that is not operated by a third party.
Through the Data Agreement, the Company has rights to 3-D seismic data
covering substantially all of the areas of mutual interest established by
these joint venture agreements. The Company has licensed or provided access to
this data to the joint venture partners. In return, the joint venture partners
must reimburse the Company for a portion of the value of this data.
As of December 31, 1999, five of these joint venture agreements were active
with expiration dates between February and July 2000.
Recent Joint Venture Agreements
As the Company matures, it intends to enter new joint ventures in order to
leverage the 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
agreements which represent examples of the first two joint venture benefits
described above.
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In January 1999, the Company 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, the Company 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. The Company has rights to
approximately 455 additional blocks of data in this area of mutual interest
under the Data Agreement. Each of the participation agreements provides the
joint venture partners with access rights to all of the Company's data
covering the area of mutual interest. In return, each of the joint venture
partners has agreed to reimburse the Company, at 50% each, for its costs to
acquire licensing rights to the data covering the 435 blocks described above.
The Company is responsible for evaluating the 3-D seismic data and
identifying prospects for exploration, development and production activities
within the area of mutual interest. If the Company acquires a leasehold
interest in any of the blocks in the area of mutual interest, one of the joint
venture partners can acquire a 25% interest and the other joint venture
partner can acquire up to a 25% interest in the Company's leasehold interest.
The Company 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 the Company to allow the joint venture
partner to participate in any leasehold interest that the Company acquires in
the area of mutual interest, but does not give the Company 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 the 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.
Marketing
Most of the Company's natural gas and oil production is sold under price
sensitive or market price contracts. Revenues, profitability and future growth
depend substantially on prevailing prices for natural gas and oil. The price
received by the Company for its natural gas and oil production fluctuates
widely. For example, natural gas and oil prices declined significantly in 1998
and, for an extended period of time, remained substantially below prices
obtained in previous years. Among the factors that can cause this fluctuation
are the level of consumer product demand, weather conditions, domestic and
foreign governmental regulations, the price and availability of alternative
fuels, political conditions in natural gas and oil producing regions, the
domestic and foreign supply of natural gas and oil, the price of foreign
imports and overall economic conditions.
Decreases in the prices of natural gas and oil could adversely affect the
carrying value of proved reserves and revenues, profitability and cash flow.
Although the Company is not currently experiencing any significant involuntary
curtailment of natural gas or oil production, market, economic and regulatory
factors may in the future materially affect its ability to sell natural gas or
oil production. For the year ended December 31, 1999, sales to Columbia Energy
Services ("Columbia") were 68% and sales to Cokinos Energy Corporation
("Cokinos") were 32% of the Company's natural gas and oil revenues. For the
years ended December 31, 1998 and 1997, sales to Cokinos were 100% of the
Company's natural gas and oil revenues.
Currently, all of the Company's natural gas production is sold at current
market prices to Columbia. Columbia generally is not required to pay the
Company for production until approximately 30 to 60 days after delivery of the
production. As a result, if Columbia were to default on its payment
obligations to the Company for its production, near-term earnings and cash
flows would be adversely affected. However, due to the availability of other
markets and pipeline connections, the Company does not believe that the loss
of Columbia or any other customer would adversely affect its ability to market
production.
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To reduce exposure to fluctuations in the prices of natural gas and oil, the
Company has entered into hedging arrangements. Hedging arrangements expose the
Company to risk of financial loss when production is less than expected, when
the other party to the hedging contract defaults on its contract obligations
or when there is a change in the expected differential between the underlying
price in the hedging agreement and actual prices received. In addition, these
hedging arrangements may limit the benefit the Company would receive from
increases in the prices for natural gas and oil. The Company cannot provide
assurance that the hedging transactions it has entered into, or may enter
into, will adequately protect it from fluctuations in the prices of natural
gas and oil.
On the other hand, the Company may choose not to engage in hedging
transactions in the future. As a result, the Company may be more adversely
affected by changes in natural gas and oil prices than its competitors which
engage in hedging transactions. For further information concerning hedging
transactions, see "Item 7A. Quantitative and Qualitative Disclosures about
Market Risk."
Competition
The Company competes with major and independent natural gas and oil
companies for property acquisitions. The Company also competes for the
equipment and labor required to operate and develop these properties. Most of
the Company's competitors have substantially greater financial and other
resources. In addition, larger competitors may be able to absorb the burden of
any changes in federal, state and local laws and regulations more easily than
the Company can, which would adversely affect its competitive position. These
competitors may be able to pay more for exploratory prospects and productive
natural gas and oil properties and may be able to define, evaluate, bid for
and purchase a greater number of properties and prospects than the Company
can. The Company's ability to explore for natural gas and oil prospects and to
acquire additional properties in the future will depend upon its ability to
conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. In addition,
most of the Company's competitors have been operating in the Gulf of Mexico
for a much longer time than the Company has and have demonstrated the ability
to operate through industry cycles.
Regulation
Federal Regulation of Sales and Transportation of Natural Gas
Historically, the transportation and sale for resale of natural gas in
interstate commerce have been regulated pursuant to the Natural Gas Act of
1938, the Natural Gas Policy Act of 1978 and the regulations promulgated
thereunder by the Federal Energy Regulatory Commission ("FERC"). In the past,
the federal government has regulated the prices at which natural gas could be
sold. Deregulation of natural gas sales by producers began with the enactment
of the Natural Gas Policy Act of 1978. In 1989, Congress enacted the Natural
Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act of
1938 and Natural Gas Policy Act of 1978 price and non-price controls affecting
producer sales of natural gas effective January 1, 1993. Congress could,
however, re-enact price controls in the future.
The Company's sales of natural gas are affected by the availability, terms
and cost of pipeline transportation. The price and terms for access to
pipeline transportation remain subject to extensive federal regulation.
Commencing in April 1992, the FERC issued Order No. 636 and a series of
related orders, which required interstate pipelines to provide open-access
transportation on a basis that is equal for all natural gas suppliers. The
FERC has stated that it intends for Order No. 636 and its future restructuring
activities to foster increased competition within all phases of the natural
gas industry. Although Order No. 636 does not directly regulate the Company's
production and marketing activities, it does affect how buyers and sellers
gain access to the necessary transportation facilities and how the Company and
its competitors sell natural gas in the marketplace. The courts have largely
affirmed the significant features of Order No. 636 and the numerous related
orders pertaining to individual pipelines, although some appeals remain
pending and the FERC continues to review and modify its regulations regarding
the transportation of natural gas. For example, the FERC recently issued Order
No. 637
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which, among other things, (i) lifts the cost-based cap on pipeline
transportation rates in the capacity release market until September 30, 2002,
for short-term releases of pipeline capacity of less than one year, (ii)
permits pipelines to charge different maximum cost-based rates for peak and
off-peak periods, (iii) encourages, but does not mandate, auctions for
pipeline capacity, (iv) requires pipelines to implement imbalance management
services, (v) restricts the ability of pipelines to impose penalties for
imbalances, overruns and non-compliance with operational flow orders, and (vi)
implements a number of new pipeline reporting requirements. Order No. 637 also
requires the FERC Staff to analyze whether the FERC should implement
additional fundamental policy changes, including, among other things, whether
to pursue performance-based ratemaking or other non-cost based ratemaking
techniques and whether the FERC should mandate greater standardization in
terms and conditions of service across the interstate pipeline grid. In
addition, the FERC recently implemented new regulations governing the
procedure for obtaining authorization to construct new pipeline facilities and
has issued a policy statement, which it largely affirmed in a recent order on
rehearing, establishing a presumption in favor of requiring owners of new
pipeline facilities to charge rates based solely on the costs associated with
such new pipeline facilities. The Company cannot predict what further action
the FERC will take on these matters, nor can it accurately predict whether the
FERC's actions will achieve the goal of increasing competition in markets in
which the Company's natural gas is sold. However, the Company does not believe
that any action taken will affect it in a way that materially differs from the
way it affects other natural gas producers, gatherers and marketers.
The Outer Continental Shelf Lands Act ("OCSLA") requires that all pipelines
operating on or across the Outer Continental Shelf provide open-access, non-
discriminatory service. Although the FERC has opted not to impose the
regulations of Order No. 509, in which the FERC implemented the OCSLA, on
gatherers and other non-jurisdictional entities, the FERC has retained the
authority to exercise jurisdiction over those entities if necessary to permit
non-discriminatory access to service on the Outer Continental Shelf.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.
Federal Leases
A substantial portion of the Company's operations is located on federal
natural gas and oil leases, which are administered by the Minerals Management
Service ("MMS"). Such leases are issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the Outer Continental Shelf Lands Act which
are subject to interpretation and change by the MMS. For offshore operations,
lessees must obtain MMS approval for exploration plans and development and
production plans prior to the commencement of such operations. In addition to
permits required from other agencies such as the Coast Guard, the Army Corps
of Engineers and the Environmental Protection Agency, lessees must obtain a
permit from the MMS prior to the commencement of drilling. The MMS has
promulgated regulations requiring offshore production facilities located on
the Outer Continental Shelf to meet stringent engineering and construction
specifications. The MMS also has regulations restricting the flaring or
venting of natural gas, and has proposed to amend such regulations to prohibit
the flaring of liquid hydrocarbons and oil without prior authorization.
Similarly, the MMS has promulgated other regulations governing the plugging
and abandonment of wells located offshore and the installation and removal of
all production facilities. To cover the various obligations of lessees on the
Outer Continental Shelf, the MMS generally requires that lessees have
substantial net worth or post bonds or other acceptable assurances that such
obligations will be met. The cost of these bonds or other surety can be
substantial, and there is no assurance that bonds or other surety can be
obtained in all cases. The Company currently has two supplemental bonds in
place. Under some circumstances, the MMS may require any of the Company's
operations on federal leases to be suspended or terminated. Any such
suspension or termination could materially adversely affect the Company's
financial condition and results of operations.
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The MMS recently issued a proposal 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 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. The Company cannot predict what action the MMS will take on this
matter. The Company believes that these rules, if adopted as proposed, will
not have a material impact on its financial condition, liquidity or results of
operations.
State and Local Regulation of Drilling and Production
The Company owns interests in properties located in the state waters of the
Gulf of Mexico offshore Texas and Louisiana and occasionally may conduct
operations in the state waters offshore Mississippi. These states regulate
drilling and operating activities by requiring, among other things, drilling
permits and bonds and reports concerning operations. The laws of these states
also govern a number of environmental and conservation matters, including the
handling and disposing of waste materials, unitization and pooling of natural
gas and oil properties and establishment of maximum rates of production from
natural gas and oil wells. Some states prorate production to the market demand
for natural gas and oil.
Oil Price Controls and Transportation Rates
Sales of crude oil, condensate and natural gas liquids by the Company are
not currently regulated and are made at market prices. In a number of
instances, however, the ability to transport and sell such products are
dependent on pipelines whose rates, terms and conditions of service are
subject to FERC jurisdiction under the Interstate Commerce Act. Certain
regulations implemented by the FERC in recent years could result in an
increase in the cost of transportation service on certain petroleum products
pipelines. However, the Company does not believe that these regulations affect
it any differently than other natural gas producers, gatherers and marketers.
Environmental Regulations
The Company's operations are subject to numerous laws and regulations
governing the discharge of materials into the environment or otherwise
relating to environmental protection. Public interest in the protection of the
environment has increased dramatically in recent years. Offshore drilling in
some areas has been opposed by environmental groups and, in some areas, has
been restricted. To the extent laws are enacted or other governmental action
is taken that prohibits or restricts offshore drilling or imposes
environmental protection requirements that result in increased costs to the
natural gas and oil industry in general and the offshore drilling industry in
particular, the Company's business and prospects could be adversely affected.
The Oil Pollution Act of 1990 ("OPA") and regulations thereunder impose a
variety of regulations on "responsible parties" related to the prevention of
oil spills and liability for damages resulting from such spills in United
States waters. A "responsible party" includes the owner or operator of a
facility or vessel, or the lessee or permittee of the area in which an
offshore facility is located. The OPA assigns liability to each responsible
party for oil removal costs and a variety of public and private damages. While
liability limits apply in some circumstances, a party cannot take advantage of
liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation. If the party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply. Even if
applicable, the liability limits for offshore facilities require the
responsible party to pay all removal costs, plus up to $75.0 million in other
damages. Few defenses exist to the liability imposed by the OPA.
The OPA also requires a responsible party to submit proof of its financial
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 OPA requires parties responsible for offshore
facilities to provide financial assurance in the amount of $35.0 million to
cover potential OPA liabilities. This amount can be increased up to $150.0
million if a study by the MMS indicates that an amount higher than $35.0
million should
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be required. On August 11, 1998, the MMS adopted a rule implementing these OPA
financial responsibility requirements. The Company is in compliance with this
new rule.
The OPA also imposes other requirements, such as the preparation of an oil
spill contingency plan. The Company has such a plan in place. The Company is
also regulated by the Clean Water Act and similar state laws. The Clean Water
Act prohibits any discharge into waters of the United States except in strict
conformance with permits issued by federal and state agencies. Failure to
comply with the ongoing requirements of these laws or inadequate cooperation
during a spill event may subject a responsible party to civil or criminal
enforcement actions.
In addition, the OCSLA authorizes regulations relating to safety and
environmental protection applicable to lessees and permittees operating on the
Outer Continental Shelf. Specific design and operational standards may apply
to Outer Continental Shelf vessels, rigs, platforms, vehicles and structures.
Violations of lease conditions or regulations issued pursuant to the OCSLA can
result in substantial civil and criminal penalties, as well as potential court
injunctions curtailing operations and the cancellation of leases. Such
enforcement liabilities can result from either governmental or private
prosecution.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, imposes liability, without
regard to fault or the legality of the original conduct, on some classes of
persons that are considered to have contributed to the release of a "hazardous
substance" into the environment. These persons include the owner or operator
of the disposal site or sites where the release occurred and companies that
disposed or arranged for the disposal of the hazardous substances found at the
site. Persons who are or were responsible for releases of hazardous substances
under CERCLA may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources, and it is not uncommon for
neighboring landowners and other third parties to file claims for personal
injury and property damage allegedly caused by the hazardous substances
released into the environment.
The Company's operations are also subject to regulation of air emissions
under the Clean Air Act, comparable state and local requirements and the
OCSLA. Implementation of these laws could lead to the gradual imposition of
new air pollution control requirements on the Company's operations. Therefore,
the Company may incur capital expenditures over the next several years to
upgrade its air pollution control equipment. The Company does not believe that
its operations would be materially affected by any such requirements, nor does
the Company expect such requirements to be any more burdensome to it than to
other companies of its size involved in natural gas and oil exploration and
production activities.
In addition, legislation has been proposed in Congress from time to time
that would reclassify some natural gas and oil exploration and production
wastes as "hazardous wastes," which would make the reclassified wastes subject
to much more stringent handling, disposal and clean-up requirements. If
Congress were to enact this legislation, it could increase the Company's
operating costs, as well as those of the natural gas and oil industry in
general. Initiatives to further regulate the disposal of natural gas and oil
wastes are also pending in some states, and these various initiatives could
have a similar impact on the Company.
Management believes that the Company is in substantial compliance with
current applicable environmental laws and regulations and that continued
compliance with existing requirements will not have a material adverse impact
on the Company.
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
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toxic gases. If any of these events occur, the Company could incur substantial
losses as a result of injury or loss of life, severe damage to and destruction
of property, natural resources and equipment, pollution and other
environmental damage, clean-up responsibilities, regulatory investigation and
penalties, suspension of the Company's operations and repairs to resume
operations. If the Company experiences any of these problems, it could affect
well bores, platforms, gathering systems and processing facilities, which
could adversely affect its ability to conduct operations.
Offshore operations are also subject to a variety of operating risks
peculiar to the marine environment, such as capsizing, collisions, and damage
or loss from hurricanes or other adverse weather conditions. These conditions
can cause substantial damage to facilities and interrupt production. As a
result, the Company could incur substantial liabilities that could reduce or
eliminate the funds available for exploration, development or leasehold
acquisitions, or result in loss of properties.
In accordance with industry practice, the Company maintains insurance
against some, but not all, potential risks and losses. The Company does not
carry business interruption insurance. For some risks, the Company may not
obtain insurance if it believes the cost of available insurance is excessive
relative to the risks presented. In addition, pollution and environmental
risks generally are not fully insurable. If a significant accident or other
event occurs and is not fully covered by insurance, it could adversely affect
the Company.
Employees
At December 31, 1999, the Company had 35 full-time employees. The Company
believes that its relationships with the employees are satisfactory. None of
the Company's employees is covered by a collective bargaining agreement. From
time to time, the Company uses the services of independent consultants and
contractors to perform various professional services, particularly in the
areas of construction, design, well-site surveillance, permitting and
environmental assessment. Independent contractors usually perform field and
on-site production operation services for the Company, including pumping,
maintenance, dispatching, inspection and testing.
Risk Factors
In addition to the other information set forth elsewhere in this Form 10-K,
you should carefully consider the following factors when evaluating Spinnaker.
Because the Company has a limited operating history and has incurred losses
from operations since its formation, future operating results are difficult to
forecast. The Company's failure to achieve or sustain profitability in the
future could adversely affect the market price of the Company's Common Stock.
The Company was formed in December 1996 and, as a result, has a limited
operating history. The Company's limited operating history and the
unpredictable results of its exploration and development strategy make it
difficult to forecast operating results. In addition, the Company has incurred
losses from operations each year since its formation. Its failure to achieve
or sustain profitability in the future could adversely affect the market price
of the Company's Common Stock.
You should consider the limited historical financial and operating
information available on which to base an evaluation of the Company's
performance. In addition, because the Company is less experienced and has
fewer financial resources than many companies in the industry, it may be at a
disadvantage in bidding for exploratory prospects and producing natural gas
and oil properties. For a description of the competition the Company faces in
its business, see "Item 1. Business--Competition."
The Company incurred net losses of $328,000 in 1996, $2.2 million in 1997,
$6.9 million in 1998 and $1.3 million in 1999. The Company's participation in
increasingly larger numbers of prospects has required and will continue to
require substantial capital expenditures. The Company cannot assure you that
it will achieve or sustain profitability or positive cash flows from operating
activities in the future.
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Exploration is a high-risk activity, and the 3-D seismic data and other
advanced technologies the Company uses cannot eliminate exploration risk and
require experienced technical personnel whom the Company may be unable to
attract or retain.
The Company's future success will depend on the success of its exploratory
drilling program. Exploration activities involve numerous risks, including the
risk that no commercially productive natural gas or oil reservoirs will be
discovered. In addition, the Company often is uncertain as to the future cost
or timing of drilling, completing and producing wells. Furthermore, drilling
operations may be curtailed, delayed or canceled as a result of the additional
exploration time and expense associated with a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, adverse weather conditions, compliance with
governmental requirements and shortages or delays in the availability of
drilling rigs 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 Company could
incur losses as a result of these expenditures. Poor results from exploration
activities could affect future cash flows and results of operations materially
and adversely.
The Company's exploratory drilling success will depend, in part, on its
ability to attract and retain experienced explorationists and other
professional personnel. Competition for explorationists and engineers with
experience in the Gulf of Mexico is extremely intense. If the Company cannot
retain its current personnel or attract additional experienced personnel, its
ability to compete in the Gulf of Mexico could be adversely affected.
If PGS terminates the Data Agreement or chooses not to acquire any further
data, the Company's ability to find additional reserves could be materially
impaired.
The Company's success depends heavily on its access to 3-D seismic data, and
its primary source for 3-D seismic data is the Data Agreement. If PGS
terminates the Data Agreement, the Company would lose substantially all of its
current access to 3-D seismic data which loss would have a material adverse
effect on its ability to find additional reserves.
PGS may terminate the Data Agreement on several grounds, including if a PGS
competitor acquires control of Spinnaker or if the Company breaches the Data
Agreement subject to specified exceptions. For a description of these
exceptions, "Item 1. Business--PGS Data Agreement--Termination Events."
Although the Company has license rights to approximately 5,300 blocks of 3-D
seismic data in the Gulf of Mexico under the Data Agreement, it anticipates
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 the Company might not receive significant additional data from PGS. The
Data 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 the Data 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
the Company. 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 the Data Agreement, then the Company 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 the Company is not entitled or for which its rights are limited. The
Company's 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.
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Natural gas and oil prices fluctuate widely, and low prices could have a
material adverse impact on the Company's business.
The Company's revenues, profitability and future growth depend substantially
on prevailing prices for natural gas and oil. Prices also affect the amount of
cash flow available for capital expenditures and the Company's ability to
borrow and raise additional capital. The amount the Company can borrow under
the Amended Credit Agreement is subject to periodic re-determination based in
part on changing expectations of future prices. Lower prices may also reduce
the amount of natural gas and oil that the Company can economically produce.
Prices for natural gas and oil fluctuate widely. For example, natural gas
and oil prices declined significantly in 1998 and, for an extended period of
time, remained substantially below prices obtained in previous years. Among
the factors that can cause this fluctuation are:
. the level of consumer product demand;
. weather conditions;
. domestic and foreign governmental regulations;
. the price and availability of alternative fuels;
. political conditions in natural gas and oil producing regions;
. the domestic and foreign supply of natural gas and oil;
. the price of foreign imports; and
. overall economic conditions.
Reserve estimates depend on many assumptions that may turn out to be
inaccurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will materially affect the quantities and net present value of the
Company's reserves.
The process of estimating natural gas and oil reserves is complex. It
requires interpretations of available technical data and various assumptions,
including assumptions relating to economic factors. Any significant
inaccuracies in these interpretations or assumptions could materially affect
the estimated quantities and net present value of reserves. See "Item 2.
Properties--Natural Gas and Oil Reserves."
In order to prepare these estimates, the Company must project production
rates and timing of development expenditures. The Company must also analyze
available geological, geophysical, production and engineering data, and the
extent, quality and reliability of this data can vary. The process also
requires economic assumptions such as natural gas and oil prices, drilling and
operating expenses, capital expenditures, taxes and availability of funds.
Therefore, estimates of natural gas and oil reserves are inherently imprecise.
Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves most likely will vary from the Company's
estimates. Any significant variance could materially affect the estimated
quantities and net present value of reserves. In addition, the Company may
adjust estimates of proved reserves to reflect production history, results of
exploration and development, prevailing natural gas and oil prices and other
factors, many of which are beyond the Company's control. At December 31, 1999,
77% of the Company's proved reserves were either proved undeveloped or proved
non-producing. Moreover, the producing wells included in the reserve report
had produced for a relatively short period of time as of December 31, 1999.
Because most of the reserve estimates are not based on a lengthy production
history and are calculated using volumetric analysis, these estimates are less
reliable than estimates based on a lengthy production history.
You should not assume that the present value of future net cash flows from
the Company's proved reserves is the current market value of its estimated
natural gas and oil reserves. In accordance with Commission
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requirements, the Company generally bases the estimated discounted future net
cash flows from its proved reserves on prices and costs on the date of the
estimate. Actual future prices and costs may differ materially from those used
in the net present value estimate.
A significant part of the value of the Company's production and reserves is
concentrated in a small number of offshore properties. Because of this
concentration, any production problems or inaccuracies in reserve estimates
related to those properties are more likely to adversely impact the Company's
business.
During 1999, over 77% of the Company's production came from four properties
in the Gulf of Mexico. If mechanical problems, storms or other events
curtailed a substantial portion of this production, the Company's cash flow
would be adversely affected. In addition, at December 31, 1999, the Company's
proved reserves were located on 22 discoveries in the Gulf of Mexico, with
approximately 50% of the proved reserves attributable to four of these
discoveries. If the actual reserves associated with any one of these four
properties were less than the estimated reserves, the Company's results of
operations and financial condition could be adversely affected.
The Company is vulnerable to operational, regulatory and other risks
associated with the Gulf of Mexico because it currently explores and produces
exclusively in that area.
The Company's operations and revenues are impacted acutely by conditions in
the Gulf of Mexico because it currently explores and produces exclusively in
that area. This concentration of activity makes the Company more vulnerable
than many of its competitors to the risks associated with the Gulf of Mexico,
including delays and increased costs relating to adverse weather conditions,
increased oilfield service costs, difficulties securing oilfield services and
compliance with environmental and other laws and regulations.
Relatively short production periods for Gulf of Mexico properties subject the
Company to higher reserve replacement needs and may impair its ability to
reduce production during periods of low natural gas and oil prices.
Production of reserves from reservoirs in the Gulf of Mexico generally
declines more rapidly than from reservoirs in many other producing regions of
the world. This results in recovery of a relatively higher percentage of
reserves from properties in the Gulf of Mexico during the initial few years of
production, and as a result, reserve replacement needs from new prospects are
greater.
Also, revenues and return on capital will depend significantly on prices
prevailing during these relatively short production periods. The Company's
potential need to generate revenues to fund ongoing capital commitments or
reduce indebtedness may limit its ability to slow or shut-in production from
producing wells during periods of low prices for natural gas and oil.
The failure to replace reserves would adversely affect production and cash
flows.
The Company's future natural gas and oil production depends on its success
in finding or acquiring additional reserves. If the Company fails to replace
reserves, its level of production and cash flows would be adversely impacted.
In general, production from natural gas and oil properties declines as
reserves are depleted, with the rate of decline depending on reservoir
characteristics. The Company's total proved reserves decline as reserves are
produced unless the Company conducts other successful exploration and
development activities or acquires properties containing proved reserves, or
both. The Company's ability to make the necessary capital investment to
maintain or expand its asset base of natural gas and oil reserves would be
impaired to the extent cash flow from operations is reduced and external
sources of capital become limited or unavailable. The Company may not be
successful in exploring for, developing or acquiring additional reserves. If
the Company is not successful, its future production and revenues will be
adversely affected.
The natural gas and oil business involves many operating risks that can cause
substantial losses.
The natural gas and oil business involves a variety of operating risks,
including fires, explosions, blow-outs and surface cratering, uncontrollable
flows of underground natural gas, oil and formation water, natural disasters,
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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, the Company could incur substantial
losses as a result of injury or loss of life, severe damage to and destruction
of property, natural resources and equipment, pollution and other
environmental damage, clean-up responsibilities, regulatory investigation and
penalties, suspension of the Company's operations and repairs to resume
operations. If the Company experiences any of these problems, it could affect
well bores, platforms, gathering systems and processing facilities, which
could adversely affect its ability to conduct operations.
Offshore operations are also subject to a variety of operating risks
peculiar to the marine environment, such as capsizing, collisions and damage
or loss from hurricanes or other adverse weather conditions. These conditions
can cause substantial damage to facilities and interrupt production. As a
result, the Company could incur substantial liabilities that could reduce or
eliminate the funds available for exploration, development or leasehold
acquisitions, or result in loss of properties.
The Company does not carry business interruption insurance. For some risks,
the Company may not obtain insurance if it believes the cost of available
insurance is excessive relative to the risks presented. In addition, pollution
and environmental risks generally are not fully insurable. If a significant
accident or other event occurs and is not fully covered by insurance, it could
adversely affect the Company's operations.
Exploration for natural gas and oil in the deep waters of the Gulf of Mexico
involves greater operational and financial risks than exploration in shallower
waters, and expansion into the deep water could result in substantial losses.
As part of its strategy, the Company intends to explore for natural gas and
oil in the deep waters of the Gulf of Mexico where operations are more
difficult and costly than in shallower waters. For example, near surface
geologic conditions in the deep waters create unique operational challenges.
Deep water drilling and operations also require the application of relatively
untested technologies that involve a higher risk of mechanical failure and
generally have significantly higher drilling and operating costs. Furthermore,
the deep waters of the Gulf of Mexico lack the physical and oilfield service
infrastructure present in the shallower waters of the Gulf of Mexico. As a
result, deep water operations may require a significant amount of time between
a discovery and the time that the Company can market the natural gas or oil,
increasing the risk involved with these operations.
The Company cannot control the activities on properties it does not operate.
Other companies operate most of the properties in which the Company has an
interest. As a result, the Company has a limited ability to exercise influence
over operations for these properties or their associated costs. The Company's
dependence on the operator and other working interest owners for these
projects and its limited ability to influence operations and associated costs
could materially and adversely affect the realization of its targeted returns
on capital in drilling or acquisition activities. The success and timing of
drilling and development activities on properties operated by others therefore
depend upon a number of factors that are outside of the Company's control,
including timing and amount of capital expenditures, the operator's expertise
and financial resources, approval of other participants in drilling wells and
selection of technology.
The Company's success depends on its Chief Executive Officer and other key
personnel, the loss of whom could disrupt business operations.
The Company depends to a large extent on the efforts and continued
employment of the Company's President and Chief Executive Officer, Roger L.
Jarvis, and other key personnel. If Mr. Jarvis or these other key personnel
resign or become unable to continue in their present roles and if they are not
adequately replaced, the Company's business operations could be adversely
affected.
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The Company may have difficulty financing its planned growth.
The Company has experienced and expects to continue to experience
substantial capital expenditure and working capital needs, particularly as a
result of its drilling program. In the future, the Company will require
additional financing, in addition to cash generated from its operations, to
fund its planned growth. The Company cannot be certain that additional
financing will be available on acceptable terms or at all. In the event
additional capital resources are unavailable, the Company may curtail its
drilling, development and other activities or be forced to sell some of its
assets on an untimely or unfavorable basis.
Competition in the industry is intense, and the Company is smaller and has a
more limited operating history than most of its competitors in the Gulf of
Mexico.
The Company competes with major and independent natural gas and oil
companies for property acquisitions. It also competes for the equipment and
labor required to operate and develop these properties. Most of the
competitors have substantially greater financial and other resources than the
Company. In addition, larger competitors may be able to absorb the burden of
any changes in federal, state and local laws and regulations more easily than
the Company can, which would adversely affect its competitive position. These
competitors may be able to pay more for exploratory prospects and productive
natural gas and oil properties and may be able to define, evaluate, bid for
and purchase a greater number of properties and prospects than the Company
can. The Company's ability to explore for natural gas and oil prospects and to
acquire additional properties in the future will depend on its ability to
conduct operations, to evaluate and select suitable properties and to
consummate transactions in this highly competitive environment. In addition,
most of the competitors have been operating in the Gulf of Mexico for a much
longer time than the Company has and have demonstrated the ability to operate
through industry cycles.
Competitors may use superior technology which the Company may be unable to
afford or which would require costly investment in order to compete.
The industry is subject to rapid and significant advancements in technology,
including the introduction of new products and services using new
technologies. As the competitors use or develop new technologies, the Company
may be placed at a competitive disadvantage, and competitive pressures may
force it to implement new technologies at a substantial cost. In addition, the
competitors may have greater financial, technical and personnel resources that
allow them to enjoy technological advantages and may in the future allow them
to implement new technologies before the Company can. The Company cannot be
certain that it will be able to implement technologies on a timely basis or at
a cost that is acceptable to it. One or more of the technologies that the
Company currently uses or that it may implement in the future may become
obsolete, and it may be adversely affected. For example, marine seismic
acquisition technology has been characterized by rapid technological
advancements in recent years and further significant technological
developments could substantially impair the 3-D seismic data's value.
One customer currently purchases all of the Company's natural gas production.
As a result, if this customer defaults on its payment obligations, near-term
earnings and cash flows would be adversely affected.
Currently, Columbia purchases all of the Company's natural gas production at
current market prices. The terms of the arrangement with Columbia require
Columbia to pay the Company within approximately 30 to 60 days after it
delivers the production to Columbia. As a result, if Columbia were to default
on its payment obligations to the Company, its near-term earnings and cash
flows would be adversely affected.
The Company is subject to complex laws and regulations, including
environmental regulations that can adversely affect the cost, manner or
feasibility of doing business.
Exploration for and development, production and sale of natural gas and oil
in the U.S. and especially in the Gulf of Mexico are subject to extensive
federal, state and local laws and regulations, including environmental
17
<PAGE>
laws and regulations. The Company may be required to make large expenditures
to comply with environmental and other governmental regulations. Matters
subject to regulation include discharge permits for drilling operations,
drilling bonds, reports concerning operations and taxation.
Under these laws and regulations, the Company could be liable for personal
injuries, property damage, oil spills, discharge of hazardous materials,
remediation and clean-up costs and other environmental damages. The Company
does not believe that full insurance coverage for all potential environmental
damages is available at a reasonable cost. Failure to comply with these laws
and regulations also may result in the suspension or termination of its
operations and subject the Company to administrative, civil and criminal
penalties. Moreover, these laws and regulations could change in ways that
substantially increase costs. For example, Congress or the MMS could decide to
limit exploratory drilling or natural gas production in some areas of the Gulf
of Mexico. Accordingly, any of these liabilities, penalties, suspensions,
terminations or regulatory changes could materially and adversely affect the
Company's financial condition and results of operations.
Hedging production may result in losses.
To reduce the exposure to fluctuations in the prices of natural gas and oil,
the Company has entered into hedging arrangements. Hedging arrangements expose
the Company to risk of financial loss in some circumstances, including
situations when production is less than expected, the other party to the
hedging contract defaults on its contract obligations or there is a change in
the expected differential between the underlying price in the hedging
agreement and actual prices received. In addition, these hedging arrangements
may limit the benefit the Company would receive from increases in the prices
for natural gas and oil. Furthermore, if the Company chooses not to engage in
hedging arrangements in the future, it may be more adversely affected by
changes in natural gas and oil prices than competitors who engage in hedging
arrangements.
PGS, Warburg and 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.
Upon completion of the initial public offering, Warburg, PGS, and the
Company's executive officers beneficially owned approximately 63% of the
outstanding shares of Common Stock. As a result, these stockholders are in a
position to significantly influence or control the outcome of matters
requiring a stockholder vote, including the election of directors, the
adoption of an amendment to the certificate of incorporation or bylaws and the
approval of mergers and other significant corporate transactions. In addition,
representatives of PGS and Warburg constitute a majority of the board of
directors. Their control of the Company may have the effect of delaying or
preventing a change of control of Spinnaker and may adversely affect the
voting and other rights of other stockholders.
Furthermore, conflicts of interest could arise in the future between the
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 the Data
Agreement, 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 other stockholders.
Substantially all of the Company's outstanding shares may be sold into the
market in the near future. This could cause the market price of the Common
Stock to drop significantly, even if the Company's business is doing well.
The market price of the Common Stock could drop due to sales of a large
number of shares of the Common Stock in the market or the perception that such
sales could occur. This could make it more difficult to raise funds through
future offerings of Common Stock.
On completion of the initial public offering, the Company had 20,420,384
shares of Common Stock outstanding, including 8,000,000 shares sold in the
initial public offering. Of the remaining shares, 12,377,098
18
<PAGE>
shares will become available for resale in the public market after a period of
180 days after September 28, 1999, with some exceptions. All shares of Common
Stock outstanding prior to the initial public offering may be sold following
the 180-day period either in transactions registered under the Securities Act
of 1933 or exempt from registration. In addition, current stockholders
collectively have rights that provide for the registration of the resale of
their shares of Common Stock at the Company's expense.
Options to purchase approximately 3,382,974 shares of Common Stock were
outstanding at December 31, 1999. The Company filed a registration statement
covering the sale of 2,673,242 shares of Common Stock issuable upon exercise
of the options and intends to file a registration statement covering the sale
of the remaining shares of Common Stock issuable upon exercise of those
options. The shares received upon exercise generally will be freely
transferable.
The certificate of incorporation and bylaws contain provisions that could
discourage an acquisition or change of control of the Company.
The certificate of incorporation authorizes the board of directors to issue
Preferred Stock without stockholder approval. If the board of directors elects
to issue Preferred Stock, it could be more difficult for a third party to
acquire control of the Company, even if that change of control might be
beneficial to stockholders. In addition, provisions of the certificate of
incorporation and bylaws, such as no stockholder action by written consent and
limitations on stockholder proposals at meetings of stockholders, could also
make it more difficult for a third party to acquire control of the Company.
19
<PAGE>
GLOSSARY OF NATURAL GAS AND OIL TERMS
The following is a description of the meanings of some of the natural gas
and oil industry terms used in this annual report.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this
annual report in reference to crude oil or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Block. A block depicted on the Outer Continental Shelf Leasing and Official
Protraction Diagrams issued by the U.S. Mineral Management Service or a
similar depiction on official protraction or similar diagrams issued by a
state bordering on the Gulf of Mexico.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production of
natural gas or oil, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a
primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable to
productive wells or wells capable of production.
Development well. A well drilled into a proved natural gas or oil reservoir
to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce natural gas or oil
reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of natural gas or oil in another reservoir
or to extend a known reservoir.
Farm-in or farm-out. An agreement under which the owner of a working
interest in a natural gas and oil lease assigns the working interest or a
portion of the working interest to another party who desires to drill on the
leased acreage. Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor usually retains a
royalty or reversionary interest in the lease. The interest received by an
assignee is a "farm-in" while the interest transferred by the assignor is a
"farm-out."
Field. An area consisting of either a single reservoir or multiple
reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in
which a working interest is owned.
Lead. A specific geographic area which, based on supporting geological,
geophysical or other data, is deemed to have potential for the discovery of
commercial hydrocarbons.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
20
<PAGE>
Mcf. Thousand cubic feet of natural gas.
Mcfe. Thousand cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MMBls. Million barrels of crude oil or other liquid hydrocarbons.
MMBtu. Million British Thermal Units.
MMcf. Million cubic feet of natural gas.
MMcfe. Million cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Net acres or net wells. The sum of the fractional working interest owned in
gross acres or wells, as the case may be.
Net feet of pay. The true vertical thickness of reservoir rock estimated to
both contain hydrocarbons and be capable of contributing to producing rates.
Productive well. A well that is found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological,
geophysical or other data and also preliminary economic analysis using
reasonably anticipated prices and costs, is deemed to have potential for the
discovery of commercial hydrocarbons.
Proved developed non-producing reserves. Proved developed reserves expected
to be recovered from zones behind casing in existing wells.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
wells and capable of production to market.
Proved developed reserves. Proved reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids that geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Reservoir. A porous and permeable underground formation containing a natural
accumulation of producible natural gas and/or oil that is confined by
impermeable rock or water barriers and is separate from other reservoirs.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of natural gas and oil regardless of whether such acreage contains proved
reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and receive a
share of production.
21
<PAGE>
Item 2. Properties
Since inception, the Company has concentrated on the exploration for natural
gas and oil in the Gulf of Mexico. As of December 31, 1999, the Company's
proved reserves were located on 22 discoveries, including one discovery in
which the Company has only a royalty interest, with production established
from 13 of these fields. Spinnaker operates 9 of the 22 wells and the
Company's working interests in these wells ranges from 12.5% to 75%. Four of
the properties account for approximately 50% of the Company's total proved
reserves and net present value of proved reserves.
The Company has license rights to approximately 7,000 blocks of mostly
contiguous, recent vintage 3-D seismic data in the Gulf of Mexico, including
approximately 5,300 blocks associated with the Data Agreement. This database
covers an area of approximately 31 million acres, which the Company believes
is one of the largest recent vintage 3-D seismic databases of any independent
exploration and production company in the Gulf of Mexico. The Company has a
leasehold interest in approximately 145 tracts located in Texas state and
federal waters.
Natural Gas and Oil Reserves
The following table presents estimated net proved natural gas and oil
reserves and the net present value of the reserves at December 31, 1999 based
on a reserve report prepared by Ryder Scott Company, L.P. The present values,
discounted at 10% per annum, of estimated future net cash flows before income
taxes shown in the table are not intended to represent the current market
value of the estimated natural gas and oil reserves Spinnaker owns. For
further information concerning the present value of future net cash flows from
these proved reserves, see Note 14 of the notes to consolidated financial
statements.
The present value of future net cash flows before income taxes as of
December 31, 1999 was determined by using year-end prices of $2.34 per MMBtu
of natural gas at Henry Hub, Louisiana and $25.60 per barrel of oil at the
Cushing NYMEX Pricing Hub.
<TABLE>
<CAPTION>
Proved Reserves
------------------------------
Developed Undeveloped Total
--------- ----------- --------
<S> <C> <C> <C>
Natural gas (MMcf).............................. 50,756 39,274 90,030
Oil and condensate (MBbls)...................... 384 2,028 2,412
Total proved reserves (MMcfe)................... 53,062 51,439 104,501
Net present value (in thousands)................ $83,204 $68,360 $151,564
</TABLE>
The process of estimating natural gas and oil reserves is complex. It
requires various assumptions, including assumptions relating to natural gas
and oil prices, drilling and operating expenses, capital expenditures, taxes
and availability of funds. The Company must project production rates and
timing of development expenditures. The Company analyzes available geological,
geophysical, production and engineering data, and the extent, quality and
reliability of this data can vary. Therefore, estimates of natural gas and oil
reserves are inherently imprecise.
Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves most likely will vary from estimates. Any
significant variance could materially affect the estimated quantities and
present value of reserves. In addition, the Company may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing natural gas and oil prices and other factors, many of
which are beyond the Company's control. At December 31, 1999, 77% of the
Company's proved reserves were either proved undeveloped or proved non-
producing. Because most of the reserve estimates are not based on a lengthy
production history and are calculated using volumetric analysis, these
estimates are less reliable than estimates based on a lengthy production
history.
22
<PAGE>
At December 31, 1999, approximately 49% of the Company's estimated
equivalent net proved reserves were undeveloped. Recovery of undeveloped
reserves generally requires significant capital expenditures and often
successful drilling operations. The reserve data assumes that the Company will
make these expenditures. Although the Company estimates its reserves and the
costs associated with developing them in accordance with industry standards,
the estimated costs may be inaccurate, development may not occur as scheduled
and results may not be as estimated.
The present value of future net cash flows does not represent the current
market value of the Company's estimated natural gas and oil reserves. In
accordance with Securities and Exchange Commission ("Commission")
requirements, the Company generally bases the estimated discounted future net
cash flows from proved reserves on prices and costs on the date of the
estimate. Actual future prices and costs may differ materially from those used
in the present value estimate.
Volumes, Prices and Operating Expenses
The following table presents information regarding the production volumes
of, average sales prices received for and average production costs associated
with Spinnaker's sales of natural gas and oil for the periods indicated:
<TABLE>
<CAPTION>
For the Year Ended
December 31,
--------------------
1997 1998 1999
------ ------ ------
<S> <C> <C> <C>
Production:
Natural gas (MMcf)..................................... 70 1,675 11,962
Oil and condensate (MBbls)............................. -- 12 180
Total (MMcfe)........................................ 70 1,747 13,044
Average sales prices per unit:
Natural gas revenues from production (per Mcf)......... $ 2.87 $ 1.89 $ 2.49
Effects of hedging activities (per Mcf)................ -- -- 0.08
------ ------ ------
Average price........................................ $ 2.87 $ 1.89 $ 2.57
Oil and condensate revenues from production (per Bbl).. $18.51 $11.61 $20.33
Effects of hedging activities (per Bbl)................ -- -- (0.57)
------ ------ ------
Average price........................................ $18.51 $11.61 $19.76
Total revenues from production (per Mcfe).............. $ 2.87 $ 1.89 $ 2.57
Effects of hedging activities (per Mcfe)............... -- -- 0.06
------ ------ ------
Total average price (per Mcfe)....................... $ 2.87 $ 1.89 $ 2.63
Expenses (per Mcfe):
Lease operating expenses (a)........................... $ 1.03 $ 0.27 $ 0.41
Depreciation, depletion and amortization--natural gas
and oil properties.................................... 0.97 1.57 1.59
</TABLE>
- --------
(a) Lease operating expenses per Mcfe in 1999 include approximately $0.13 per
Mcfe associated with workovers on two wells and well control activities on
another well.
23
<PAGE>
Development, Exploration and Acquisition Capital Expenditures
The following table presents information regarding Spinnaker's net costs
incurred in the purchase of proved and unproved properties and in exploration
and development activities:
<TABLE>
<CAPTION>
For the Year Ended
December 31,
-----------------------
1997 1998 1999
------- ------- -------
<S> <C> <C> <C>
Property acquisition costs:
Unproved....................................... $ 4,458 $15,791 $13,911
Proved......................................... -- -- --
Exploration costs (a)............................ 7,116 46,620 45,152
Development costs (b)............................ 2,422 23,067 23,614
------- ------- -------
Total costs incurred......................... $13,996 $85,478 $82,677
======= ======= =======
</TABLE>
- --------
(a) Includes seismic data acquisitions of $1.4 million, $2.5 million and $10.5
million in 1997, 1998 and 1999, respectively.
(b) Includes costs of completions, platforms, facilities and pipelines
associated with exploratory wells.
Drilling Activity
The following table shows Spinnaker's drilling activity. In the table,
"gross" refers to the total wells in which the Company has a working interest
and "net" refers to gross wells multiplied by the Company's working interest
in such wells.
<TABLE>
<CAPTION>
For the Year Ended December
31,
-----------------------------
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 8 4.6
Nonproductive............................. -- -- 6 2.3 4 1.9
--- --- --- --- --- ---
Total................................... 4 1.5 15 5.2 12 6.5
=== === === === === ===
Development Wells:
Productive................................ -- -- -- -- -- --
Nonproductive............................. -- -- -- -- -- --
--- --- --- --- --- ---
Total................................... -- -- -- -- -- --
=== === === === === ===
</TABLE>
Since December 31, 1999 and through March 1, 2000, the Company has drilled
one gross (0.8 net) productive exploratory well and four gross (1.8 net)
nonproductive exploratory wells. As of March 1, 2000, the Company was drilling
four exploratory gross (1.5 net) wells.
Productive Wells
The following table sets forth the number of productive natural gas and oil
wells in which Spinnaker owned an interest as of December 31, 1999:
<TABLE>
<CAPTION>
Total
Productive
Wells
------------
Gross Net
------ -----
<S> <C> <C>
Natural gas.................................................. 20 8.9
Oil.......................................................... 1 0.1
----- -----
Total...................................................... 21 9.0
===== =====
</TABLE>
24
<PAGE>
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 Spinnaker's developed and
undeveloped lease acreage as of December 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................ 34,687 15,733 227,302 79,680 261,989 95,413
Offshore Texas.................... 23,040 6,966 177,120 73,992 200,160 80,958
Texas State Waters................ 1,200 300 30,233 12,518 31,433 12,818
------ ------ ------- ------- ------- -------
Total........................... 58,927 22,999 434,655 166,190 493,582 189,189
====== ====== ======= ======= ======= =======
</TABLE>
The Company's lease agreements generally terminate if wells have not been
drilled on the acreage within a period of five years from the date of the
lease if located on the shelf in less than 200 meters of water or 10 years if
located in deeper waters of the Gulf of Mexico.
Item 3. Legal Proceedings
From time to time, the Company may be a party to various legal proceedings.
The Company currently is not a party to any material litigation.
Item 4. Submission of Matters to a Vote of Security Holders
The Company did not hold a meeting of stockholders or otherwise submit any
matter to a vote of stockholders in the fourth quarter of 1999.
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Spinnaker's Common Stock began trading on The Nasdaq Stock Market on
September 29, 1999 under the symbol "SPNX." The following table sets forth the
range of high and low sales prices per share of Common Stock for the calendar
quarters ended September 30, 1999 and December 31, 1999.
<TABLE>
<CAPTION>
Sales Price
-------------
High Low
------ ------
<S> <C> <C>
Third Quarter 1999 (from September 29, 1999)............... $14.75 $13.00
Fourth Quarter 1999........................................ $16.75 $12.56
</TABLE>
On March 1, 2000, the closing sale price of Spinnaker's Common Stock, as
reported by The Nasdaq Stock Market, was $16.44 per share. On that date, there
were approximately 32 holders of record of Spinnaker Common Stock.
The Company has never declared or paid any dividends on its Common Stock and
currently intends to retain future earnings, if any, for the operation and
development of its business and does not anticipate paying any dividends in
the foreseeable future. In addition, the Company's credit agreement prohibits
it from paying cash dividends on the Common Stock. Any future dividends may
also be restricted by any loan agreements the Company may enter into from time
to time.
25
<PAGE>
Item 6. Selected Financial Data
The following table sets forth certain selected historical consolidated
financial data of the Company. The amounts have been derived from audited
consolidated financial statements of the Company. This information should be
read in conjunction with "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and the Consolidated Financial Statements
and Notes thereto included elsewhere herein. The selected consolidated
financial data provided below are not necessarily indicative of the future
results of operations or financial performance of the Company.
<TABLE>
<CAPTION>
Period from
Inception
(December 20,
1996) through Year Ended December 31,
December 31, ---------------------------
1996 1997 1998 1999
------------- ------- -------- --------
(In thousands, except per share data)
<S> <C> <C> <C> <C>
Summary of Operations:
Revenues............................ $ -- $ 201 $ 3,298 $ 34,258
Expenses:
Lease operating expenses.......... -- 72 474 5,411
Depreciation, depletion and
amortization--natural gas and oil
properties....................... -- 68 2,738 20,788
Write-down of natural gas and oil
properties(1).................... -- -- 2,642 --
Depreciation and amortization--
other............................ 10 349 437 213
General and administrative........ 318 1,965 3,809 4,860
Stock appreciation rights
expense(2)....................... -- -- -- 1,651
------ ------- -------- --------
Total expenses.................. 328 2,454 10,100 32,923
------ ------- -------- --------
Income (loss) from operations....... (328) (2,253) (6,802) 1,335
Other income (expense):
Interest income................... -- 91 221 528
Interest expense.................. -- -- (516) (3,771)
Capitalized interest.............. -- -- 237 966
------ ------- -------- --------
Total other income (expense).... -- 91 (58) (2,277)
------ ------- -------- --------
Loss before income taxes............ (328) (2,162) (6,860) (942)
Income tax provision.............. -- -- -- --
------ ------- -------- --------
Loss before cumulative effect of
change in accounting principle..... (328) (2,162) (6,860) (942)
Cumulative effect of change in
accounting principle(3).......... -- -- -- (395)
------ ------- -------- --------
Net loss............................ (328) (2,162) (6,860) (1,337)
Accrual of dividends on preferred
stock(4)........................... (16) (1,326) (7,094) (7,911)
------ ------- -------- --------
Net loss available to common
stockholders....................... $ (344) $(3,488) $(13,954) $ (9,248)
====== ======= ======== ========
Basic and diluted loss per common
share(5):
Loss before cumulative effect of
change in accounting principle... $(0.09) $ (0.88) $ (3.44) $ (1.06)
Cumulative effect of change in
accounting principle(3).......... -- -- -- (0.05)
------ ------- -------- --------
Net loss per common share........... $(0.09) $ (0.88) $ (3.44) $ (1.11)
====== ======= ======== ========
Weighted average number of common
shares outstanding(4)(5):
Basic and diluted................. 3,960 3,960 4,059 8,355
====== ======= ======== ========
Summary Balance Sheet Data:
Working capital (deficit)........... $2,730 $ 4,252 $(30,641) $ 19,675
Property and equipment, net......... -- 15,452 95,607 157,397
Total assets........................ 5,241 22,358 102,769 189,553
Short-term debt..................... -- -- 19,000 --
Accrued preferred dividends
payable(4)......................... 16 1,383 8,478 --
Total stockholders' equity.......... 3,367 18,879 56,913 177,102
</TABLE>
26
<PAGE>
- --------
(1) At December 31, 1998, the Company recognized a non-cash write-down of
natural gas and oil properties in the amount of approximately $2.6 million
in connection with the ceiling limitation required by the full cost method
of accounting for natural gas and oil properties. The write-down was
primarily the result of the decline in natural gas prices experienced in
1998 and through April 9, 1999. As permitted by applicable Commission
rules, in calculating the amount of the write-down, the Company used post
year-end natural gas and oil price increases of $0.26 per MMBtu of natural
gas and $4.52 per barrel of oil from December 31, 1998 to April 9, 1999.
If the Company had used only December 31, 1998 natural gas and oil prices,
it would have recognized a total non-cash write-down of natural gas and
oil properties of approximately $13.0 million.
(2) The stock option agreements of two of the Company's officers provided that
they could elect to have the Company deliver shares equal to the
appreciation in the value of the stock over the option price in lieu of
purchasing the amount of shares under option. Based on management's
estimate of the share value of the Company, compensation expense of
approximately $1.7 million was recorded in 1999 related to the stock
appreciation rights of the stock option agreements. In July 1999, these
two officers agreed to eliminate the stock appreciation rights feature of
their stock option agreements.
(3) The cumulative effect of change in accounting principle represents the
adoption of Statement of Position No. 98-5 "Reporting on the Costs of
Start-Up Activities."
(4) In connection with the initial public offering on October 4, 1999, the
Company converted all outstanding shares of Preferred Stock into 6,061,840
shares of Common Stock and issued 1,200,384 shares of Common Stock to
certain holders of the Preferred Stock in lieu of payment of accrued cash
dividends.
(5) Spinnaker was originally formed as a limited liability company. The
Company issued common units and preferred units. In connection with its
conversion to a corporation in January 1998, the Company exchanged Common
Stock for all then outstanding common units and Preferred Stock for all
then outstanding preferred units. The Company has expressed all historical
unit data in shares.
27
<PAGE>
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
General
Spinnaker is an independent energy company engaged in the exploration,
development and production of natural gas and oil in the Gulf of Mexico. The
Company's operating results depend substantially on the success of its
exploratory drilling program and the price of natural gas and oil. Revenues,
profitability and future growth rates also substantially depend on factors
beyond the Company's 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 the Company's financial
position, its results of operations, the quantities of natural gas and oil
reserves that it can economically produce and its access to capital.
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, related
general and administrative costs and other amounts directly attributable to
these exploration activities. The Company capitalized general and
administrative costs and other amounts of $2.5 million in 1999, $2.5 million
in 1998 and $1.3 million in 1997. The Company expenses costs associated with
production and general corporate activities in the period incurred. The
Company capitalizes 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.
The Company computes the provision for depreciation, depletion and
amortization ("DD&A") of natural gas and oil properties using the unit-of-
production method of accounting based on production and estimates of proved
reserve quantities. The Company excludes unevaluated costs and related
carrying costs from the amortization base until it evaluates the properties
associated with these costs. The Company periodically assesses the unamortized
costs for possible impairments or reductions in value. An impairment to the
value may occur in the event of decreases in natural gas and oil prices,
downward adjustments to estimated proved reserves, increases in estimates of
development costs and deterioration in exploration results. If a reduction in
value has occurred, the Company increases its 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 DD&A, may not exceed a ceiling limit ("full
cost ceiling") 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 the full cost ceiling, the Company charges the excess
to "write-down of natural gas and oil properties" in the quarter in which the
excess occurs. The Company may not reverse these write-downs even if natural
gas and oil prices increase in subsequent periods. At December 31, 1998, the
Company recognized a non-cash write-down of natural gas and oil properties in
the amount of approximately $2.6 million in connection with the ceiling
limitation required by the full cost method of accounting for natural gas and
oil properties. The write-down was primarily the result of the decline in
natural gas prices experienced in 1998 and through April 9, 1999. As permitted
by applicable Commission rules, in calculating the amount of the write-down,
the Company used post year-end natural gas and oil price increases of $0.26
per MMBtu of natural gas and $4.52 per barrel of oil from December 31, 1998 to
April 9, 1999. If the Company had used only December 31, 1998 natural gas and
oil prices, it would have recognized a total non-cash write-down of natural
gas and oil properties of approximately $13.0 million.
The Company conducts substantially all of its exploration activities jointly
with others and, accordingly, recorded amounts for its natural gas and oil
properties reflect only the Company's proportionate interest in such
activities.
Effective January 1998, the Company completed the conversion of Spinnaker
from a limited liability company to a corporation and now accounts for income
taxes in accordance with Statement on Financial
28
<PAGE>
Accounting Standards No. 109, "Accounting for Income Taxes." Under Statement
No. 109, the Company 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. The Company establishes valuation
allowances when necessary to reduce deferred tax assets to the amount to be
realized.
Results of Operations
The following table sets forth certain operating information with respect to
the natural gas and oil operations of the Company:
<TABLE>
<CAPTION>
For the Year Ended
December 31,
-------------------------
1997 1998 1999
------- ------- -------
<S> <C> <C> <C>
Production:
Natural gas (MMcf)................................ 70 1,675 11,962
Oil and condensate (MBbls)........................ -- 12 180
Total (MMcfe)..................................... 70 1,747 13,044
Revenues (in thousands):
Natural gas....................................... $ 200 $ 3,158 $29,839
Oil and condensate................................ 1 140 3,668
Other............................................. -- -- 751
------- ------- -------
Total........................................... $ 201 $ 3,298 $34,258
Average sales price per unit:
Natural gas revenues from production (per Mcf).... $ 2.87 $ 1.89 $ 2.49
Effects of hedging activities (per Mcf)........... -- -- 0.08
------- ------- -------
Average price................................... $ 2.87 $ 1.89 $ 2.57
Oil and condensate revenues from production (per
Bbl)............................................. $ 18.51 $ 11.61 $ 20.33
Effects of hedging activities (per Bbl)........... -- -- (0.57)
------- ------- -------
Average price................................... $ 18.51 $ 11.61 $ 19.76
Total revenues from production (per Mcfe)......... $ 2.87 $ 1.89 $ 2.57
Effects of hedging activities (per Mcfe).......... -- -- 0.06
------- ------- -------
Total average price (per Mcfe).................. $ 2.87 $ 1.89 $ 2.63
Expenses (per Mcfe):
Lease operating expenses.......................... $ 1.03 $ 0.27 $ 0.41
Depreciation, depletion and amortization--natural
gas and oil properties........................... 0.97 1.57 1.59
Income (loss) from operations (in thousands)........ $(2,253) $(6,802) $ 1,335
</TABLE>
Year Ended December 31, 1999 Compared to the Year Ended December 31, 1998
Production increased approximately 11.3 Bcfe in 1999 compared to 1998. The
average daily production rate at the end of December 1999 was approximately
53,000 Mcfe as compared to a rate of approximately 8,000 Mcfe at the end of
December 1998.
Natural gas and oil revenues increased $31.0 million and income from
operations increased $8.1 million in 1999 compared to 1998. Natural gas
revenues increased $26.7 million and oil and condensate revenues increased
$3.5 million in 1999 compared to 1998, and net natural gas and oil hedging
income was $751,000 in 1999 as a result of hedging activities beginning during
the fourth quarter of 1999. Natural gas production volumes
29
<PAGE>
increased primarily due to seven wells which commenced production in 1999,
contributing to $25.3 million of the increase in natural gas revenues. Average
natural gas prices also increased, contributing to $1.4 million of the
increase in natural gas revenues. Oil and condensate production volumes
increased primarily due to six wells which commenced production in 1999,
contributing to $3.4 million of the increase in oil and condensate revenues.
The Brazos A-19 well commenced production on October 16, 1999 and reached a
peak production rate of 87 million cubic feet per day on November 2, 1999.
However, on November 15, 1999, during a shutdown of the well, the operator
detected a pressure buildup in the production casing. The well remains shut-in
and secure while the operator performs diagnostic work to determine the cause
of the pressure buildup and to develop plans to permanently resolve the
situation.
Lease operating expenses increased $4.9 million in 1999 compared to 1998. Of
the total increase in lease operating expenses, $4.5 million was attributable
to seven wells which commenced production in 1999, including $1.6 million of
expense related to workovers at Garden Banks 367 (Dulcimer) and High Island
235 and well control activities at Brazos A-19. The Company expensed $225,000
related to Brazos A-19 well control activities during the fourth quarter of
1999. Diagnostic and other costs to bring the well back onto production will
be capitalized.
General and administrative expenses increased $1.1 million in 1999 compared
to 1998. The increase in general and administrative expenses was primarily due
to employment-related costs associated with an increase in personnel in late
1998 and 1999. Stock appreciation rights expense in 1999 was approximately
$1.7 million compared to zero in 1998. The stock option agreements of two of
the Company's officers provided that they could elect to have the Company
deliver shares equal to the appreciation in the value of the stock over the
option price in lieu of purchasing the amount of shares under option. Based on
management's estimate of the share value of the Company, compensation expense
was recorded in 1999 related to the stock appreciation rights of the stock
option agreements. In July 1999, these two officers agreed to eliminate the
stock appreciation rights feature of their stock option agreements.
DD&A increased $18.1 million in 1999 compared to 1998, primarily due to a
substantial increase in production during 1999.
Interest income increased $307,000 in 1999 compared to 1998 primarily due to
invested initial public offering proceeds during the fourth quarter of 1999.
Interest expense, net of capitalized interest, increased $2.5 million in 1999
compared to 1998 as a result of additional borrowings under the credit
agreement during 1999.
The Company recognized a net loss of $1.3 million in 1999 compared to a net
loss of $6.9 million in 1998. After preferred dividends of $7.9 million, the
Company recognized a net loss available to common stockholders of $9.2
million, or $1.11 per share, in 1999. After preferred dividends of $7.1
million, the Company recognized a net loss available to common stockholders of
$14.0 million, or $3.44 per share, in 1998.
Year Ended December 31, 1998 Compared to the Year Ended December 31, 1997
The Company had natural gas and oil revenues of $3.3 million for the year
ended December 31, 1998 as compared to $201,000 for the year ended December
31, 1997. This increase in natural gas and oil revenues was due primarily to
production commencing in 1998 from wells located at West Cameron 522 and South
Timbalier 220. Primarily as a result of these wells, production substantially
increased to 1,747 MMcfe in 1998 from 70 MMcfe in 1997. This increased
production more than offset the decrease in the average price of the natural
gas production to $1.89 per Mcf for 1998 from $2.87 per Mcf for 1997.
Lease operating expenses were $474,000 in 1998 as compared to $72,000 in
1997. The increase in lease operating expenses was primarily the result of
operating expenses attributable to properties that commenced production during
the second half of 1997 and during 1998.
30
<PAGE>
General and administrative expenses were $3.8 million in 1998 as compared to
$2.0 million in 1997. The increase in general and administrative expenses was
primarily due to an increase of $1.2 million in expenses related to personnel
during the latter part of 1997 and during 1998 and to an increase of $0.3
million primarily related to legal and accounting services associated with the
conversion of Spinnaker from a limited liability company to a corporation.
DD&A in 1998 was $2.7 million as compared to $68,000 in 1997. Of the $2.6
million increase, $1.6 million was attributable to a substantial increase in
production and $1.0 million was due to an increase in the unit depletion rate
during 1998. Depreciation and amortization-other increased to $437,000 in 1998
from $349,000 in 1997. The increase was attributable to the purchase of
additional computer hardware and software.
The Company recognized a non-cash write-down of natural gas and oil
properties of $2.6 million due to a decline in prices during 1998 and through
April 9, 1999.
The Company recognized a net loss of $6.9 million in 1998 compared to a net
loss of $2.2 million 1997. After preferred dividends of $7.1 million, the
Company recognized a net loss available to common stockholders of $14.0
million, or $3.44 per share, in 1998. After preferred dividends of $1.3
million, the Company recognized a net loss available to common stockholders of
$3.5 million, or $0.88 per share, in 1997.
Liquidity and Capital Resources
Through September 30, 1999, the Company funded its activities primarily with
the proceeds from private placements of its equity securities and borrowings
under the credit agreement. The Company has experienced and expects to
continue to experience substantial working capital requirements, primarily due
to its active exploration and development programs. The Company plans to fund
2000 capital expenditures from working capital, cash flows from operations and
borrowings under current and future financing arrangements. In the event
additional capital resources are unavailable, the Company may curtail its
drilling, development and other activities or be forced to sell some of its
assets on an untimely or unfavorable basis.
Cash and cash equivalents increased $18.3 million to $20.5 million at
December 31, 1999 from $2.2 million at December 31, 1998. The increase
resulted from $14.9 million provided by operating activities and $88.5 million
provided by financing activities, offset in part by $85.1 million used in
investing activities.
Operating Activities
The Company intends to use cash flows from operations to fund a portion of
its future acquisition, exploration and development activities. Net cash of
$14.9 million provided by operating activities in 1999 included $21.7 million
provided by operations, primarily as a result of a substantial increase in
natural gas and oil production and an increase in natural gas and oil prices,
and $6.8 used in working capital and other activities.
Cash flow from operations will depend on the Company's ability to increase
production through its exploration and development drilling program and the
prices of natural gas and oil. The Company has made significant investments to
expand its operations in the Gulf of Mexico. These investments have resulted
in a production ramp-up that increased the Company's average daily production
to approximately 53,000 Mcfe at the end of December 1999 from approximately
8,000 Mcfe at the end of December 1998. The Company expects substantially
higher production and cash flow during 2000 as recent discoveries commence
production. However, the Company can provide no assurance that production
volumes and pricing in 2000 will achieve expectations. See "Item 1.--Risk
Factors."
The Company currently sells most of its natural gas and oil production under
price sensitive or market price contracts. To reduce exposure to fluctuations
in natural gas and oil prices, the Company enters into hedging arrangements.
However, these contracts also limit the benefits the Company would realize if
prices increase. See "Item 7A. Quantitative and Qualitative Disclosures About
Market Risk."
31
<PAGE>
The increase in Accounts Receivable was primarily due to a $3.1 million
increase in accrued oil and gas revenues resulting from a substantial increase
in production in 1999 and a $2.0 million increase in insurance claims related
to four wells.
Investing Activities
Net cash of $85.1 million used in investing activities in 1999 included net
oil and gas property capital expenditures of $84.2 million and purchases of
other property and equipment of $916,000.
The 2000 budget includes development costs that are contingent on the
success of future exploratory drilling. The Company does not anticipate that
budgeted leasehold acquisition activities will include the acquisition of
producing properties. The Company does not anticipate any significant
abandonment or dismantlement costs through 2000. The Company has capital
expenditure plans totaling approximately $115 million during 2000, primarily
for exploratory drilling costs. Actual levels of capital expenditures may vary
significantly due to many factors, including drilling results, natural gas and
oil prices, industry conditions, decisions of operators and other prospect
owners and the prices of oilfield goods and services.
Financing Activities
Net cash of $88.5 million was provided by financing activities, including
$108.7 million received from the initial public offering and $53.0 million in
borrowings, partially offset by $72.0 million of payments on borrowings and
$1.1 million of common stock issuance costs.
In September 1998, the Company entered into the $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.) ("Credit Agreement").
The Company received $19.0 million and $53.0 million from borrowings under the
Credit Agreement during 1998 and 1999, respectively. Simultaneously with the
completion of the initial public offering, the Company retired all outstanding
borrowings under the Credit Agreement, which were $72.0 million as of October
4, 1999.
On October 29, 1999, the Company amended and restated the Credit Agreement.
The $25.0 million Amended and Restated 364-Day Credit Agreement among the
Company, Bank of Montreal and Credit Suisse First Boston ("Amended Credit
Agreement") matures on October 27, 2000. The Company may borrow only up to the
borrowing base, which was $16.0 million as of October 29, 1999. On a semi-
annual basis, proved reserves are required to be evaluated to re-determine the
borrowing base. The Company has recently entered into negotiations to increase
the $16.0 million borrowing base as a result of recent proved reserve
additions.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
The Company is exposed to changes in interest rates. Changes in interest
rates affect the interest earned on the Company's cash and cash equivalents
and the interest rate paid on borrowings under the credit agreements. Under
its current policies, the Company does not use interest rate derivative
instruments to manage exposure to interest rate changes.
Commodity Price Risk
The Company's revenues, profitability and future growth depend substantially
on prevailing prices for natural gas and oil. Prices also affect the amount of
cash flow available for capital expenditures and the Company's ability to
borrow and raise additional capital. The amount the Company can borrow under
the Amended Credit Agreement is subject to periodic re-determination based in
part on changing expectations of future prices. Lower prices may also reduce
the amount of natural gas and oil that the Company can economically produce.
The Company currently sells most of its natural gas and oil production under
price sensitive or market
32
<PAGE>
price contracts. To reduce exposure to fluctuations in natural gas and oil
prices, the Company entered into hedging arrangements beginning in the fourth
quarter of 1999. However, these contracts also limit the benefits the Company
would realize if prices increase. The Company has entered into the following
collar arrangements for 2000. One MMBtu approximates one Mcf of gas.
<TABLE>
<CAPTION>
Gas Collars Oil Collars
------------------------------- ---------------------------
Average Average Average Average Average
Daily Average NYMEX Daily NYMEX NYMEX
Volume NYMEX Floor Ceiling Volume Floor Ceiling
Time Period (MMBtu) Price/MMBtu Price/MMBtu (Bbl) Price/Bbl Price/Bbl
----------- ------- ----------- ----------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
First Quarter 2000...... 25,000 $2.86 $3.06 534 $19.63 $21.81
Second Quarter 2000..... 25,000 2.40 2.60 600 19.37 21.78
Third Quarter 2000...... 25,000 2.36 2.57 600 18.61 21.03
October 2000............ -- -- -- 600 21.22 25.22
</TABLE>
The average daily production rates at the end of December 1999 were
approximately 47,000 Mcf of natural gas and approximately 1,000 barrels of oil
and condensate. These transactions are designated as hedges and accounted for
on the accrual basis with realized gains and losses recognized in revenues
when the related production occurs. The Company recognized $751,000 of net
hedging income during 1999. The estimated fair value of the open collar
arrangements in place at December 31, 1999 was an unrealized gain of
approximately $968,000. Using natural gas and oil prices as of February 29,
2000, the fair value of the open collar arrangements was an unrealized loss of
approximately $1.0 million.
Item 8. Financial Statements and Supplementary Data
The consolidated financial statements and supplementary data of the Company
appear on pages 36 through 59 hereof and are incorporated by reference into
this Item 8. Selected quarterly financial data is set forth in Note 13 of
Notes to Consolidated Financial Statements, which is incorporated herein by
reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
There have been no changes in or disagreements with the Company's
accountants regarding accounting principles or practices or financial
statement disclosures.
PART III
The Company's Proxy Statement for its 2000 Annual Meeting of Stockholders,
which, when filed pursuant to Regulation 14A under the Securities Exchange Act
of 1934, will be incorporated by reference in this Annual Report on Form 10-K
pursuant to General Instruction G(3) of Form 10-K and will provide the
information required under Part III (Items 10, 11, 12 and 13).
33
<PAGE>
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) Financial Statements
(1) and (2) Financial Statements and Schedules
See "Index to Consolidated Financial Statements and Schedules" on
page 36.
(3) Exhibits
See "Exhibit Index" on page 60.
The management contracts and compensatory plans or arrangements required to
be filed as exhibits to this report are as follows:
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
10.2* --Amended and Restated 1998 Spinnaker Stock Option Plan.
10.6* --Employment Agreement between Spinnaker and Roger L. Jarvis dated
December 20, 1996, as amended.
10.7* --Employment Agreement between Spinnaker and James M. Alexander dated
December 20, 1996, as amended.
10.8* --Employment Agreement between Spinnaker and William D. Hubbard dated
February 24, 1997, as amended.
10.9* --Employment Agreement between Spinnaker and Kelly M. Barnes dated
February 24, 1997, as amended.
10.10* --1999 Spinnaker Stock Incentive Plan.
10.11* --1999 Spinnaker Employee Stock Purchase Plan.
</TABLE>
- --------
* Incorporated herein by reference to the exhibit filed with the Company's
Registration Statement on Form S-1 (Commission File No. 333-83093).
(b) Reports on Form 8-K
None.
34
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
March 1, 2000 SPINNAKER EXPLORATION COMPANY
/s/ Roger L. Jarvis
By:__________________________________
Roger L. Jarvis
Chairman, President,
Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant in the capacities and on the dates indicated.
<TABLE>
<CAPTION>
Signature Title Date
--------- ----- ----
<S> <C> <C>
/s/ Roger L. Jarvis Chairman, President, Chief March 1, 2000
______________________________________ Executive Officer and
Roger L. Jarvis Director
/s/ James M. Alexander Vice President, Chief March 1, 2000
______________________________________ Financial Officer and
James M. Alexander Secretary (Principal
Financial Officer)
/s/ Jeffrey C. Zaruba Treasurer March 1, 2000
______________________________________ (Principal Accounting
Jeffrey C. Zaruba Officer)
/s/ Bjarte Bruheim Director March 1, 2000
______________________________________
Bjarte Bruheim
/s/ Sheldon R. Erikson Director March 1, 2000
______________________________________
Sheldon R. Erikson
/s/ Jeffrey A. Harris Director March 1, 2000
______________________________________
Jeffrey A. Harris
/s/ Michael E. McMahon Director March 1, 2000
______________________________________
Michael E. McMahon
/s/ Reidar Michaelsen Director March 1, 2000
______________________________________
Reidar Michaelsen
/s/ Howard H. Newman Director March 1, 2000
______________________________________
Howard H. Newman
</TABLE>
35
<PAGE>
SPINNAKER EXPLORATION COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
Report of Independent Public Accountants................................. 37
Consolidated Balance Sheets as of December 31, 1998 and 1999............. 38
Consolidated Statements of Operations for each of the three years in the
period ended December 31, 1999.......................................... 39
Consolidated Statements of Equity for each of the three years in the
period ended December 31, 1999.......................................... 40
Consolidated Statements of Cash Flows for each of the three years in the
period ended December 31, 1999.......................................... 41
Notes to Consolidated Financial Statements............................... 42
</TABLE>
All schedules for which provision is made in the applicable rules and
regulations of the Securities and Exchange Commission have been omitted as the
schedules are not required under the related instructions, are not applicable
or the information required thereby is set forth in the Consolidated Financial
Statements or the Notes thereto.
36
<PAGE>
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Stockholders of
Spinnaker Exploration Company:
We have audited the accompanying consolidated balance sheets of Spinnaker
Exploration Company (a Delaware corporation), as of December 31, 1998 and
1999, and the related consolidated statements of operations, equity and cash
flows for each of the three years in the period ended December 31, 1999. These
financial statements are the responsibility of Spinnaker Exploration Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on
a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used
and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Spinnaker
Exploration Company as of December 31, 1998 and 1999, and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1999, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 23, 2000
37
<PAGE>
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
<TABLE>
<CAPTION>
As of
December 31,
------------------
1998 1999
ASSETS -------- --------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................ $ 2,141 $ 20,452
Accounts receivable...................................... 3,821 10,795
Other.................................................... 775 879
-------- --------
Total current assets................................... 6,737 32,126
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties....................................... 71,091 141,455
Unproved properties and properties under development,
not being amortized.................................... 28,383 40,696
Other.................................................... 2,798 3,714
-------- --------
102,272 185,865
Less--Accumulated depreciation, depletion and
amortization............................................ (6,665) (28,468)
-------- --------
Total property and equipment........................... 95,607 157,397
OTHER ASSETS:
Organization costs and other, net........................ 425 30
-------- --------
Total assets........................................... $102,769 $189,553
======== ========
<CAPTION>
LIABILITIES AND EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts payable......................................... $ 6,471 $ 4,509
Accrued liabilities...................................... 11,907 7,942
Short-term debt.......................................... 19,000 --
-------- --------
Total current liabilities.............................. 37,378 12,451
ACCRUED PREFERRED DIVIDENDS PAYABLE........................ 8,478 --
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares
authorized; 3,030,920 and 0 shares issued and
outstanding at December 31, 1998 and 1999,
respectively............................................ 30 --
Common stock, $0.01 par value; 50,000,000 shares
authorized; 4,082,200 shares issued and outstanding at
December 31, 1998 and 20,426,192 shares issued and
20,404,336 shares outstanding at December 31, 1999...... 20 204
Additional paid-in capital............................... 74,649 203,987
Accumulated deficit...................................... (17,786) (27,034)
Less: Treasury stock, at cost, 0 and 21,856 shares at
December 31, 1998 and 1999, respectively........... -- (55)
-------- --------
Total equity........................................... 56,913 177,102
-------- --------
Total liabilities and equity........................... $102,769 $189,553
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
38
<PAGE>
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per unit/share data)
<TABLE>
<CAPTION>
For the Year Ended
December 31,
--------------------------
1997 1998 1999
------- -------- -------
<S> <C> <C> <C>
REVENUES........................................... $ 201 $ 3,298 $34,258
EXPENSES:
Lease operating expenses......................... 72 474 5,411
Depreciation, depletion and amortization--natural
gas and oil properties.......................... 68 2,738 20,788
Write-down of natural gas and oil properties..... -- 2,642 --
Depreciation and amortization--other............. 349 437 213
General and administrative....................... 1,965 3,809 4,860
Stock appreciation rights expense................ -- -- 1,651
------- -------- -------
Total expenses................................. 2,454 10,100 32,923
------- -------- -------
INCOME (LOSS) FROM OPERATIONS...................... (2,253) (6,802) 1,335
OTHER INCOME (EXPENSE):
Interest income.................................. 91 221 528
Interest expense................................. -- (516) (3,771)
Capitalized interest............................. -- 237 966
------- -------- -------
Total other income (expense)................... 91 (58) (2,277)
------- -------- -------
LOSS BEFORE INCOME TAXES........................... (2,162) (6,860) (942)
Income tax provision............................. -- -- --
------- -------- -------
LOSS BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE.............................. (2,162) (6,860) (942)
Cumulative effect of change in accounting
principle (Note 2).............................. -- -- (395)
------- -------- -------
NET LOSS........................................... (2,162) (6,860) (1,337)
ACCRUAL OF DIVIDENDS ON PREFERRED UNITS/STOCK...... (1,326) (7,094) (7,911)
------- -------- -------
NET LOSS AVAILABLE TO COMMON UNITHOLDERS/
STOCKHOLDERS...................................... $(3,488) $(13,954) $(9,248)
======= ======== =======
BASIC LOSS PER COMMON UNIT/SHARE:
Loss before cumulative effect of change in
accounting principle............................ $ (0.88) $ (3.44) $ (1.06)
Cumulative effect of change in accounting
principle....................................... -- -- (0.05)
------- -------- -------
NET LOSS PER COMMON UNIT/SHARE..................... $ (0.88) $ (3.44) $ (1.11)
======= ======== =======
DILUTED LOSS PER COMMON UNIT/SHARE:
Loss before cumulative effect of change in
accounting principle............................ $ (0.88) $ (3.44) $ (1.06)
Cumulative effect of change in accounting
principle....................................... -- -- (0.05)
------- -------- -------
NET LOSS PER COMMON UNIT/SHARE..................... $ (0.88) $ (3.44) $ (1.11)
======= ======== =======
WEIGHTED AVERAGE NUMBER OF COMMON UNITS/SHARES
OUTSTANDING:
Basic............................................ 3,960 4,059 8,355
======= ======== =======
Diluted.......................................... 3,960 4,059 8,355
======= ======== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
39
<PAGE>
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands, except units/shares and unit/share dividend data)
<TABLE>
<CAPTION>
Units/Shares Par Value Preferred Additional Unitholder/
---------------------- ---------------- Unit Paid-In Stockholder Accumulated Treasury
Preferred Common Preferred Common Subscriptions Capital Receivables Deficit Stock Total
---------- ---------- --------- ------ ------------- ---------- ----------- ----------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Balance, December
31, 1996......... 198,921 3,960,000 $-- $ -- $54,480 $ 29 $(50,798) $ (344) $ -- $ 3,367
Net loss........ -- -- -- -- -- -- -- (2,162) -- (2,162)
Preferred unit
dividends ($3.00
per preferred
unit)........... -- -- -- -- -- -- -- (1,326) -- (1,326)
Preferred unit
payments........ 760,000 -- -- -- -- -- 19,000 -- -- 19,000
---------- ---------- --- ---- ------- -------- -------- -------- ---- --------
Balance, December
31, 1997......... 958,921 3,960,000 -- -- 54,480 29 (31,798) (3,832) -- 18,879
Conversion to
Spinnaker
Exploration
Company......... -- 97,200 10 20 (54,480) 54,450 -- -- -- --
---------- ---------- --- ---- ------- -------- -------- -------- ---- --------
958,921 4,057,200 10 20 -- 54,479 (31,798) (3,832) -- 18,879
Net loss........ -- -- -- -- -- -- -- (6,860) -- (6,860)
Common stock
issuance........ -- 25,000 -- -- -- 188 -- -- -- 188
Preferred stock
subscriptions... -- -- -- -- -- 19,982 (19,982) -- -- --
Preferred stock
dividends ($3.00
per share)...... -- -- -- -- -- -- -- (7,094) -- (7,094)
Preferred stock
payments........ 2,071,999 -- 20 -- -- -- 51,780 -- -- 51,800
---------- ---------- --- ---- ------- -------- -------- -------- ---- --------
Balance, December
31, 1998......... 3,030,920 4,082,200 30 20 -- 74,649 -- (17,786) -- 56,913
Net loss........ -- -- -- -- -- -- -- (1,337) -- (1,337)
Common stock
split........... -- -- -- 20 -- (20) -- -- -- --
Common stock
issuance........ -- 9,076,096 -- 91 -- 111,260 -- -- -- 111,351
Exercise of
stock options... -- 5,808 -- -- -- 29 -- -- -- 29
Preferred stock
dividends ($3.00
per share)...... -- -- -- -- -- -- -- (7,911) -- (7,911)
Conversion of
preferred stock
to common
stock........... (3,030,920) 6,061,840 (30) 61 -- (31) -- -- -- --
Reinvestment of
preferred stock
dividends into
common stock.... -- 1,200,248 -- 12 -- 16,299 -- -- -- 16,311
Stock
compensation
costs........... -- -- -- -- -- 150 -- -- -- 150
Stock
appreciation
rights
termination..... -- -- -- -- -- 1,651 -- -- -- 1,651
Treasury stock.. -- -- -- -- -- -- -- -- (55) (55)
---------- ---------- --- ---- ------- -------- -------- -------- ---- --------
Balance, December
31, 1999......... -- 20,426,192 $-- $204 $ -- $203,987 $ -- $(27,034) $(55) $177,102
========== ========== === ==== ======= ======== ======== ======== ==== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
40
<PAGE>
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Year Ended
December 31,
----------------------------
1997 1998 1999
-------- -------- --------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss....................................... $ (2,162) $ (6,860) $ (1,337)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Depreciation, depletion and amortization..... 417 3,175 21,001
Write-down of natural gas and oil
properties.................................. -- 2,642 --
Stock appreciation rights expense............ -- -- 1,651
Cumulative effect of change in accounting
principle................................... -- -- 395
Change in components of working capital:
Accounts receivable.......................... (3,593) (218) (6,974)
Accounts payable and accrued liabilities..... (63) (896) (636)
Other current assets and other............... (122) (619) 805
-------- -------- --------
Net cash provided by (used in) operating
activities................................ (5,523) (2,776) 14,905
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties......................... (13,638) (84,823) (78,894)
Change in property related payables............ 342 17,178 (5,291)
Purchases of other property and equipment...... (1,940) (858) (916)
-------- -------- --------
Net cash used in investing activities...... (15,236) (68,503) (85,101)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings....................... -- 19,000 53,000
Payments on borrowings......................... -- -- (72,000)
Proceeds from issuance of common stock......... -- -- 108,720
Common stock issuance costs.................... -- -- (1,109)
Preferred stock dividends...................... -- -- (78)
Proceeds from exercise of stock options........ -- -- 29
Acquisition of treasury stock.................. -- -- (55)
Proceeds from issuance of preferred stock,
net........................................... -- 51,738 --
Preferred unit subscription payments, net...... 18,863 -- --
-------- -------- --------
Net cash provided by financing activities.. 18,863 70,738 88,507
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS..................................... (1,896) (541) 18,311
CASH AND CASH EQUIVALENTS, beginning of year..... 4,578 2,682 2,141
-------- -------- --------
CASH AND CASH EQUIVALENTS, end of year........... $ 2,682 $ 2,141 $ 20,452
======== ======== ========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts
capitalized................................... $ -- $ 84 $ 2,591
Cash paid for income taxes..................... -- -- --
SUPPLEMENTAL NON-CASH INVESTING AND FINANCING
ACTIVITIES:
Reinvestment of preferred dividends payable
into common stock............................. $ -- $ -- $ 16,311
Issuance of common stock for amended seismic
data rights................................... -- -- 2,900
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
41
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization, Nature of Operations and Formation:
Organization and Nature of Operations
Spinnaker Exploration Company, L.L.C. ("Spinnaker"), a Delaware limited
liability company, was formed on December 20, 1996, and is engaged in the
exploration, development and production of natural gas and oil properties in
the U.S. Gulf of Mexico. Spinnaker was formed by WP Spinnaker Holdings, Inc.
("Holdings"), a subsidiary of Warburg, Pincus Ventures L.P. ("Warburg"),
Seismic Energy Holdings, Inc. ("SEHI"), a subsidiary of Petroleum Geo-Services
ASA ("PGS"), a Norwegian joint-stock company, and certain members of
management of Spinnaker (collectively known as the "Investors").
Formation
As a part of the formation of Spinnaker, Warburg purchased 1,000,000 common
units ("Common Units") at $0.0125 per Common Unit and agreed to subscriptions
on preferred units ("Preferred Units") of up to $50.0 million at a price of
$25.00 per unit, of which 151,746 Preferred Units were purchased at formation.
PGS purchased 1,000,000 Common Units at $0.0125 per Common Unit and subscribed
for up to $15.0 million of Preferred Units also at a price of $25.00 per unit,
of which 45,093 Preferred Units were purchased at formation. PGS was only
obligated to purchase an aggregate of $5.0 million Preferred Units unless
Spinnaker sold additional Preferred Units to other investors. As a result,
preferred stock subscriptions were recorded at approximately $54.5 million at
inception. Additionally, PGS entered into a seismic data agreement ("Data
Agreement") with Spinnaker dated December 20, 1996, whereby it agreed to
transfer to Spinnaker certain rights to 3-D seismic data in consideration of
Common Units. See Note 4. Management purchased 160,000 Common Units and agreed
to subscriptions on Preferred Units of up to $798,000 at $25.00 per unit of
which 2,352 units were purchased at formation. Property contributed by
management related to this formation included cash of $9,726 and property
resulting from expenditures made by Mr. Jarvis in anticipation of the
formation of the Company. The total value, for purposes of the agreement, of
the initial management contributions was $60,790. The 198,921 Preferred Units
purchased at inception resulted in consideration received of approximately
$5.0 million and net of $1.3 million in offering costs resulted in net
proceeds of $3.7 million. Upon completion of the formation, beneficial
ownership of the Common Units was 71%, 25% and 4% for PGS, Warburg, and
management, respectively. Spinnaker accounted for the contribution of the Data
Agreement at PGS' cost, which was immaterial. See Note 4.
Change in Reporting Entity
On January 6, 1998, Spinnaker Exploration Corp. ("Spinco"), a Delaware
corporation, was formed by Spinnaker Exploration Company, L.L.C., with Mr.
Jarvis acting as sole director until a board was elected. Contemporaneous with
the formation of Spinco, the Investors, other than Warburg, contributed their
respective Preferred Units and Common Units to Spinco and in exchange for such
contributions, Spinco issued a like number of its shares of common stock, par
value $0.01 per share ("Common Stock"), and Series A Convertible Preferred
Stock ("Preferred Stock"), par value $0.01 per share. Warburg contributed all
of its issued and outstanding common shares of Holdings to Spinco in exchange
for shares of Common Stock and Preferred Stock of Spinco. As of January 6,
1998, the equity owners of Spinnaker were Spinco and Spinco's wholly owned
subsidiary, Holdings. On April 27, 1998, Spinco filed an amendment to its
certificate of incorporation with the State of Delaware to change its name
from Spinco to Spinnaker Exploration Company ("Spinnaker" or the "Company").
As a part of the change in entity, SEHI was issued an additional 97,200 shares
of Common Stock.
Initial Public Offering
On September 28, 1999, the Company priced its initial public offering of
8,000,000 shares of Common Stock and commenced trading the following day.
After payment of underwriting discounts and commissions, the
42
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Company received net proceeds of $108.7 million on October 4, 1999. With a
portion of the proceeds, the Company retired all outstanding debt of $72.0
million. In connection with the initial public offering, the Company converted
all outstanding Preferred Stock into shares of Common Stock, and certain
shareholders reinvested preferred dividends payable of $16.3 million into
shares of Common Stock.
2. Summary of Significant Accounting Policies:
General
The accompanying consolidated financial statements of Spinnaker Exploration
Company have been prepared in accordance with accounting principles generally
accepted in the United States and pursuant to the rules and regulations of the
Securities and Exchange Commission (the "Commission").
Principles of Consolidation
The accompanying consolidated financial statements include the activities
and accounts of the Company, Spinnaker Exploration Company, L.L.C. and WP
Spinnaker Holdings, Inc. All significant intercompany transactions and
balances are eliminated in consolidation.
Use of Estimates
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Significant estimates include depreciation, depletion and amortization of
proved natural gas and oil properties. Natural gas and oil reserve estimates,
which are the basis for unit-of-production DD&A and the full cost ceiling
test, are inherently imprecise and are expected to change as future
information becomes available.
Cash Equivalents
The Company considers all highly liquid investments with a maturity of three
months or less when purchased to be cash equivalents.
Other Current Assets
Other current assets includes debt financing costs of $465,000 and $242,000
at December 31, 1998 and 1999, respectively, related to the $85 million and
$25 million credit agreements, which are amortized to interest expense over
the term of the related credit agreements. Amortization included in interest
expense was $116,000 and $576,000 for the years ended December 31, 1998 and
1999, respectively. See Note 3.
Natural Gas and Oil Properties
The Company uses the full cost method of accounting for its investment in
natural gas and oil properties. Under this method, all acquisition,
exploration and development costs, including certain related employee costs,
incurred for the purpose of finding natural gas and oil are capitalized. Such
amounts include the cost of drilling and equipping productive wells, dry hole
costs, lease acquisition costs, delay rentals and costs related to such
activities. Exclusive of field-level costs, Spinnaker capitalized $1.3
million, $2.5 million and $2.5 million of internal costs in 1997, 1998 and
1999, respectively. Costs associated with production and general corporate
activities are expensed in the period incurred. Interest costs related to
unproved properties and properties under development are also capitalized to
natural gas and oil properties. Sales of natural gas and oil properties,
whether
43
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
or not being amortized currently, are accounted for as adjustments of
capitalized costs, with no gain or loss recognized, unless such adjustments
would significantly alter the relationship between capitalized costs and
proved reserves of natural gas and oil.
The Company computes the provision for depreciation, depletion and
amortization ("DD&A") of natural gas and oil properties using the unit-of-
production method based upon production and estimates of proved reserve
quantities. Unevaluated costs and related carrying costs are excluded from the
amortization base until the properties associated with these costs are
evaluated. The amortization base includes estimated future development costs
and dismantlement, restoration and abandonment costs, net of estimated salvage
values.
The Company limits the capitalized costs of natural gas and oil properties,
net of accumulated DD&A and related deferred taxes, to the estimated future
net cash flows from proved natural gas and oil reserves discounted at 10%,
plus the lower of cost or fair value of unproved properties, as adjusted for
related income tax effects (the full cost ceiling). If capitalized costs
exceed the full cost ceiling, the excess is charged to write-down of natural
gas and oil properties in the quarter in which the excess occurs. At December
31, 1998, the Company recognized a non-cash write-down of natural gas and oil
properties in the amount of $2.6 million pursuant to the ceiling limitation
required by the full cost method of accounting for natural gas and oil
properties, using prices as of April 9, 1999. The write-down was primarily the
result of the precipitous decline in natural gas prices experienced in 1998.
Using December 31, 1998 prices, the Company would have recognized a non-cash
write-down of natural gas and oil properties in the amount of $13.0 million.
The write-down was reduced due to the increase in natural gas and oil prices
from December 31, 1998 through April 9, 1999.
The costs of certain unevaluated leasehold acreage and wells drilled, but
currently under evaluation, are not being amortized. Costs not being amortized
are periodically assessed for possible impairments or reduction in value. If a
reduction in value has occurred, costs being amortized are increased. Of the
$40.7 million of net unproved property costs at December 31, 1999 excluded
from the amortizable base, $5.7 million, $22.7 million and $12.3 million were
incurred in 1997, 1998 and 1999, respectively. The majority of the costs will
be evaluated over the next four years.
Substantially all the Company's exploration activities are conducted jointly
with others and, accordingly, the natural gas and oil property balances
reflect only its proportionate interest in such activities.
Other Property and Equipment
Other property and equipment consists of computer hardware and software,
office furniture and leasehold improvements. The Company is depreciating these
assets using the straight-line method based upon estimated useful lives
ranging from three to five years.
Organization Costs
As of December 31, 1998, Other assets included capitalized organization
costs incurred by the Company in its initial formation. The Company was
amortizing the start-up costs over a period of five years. Amortization
expense for each of the years ended December 31, 1997 and 1998, was $126,000
and $132,000, respectively.
On April 3, 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5 ("SOP 98-5"), "Reporting on the Costs of
Start-Up Activities," which requires that costs for start-up activities and
organization costs be expensed as incurred and not capitalized as had
previously been allowed. SOP 98-5 is effective for financial statements for
fiscal years beginning after 1998. The Company adopted this policy in the
first quarter of 1999 and recorded a charge related to this accounting change
of $395,000 in conjunction with the write-off of previously capitalized
organization costs.
44
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Revenue Recognition Policy
The Company records as revenue only that portion of production sold and
allocable to its ownership interest in the related property. Imbalances arise
when a purchaser takes delivery of more or less volume from a property than
the Company's actual interest in the production from that property. Such
imbalances are reduced either by subsequent recoupment of over-and-under
deliveries or by cash settlement, as required by applicable contracts. Under-
deliveries are included in Other assets and over-deliveries are included in
Other liabilities.
Income Taxes
Prior to January 6, 1998, the Company was not a tax-paying entity for
federal income tax purposes. The profit or loss of the Company for federal
income tax reporting purposes was included in the income tax returns of the
Investors. Accordingly, no recognition has been given to income taxes in the
accompanying 1997 financial statements.
Effective January 6, 1998, with the formation of Spinco, the Company became
subject to federal income taxes and began to apply the provisions of Statement
of Financial Accounting Standards ("SFAS") No. 109, "Accounting for Income
Taxes." See Notes 1 and 10. Under SFAS No. 109, deferred income taxes are
recognized at each year-end for the future tax consequences of differences
between the tax bases of assets and liabilities and their financial reporting
amounts based on enacted tax laws and statutory tax rates applicable to the
periods in which the differences are expected to affect taxable income.
Valuation allowances are established when necessary to reduce deferred tax
assets to the amount expected to be realized. The total provision for income
taxes is the sum of taxes payable for the year and the change during the year
in deferred tax assets and liabilities.
Stock Split
On September 1, 1999, the Company declared a two-for-one stock split on the
Common Stock (the "Stock Split"). All references to the number of common
units/shares and per share amounts elsewhere in the consolidated financial
statements and related footnotes have been restated as appropriate to reflect
the effect of the Stock Split for all periods presented.
Financial Instruments and Hedging Activities
The Company's financial instruments consist of cash and cash equivalents,
receivables, payables and debt. The carrying amount of cash and cash
equivalents, receivables, payables and debt approximates fair value because of
the short-term nature of these items.
The Company's commodity hedging policy permits the use of certain financial
instruments and commodity contracts to mitigate its exposure to natural gas
and oil price volatility. These financial instruments, which are placed with
major financial institutions the Company believes are minimum credit risks,
take the form of costless collars. These transactions are designated as hedges
and accounted for on the accrual basis with realized gains and losses
recognized in revenues when the related production occurs. The Company
recognized approximately $751,000 of net hedging income during 1999. The
Company's costless collars mature monthly through October 2000. The estimated
fair value of the open collar arrangements in place at December 31, 1999 was
an unrealized gain of approximately $968,000.
Stock Options
In October 1995, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 123, "Accounting for Stock-Based Compensation." SFAS No. 123
encourages, but does not require, companies to record
45
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
compensation cost for stock-based employee compensation plans at fair value.
The Company has chosen to account for stock-based compensation using the
intrinsic value method prescribed in Accounting Principles Board ("APB")
Opinion No. 25, "Accounting for Stock Issued to Employees," and related
interpretations. Accordingly, compensation cost for stock options is measured
as the excess, if any, of the fair value of the Company's Common Stock at the
date of the grant over the amount an employee must pay to acquire the Common
Stock. See Note 6.
Concentration of Credit Risk
Financial instruments that potentially subject the Company to concentration
of credit risk consist principally of cash equivalents and trade accounts
receivable. Management believes that the credit risk posed by this
concentration is offset by the creditworthiness of the Company's customer
base.
Risk Factors
The Company's revenue, profitability, cash flow and future rate of growth is
substantially dependent upon the price of and demand for natural gas, oil and
natural gas liquids. Prices for natural gas and oil are subject to wide
fluctuations in response to relatively minor changes in the supply of and
demand for natural gas and crude oil, market uncertainty and a variety of
additional factors that are beyond the control of the Company. Other factors
that could affect the revenue, profitability, cash flow and future growth of
the Company include its limited operating history and the incurrence of losses
since formation, the inherent uncertainties in reserve estimates, the
concentration of production and reserves in a small number of offshore
properties, and the ability to finance growth and replace reserves. Spinnaker
is also dependent upon the continued success of an exploratory drilling
program and its ability to realize value from its Data Agreement. See Note 4.
New Accounting Policies
In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities." SFAS No. 133 established accounting and
reporting standards requiring that all derivative instruments be recorded in
the balance sheet as either an asset or liability measured at its fair value.
The SFAS requires that changes in a derivative's fair value be recognized
currently in earnings unless specific hedge accounting criteria are met.
Accounting for qualifying hedges allows a derivative's gains and losses to
offset related results on the hedged item in the income statement and requires
a company to formally document, designate and assess the effectiveness of
transactions that qualify for hedge accounting. SFAS No. 133 was originally
effective for fiscal years beginning after June 15, 1999; however, SFAS No.
137, "Accounting for Derivative Instruments and Hedging Activities--Deferral
of the Effective Date of FASB Statement No. 133--An Amendment of FASB
Statement No. 133" extended implementation to fiscal years beginning after
June 15, 2000. Early adoption is permitted. The Company believes SFAS No. 133
will not have a significant impact on the consolidated financial statements.
3. Debt:
In September 1998, the Company entered into an $85.0 million credit
agreement ("Credit Agreement") with certain financial institutions. Proceeds
from borrowings under the Credit Agreement were used to fund exploration and
development activities. The Credit Agreement was secured by the Company's
interests in natural gas and oil properties and by certain guarantees of PGS
and Warburg. The stockholder guarantees for the Credit Agreement were $75.0
million, split evenly between PGS and Warburg. On a semi-annual basis, the
Company's proved reserves were required to be evaluated to re-determine the
borrowing base. If the borrowing base increased, the guarantees were
permanently decreased dollar for dollar. If payments were made under a
46
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
guarantee, the balance due to the guarantor was immediately and automatically
converted into equity of the Company at a rate of $15.00 per share.
The Credit Agreement was comprised of three tranches, each with a specified
interest rate. The weighted average interest rate for each of the PGS and the
Warburg tranches was 5.67% in 1998 and 5.54% in 1999. The weighted average
interest rate for the borrowing base tranche was 8.23% in 1998 and 7.45% in
1999. The overall weighted average interest rate for borrowings outstanding
under the Credit Agreement was 6.54% in 1998 and 5.71% in 1999.
Borrowings outstanding under the Credit Agreement as of October 4, 1999 were
$72.0 million, of which $67.0 million was guaranteed by PGS and Warburg.
Interest expense related to the Credit Agreement was $212,000 and $2.4 million
for the years ended December 31, 1998 and 1999, respectively, excluding
amounts related to the stock issuances for guarantees, as described below.
In consideration for providing guarantees under the Credit Agreement, PGS
and Warburg were entitled to receive, from time to time, Common Stock. Any
related stock issuances were accounted for at the fair value of the guarantees
provided. Such amounts were $188,000 and $840,000 for the years ended December
31, 1998 and 1999, respectively, and have been included in interest expense in
the accompanying consolidated statements of operations.
The Credit Agreement contained certain covenants and restrictive provisions,
including limitations on the incurrence of additional debt or liens, the sales
of property, the declaration or payment of dividends and the repurchase or
redemption of capital stock, and the maintenance of certain financial ratios.
On October 4, 1999, with proceeds from the initial public offering, the
Company paid all outstanding borrowings of $72.0 million.
The Credit Agreement was scheduled to mature on December 31, 1999; however,
the Company amended and restated the original Credit Agreement on October 29,
1999. The $25.0 million Amended and Restated 364-Day Credit Agreement
("Amended Credit Agreement") among the Company, Bank of Montreal and Credit
Suisse First Boston matures on October 27, 2000. The Company may borrow only
up to the borrowing base, which is currently $16.0 million. On a semi-annual
basis, the Company's proved reserves are required to be evaluated to re-
determine the borrowing base. The Amended Credit Agreement contains covenants
and restrictive provisions, including the following limitations, subject to
some exceptions, where the Company:
. may not incur any other indebtedness from borrowings, except for
indebtedness of up to $1.0 million and indebtedness owed to guarantors of
the Amended Credit Agreement;
. may not incur any liens upon properties or assets other than permitted
liens securing indebtedness of up to $1.0 million, pledges or deposits to
secure hedging agreements up to $5.0 million and other liens in the
ordinary course of business;
. may not enter into any amalgamation or merger unless it is the survivor
and no default exists;
. may not dispose of all or substantially all property, business or assets;
. may not dispose of any properties valued in the borrowing base except
obsolete equipment, inventory sold in the ordinary course of business,
some interests in natural gas and oil properties included in the
borrowing base in an aggregate amount not to exceed $500,000 between the
borrowing base determination and non-proved reserves;
. may not make or pay any dividend, distribution or payment in respect of
capital stock nor purchase, redeem, retire, or permit any reduction or
retirement of capital stock;
47
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
. must maintain the ratio of consolidated current assets as of the end of
each fiscal quarter to consolidated current liabilities other than debt
under the Amended Credit Agreement as of the end of such fiscal quarter
so that it is not less than 1.00 to 1.00;
. may not enter into any hedging agreement unless the Company meets
specified requirements including limits on the aggregate amounts maturing
in any month under any floor hedging contracts and under any forward
sales transactions.
4. Seismic Data Agreement:
As part of the Company's formation, SEHI agreed to transfer to Spinnaker
certain rights to 3-D seismic data in exchange for issuing 1,800,000 Common
Units to SEHI pursuant to the Data Agreement dated December 20, 1996. See
Notes 1 and 5. The Company also had the ability under the Data Agreement to
acquire additional rights to 3-D seismic data in exchange for issuing
additional Common Units to SEHI. SEHI's obligation to the Company in
connection with the Data Agreement is guaranteed by its parent, PGS. In
addition, the Company has agreed to purchase $2.0 million of seismic related
services from PGS prior to December 31, 2002. The Company paid to PGS
approximately $59,000, $122,000 and $318,000 in 1997, 1998 and 1999,
respectively, for seismic-related services.
The Data Agreement was amended effective June 30, 1999. The amended Data
Agreement modified the amount, type and geographic coverage of the data and
related information made available to Spinnaker. In exchange for the amended
rights under the Data Agreement, Spinnaker issued to PGS an additional
1,000,000 shares of Common Stock. This transaction has been accounted for at
PGS' cost of $2.9 million, pursuant to Staff Accounting Bulletin No. 48.
5. Equity:
Convertible Preferred Units/Stock
On December 20, 1996, Spinnaker authorized 3,030,720 units of Series A
Convertible Preferred Units, and on the same day sold 198,921 Preferred Units
to the Investors for consideration of approximately $5.0 million, composed of
cash and certain previously incurred organization costs. Offering costs of
$1.3 million, consisting principally of investment banking fees, were incurred
in connection with this transaction. In 1997, Spinnaker sold an additional
760,000 Preferred Units to the Investors for consideration of approximately
$19.0 million.
The Investors initially committed, subject to certain conditions, to
purchase a total of up to approximately $65.8 million of Preferred Units. In
1998, the total capital commitment for the Investors was increased to $75.8
million, allocated as follows: $15.0 million to SEHI, $60.0 million to
Holdings and $800,000 to management.
On January 6, 1998, concurrent with the formation of Spinco, Spinco
authorized 3,030,920 shares of Preferred Stock with a par value of $.01. All
Preferred Units of Spinnaker, except those issued to Holdings, were
contributed to Spinco in exchange for a like number of shares in Spinco's
Preferred Stock. The Preferred Stock had a liquidation preference of $25.00
per share plus accrued dividends. Each share of Preferred Stock was
convertible into two shares of Common Stock subject to certain anti-dilution
provisions, upon one of the following: (a) at the holder's option, (b) by a
vote of a majority of the board of directors and holders of the Preferred
Stock representing at least 65% of the voting power of the Preferred Stock, or
(c) a qualified public offering. In the event of a qualified public offering,
the Company, at its option, could have automatically converted the Preferred
Stock into Common Stock if the Common Stock was sold for not less than 150% of
the conversion price of $12.50, subject to adjustments in the event of stock
dividends, stock splits, and issuance of shares below the $12.50 conversion
price, etc.
48
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Dividends accrued at the rate of $3.00 per share and unpaid dividends
compounded quarterly at a rate of 12% per annum until December 31, 2006, at
which time, the rate would have decreased to $2.00 per share per annum
thereafter if all dividends for the then prior periods had been declared and
paid in full. Otherwise, the dividend rate would have increased to $5.00 per
share per annum and the rate at which the dividends compound quarterly would
have increased to an annual rate of 20% after December 31, 2006. At December
31, 1998, accrued dividends on the Preferred Stock were $8.5 million.
Dividends were payable in cash on the earliest to occur of a qualified initial
public offering, a merger or consolidation involving the Company, a sale of
all or substantially all of the assets of the Company or a change of control
of the Company. The Preferred Stock was entitled to vote together with the
Common Stock on an as converted basis. The Preferred Stock could have been
redeemed by the Company on or after January 21, 2018 at a redemption price of
$25.00 per share plus any accrued and unpaid dividends through the redemption
date.
The Preferred Stock had substantially the same economic terms as the
Preferred Units had except that the dividend rate on the Preferred Units
increased after December 31, 2006 to $5.00 per share and the Preferred Units
could be redeemed by the Company after December 31, 2006.
During 1998, Preferred Stock subscriptions increased by approximately $20.0
million as a result of Warburg increasing its Preferred Unit subscriptions by
$10.0 million and PGS agreeing that it would be obligated to purchase an
aggregate of $15.0 million of Preferred Stock rather than $5.0 million.
In 1998, Spinnaker sold an additional 2,071,999 shares of Preferred Stock to
the Investors for consideration of approximately $51.8 million, of which $11.0
million was sold during the first quarter. At December 31, 1996 and 1997,
receivables on the conditional commitments for the sale of Preferred
Units/Stock to the Investors were approximately $50.8 million and $31.8
million, respectively, and are presented as a reduction in equity. At December
31, 1998, all commitments from Investors for Preferred Stock had been
fulfilled.
In connection with the initial public offering, the Company converted all
outstanding Preferred Stock into shares of Common Stock, and certain
shareholders reinvested preferred dividends payable of $16.3 million into
shares of Common Stock.
Common Units/Stock
In December 1996, Spinnaker authorized 14,701,440 Common Units, of which
3,960,000 were sold to the Investors on December 21, 1996, for consideration
of $25,000 of cash, certain organization costs and a seismic data contribution
agreement. See Note 4. The Common Units were subject to certain transfer
restrictions, and holders of Common Units were bound by certain tax-sharing
arrangements which had the effect of providing economic benefits to Holdings
greater than would be expected in the absence of such agreement.
The Company issued a total of 25,000 and 76,096 shares of Common Stock to
PGS and Warburg in 1998 and 1999, respectively, under terms of the Credit
Agreement related to the guarantor commitments of both parties. See Note 3.
On January 6, 1998, concurrent with the formation of Spinco, Spinco
authorized 14,399,040 shares of Common Stock with a par value of $.01 per
share. All issued Common Units of Spinnaker, except for those issued to
Holdings, were contributed to Spinco in exchange for a like number of shares
in Spinco's Common Stock. In September 1998, the Company amended its
certificate of incorporation and increased the number of authorized shares of
Common Stock to 22,000,000.
On September 28, 1999, the Company priced its initial public offering of
8,000,000 shares of Common Stock and commenced trading the following day. In
connection with the initial public offering, the Company
49
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
converted all outstanding Preferred Stock into 6,061,840 shares of Common
Stock, and certain shareholders reinvested preferred dividends payable of
$16.3 million into 1,200,248 shares of Common Stock.
Common Stock Split
On August 31, 1999, the Company approved a two-for-one stock split on the
Common Stock effective September 1, 1999. One additional share was issued for
each share of Common Stock. Par value remained unchanged at $0.01 per share.
In connection with the Stock Split, the Company amended the certificate of
incorporation to increase the authorized number of shares of Common Stock to
50,000,000 shares.
6. Unit/Stock Option Agreements:
On December 27, 1996, Spinnaker adopted its unit option plan, authorizing
nonqualified options for the benefit of Spinnaker's officers and other key
employees to acquire up to 2,480,000 Common Units, 1,520,000 at $5.00 per
Common Unit and 960,000 at $15.63 per Common Unit. The maximum period for
exercise of an option may not be more than ten years from the date of grant.
Options granted vest and become exercisable in general at dates determined by
the compensation committee, subject to the specific terms of the individual
option agreements.
On January 6, 1998, the unit options in the unit option plan were exchanged
for stock options in Spinco. In connection with the exchange, all benefits,
rights and obligations of the unit options were transferred to the stock
options. In August 1998, the Company authorized additional options for the
benefit of Spinnaker's officers and other key employees to acquire up to 3,040
shares of Common Stock at $5.00 per share and 356,920 shares of Common Stock
at $15.63 per share.
The Company applies APB Opinion No. 25 and related interpretations in
accounting for its employee stock-based compensation. In accordance with APB
Opinion No. 25, compensation expense related to stock-based compensation
included in general and administrative expense was zero for 1997 and 1998,
respectively, and $150,000 for 1999. Had compensation cost for the Company's
stock option compensation plans been determined based on the fair value at the
grant dates for awards under this plan consistent with the method of SFAS No.
123, "Accounting for Stock-Based Compensation," the Company's pro forma net
loss available to common unitholders/stockholders and loss per common
unit/share would have been as follows (in thousands, except per share
amounts):
<TABLE>
<CAPTION>
For the Year Ended
December 31,
---------------------------
1997 1998 1999
------- -------- --------
<S> <C> <C> <C>
Pro forma net loss available to common
unitholders/stockholders........................ $(3,517) $(14,172) $(10,950)
======= ======== ========
Pro forma net loss per basic and diluted common
unit/share...................................... $ (0.89) $ (3.49) $ (1.31)
======= ======== ========
</TABLE>
For purposes of the SFAS No. 123 disclosure, the fair value of each option
grant is estimated on the date of grant using the Black-Scholes option-pricing
model with weighted average assumptions for grants in 1997, 1998 and 1999
which, among others, include the following:
<TABLE>
<CAPTION>
For the Year Ended December
31,
-----------------------------
1997 1998 1999
----- ----------- -----------
<S> <C> <C> <C>
Risk-free interest rate........................... 6.89% 4.96%-5.96% 4.67%-6.08%
Volatility factor................................. 0% 0% 54.8%
Dividend yield.................................... 0% 0% 0%
Expected life of the options (years).............. 10 10 4.5
</TABLE>
50
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Presented below is a summary of stock option activity.
<TABLE>
<CAPTION>
Number of Weighted
Shares Average
Under Exercise Price
Option Per Share
--------- --------------
<S> <C> <C>
Outstanding options at December 31, 1996.............. 1,388,800 $ 9.12
Granted............................................. 809,200 9.09
---------
Outstanding options at December 31, 1997.............. 2,198,000 9.10
Granted............................................. 328,880 9.13
---------
Outstanding options at December 31, 1998.............. 2,526,880 9.11
Granted............................................. 866,574 14.74
Exercised........................................... (5,872) 4.97
Canceled............................................ (4,608) 9.29
---------
Outstanding options at December 31, 1999.............. 3,382,974 $10.56
=========
Exercisable, December 31,
1997................................................ 717,360 $ 9.11
1998................................................ 1,222,736 $ 9.11
1999................................................ 1,919,019 $ 9.62
</TABLE>
At December 31, 1999, the following options were outstanding and exercisable
and had the indicated weighted average remaining contractual lives:
<TABLE>
<CAPTION>
Outstanding Exercisable
- ------------------------- ------------------------
Weighted
Average
Weighted Weighted Range of Remaining
Average Average Exercise Contractual
Number of Exercise Price Number of Exercise Price Prices Per Life
Options Per Share Options Per Share Share (Years)
- --------- -------------- --------- -------------- -------------- -----------
<S> <C> <C> <C> <C> <C>
1,536,400 $ 4.96 1,067,528 $ 4.98 $ 2.50--$ 5.00 7.2
1,846,574 $15.21 851,491 $15.44 $14.50--$15.63 8.4
</TABLE>
Stock option grants vest ratably over four years, with 20% vesting on the
date of grant and 20% vesting in each of the succeeding four years. Stock
options vest fully in the event of a change in control of the Company.
Additionally, the stock option agreements of two of the Company's officers
provided that they could elect to have the Company deliver shares equal to the
appreciation in the value of the stock over the option price in lieu of
purchasing the amount of shares under option. Based on management's estimate
of the share value of the Company, compensation expense of approximately $1.7
million was recorded in 1999 related to the stock appreciation rights of the
stock option agreements. In July 1999, these two officers agreed to eliminate
the stock appreciation rights feature of their stock option agreements.
51
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
7. Earnings Per Unit/Share:
Basic and diluted net loss per unit/share is computed based on the following
information (in thousands, except per share amounts):
<TABLE>
<CAPTION>
For the Year Ended
December 31,
--------------------------
1997 1998 1999
------- -------- -------
<S> <C> <C> <C>
Numerator:
Net loss available to common
unitholders/stockholders.......................... $(3,488) $(13,954) $(9,248)
======= ======== =======
Denominator:
Basic earnings per unit/share--weighted average
units/shares...................................... 3,960 4,059 8,355
======= ======== =======
Dilutive securities:
Unit/stock options............................... -- -- --
Preferred units/stock............................ -- -- --
------- -------- -------
Dilutive potential common unit/shares.............. -- -- --
------- -------- -------
Diluted earnings per unit/share--adjusted weighted
average units/shares and assumed conversions...... 3,960 4,059 8,355
======= ======== =======
Net loss per common unit/share:
Basic:
Loss before cumulative effect of change in
accounting principle............................ $ (0.88) $ (3.44) $ (1.06)
Cumulative effect of change in accounting
principle....................................... -- -- (0.05)
------- -------- -------
Net loss per common unit/share..................... $ (0.88) $ (3.44) $ (1.11)
======= ======== =======
Diluted:
Loss before cumulative effect of change in
accounting principle............................ $ (0.88) $ (3.44) $ (1.06)
Cumulative effect of change in accounting
principle....................................... -- -- (0.05)
------- -------- -------
Net loss per common unit/share..................... $ (0.88) $ (3.44) $ (1.11)
======= ======== =======
</TABLE>
For purposes of the diluted earnings per unit/share calculation, the
Preferred Units/Stock and unit/stock options are considered anti-dilutive and
are therefore not considered in the above calculation.
8. Major Customers:
The Company had natural gas and oil sales to one customer accounting for
100% of total natural gas and oil revenues for the years ended December 31,
1997 and 1998, respectively. The Company had natural gas and oil revenues to
two customers, accounting for 68% and 32%, respectively, of total natural gas
and oil revenues for the year ended December 31, 1999.
9. Related-Party Transactions:
As part of the Company's formation, SEHI agreed to transfer limited rights
to 3-D seismic data to Spinnaker in exchange for issuing Common Units to SEHI.
See Note 4. The Common Units were exchanged for shares of Common Stock upon
the formation of Spinco. Additionally, the Company paid to PGS approximately
$59,000, $122,000 and $318,000 in 1997, 1998 and 1999, respectively, for
seismic-related services.
The Data Agreement was amended effective June 30, 1999. In exchange for the
amended rights under the Data Agreement, Spinnaker issued to PGS an additional
1,000,000 shares of Common Stock. See Note 4.
52
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
From September 30, 1998 through October 4, 1999, PGS and Warburg provided
certain guarantees for the Credit Agreement totaling $75.0 million. See Note
3.
10. Income Taxes:
Effective with the formation of Spinco, the Company became subject to
federal income taxes. The formation of Spinco required the Company to
establish a deferred tax liability, which resulted in a one-time non-cash
charge to income of $1.7 million. During 1998, the Company generated
additional operating losses and the related tax benefits offset this amount.
No net income tax benefit was recognized in 1998 or 1999 due to the
uncertainty of future operating income as the Company has not established a
history of net operating income. Net operating loss carryforwards of $23.0
million and $3.6 million expire in 2018 and 2019, respectively.
The significant items giving rise to the deferred income tax assets and
liabilities are as follows (in thousands):
<TABLE>
<CAPTION>
At December
31,
---------------
1998 1999
------- ------
<S> <C> <C>
Deferred income tax liabilities:
Basis differences in natural gas and oil properties... $20,193 $9,063
Other................................................. 138 56
------- ------
Total deferred income tax liabilities............... 20,331 9,119
Deferred income tax assets:
Net operating losses.................................. 20,789 9,304
Other................................................. 274 414
------- ------
Total deferred income tax assets.................... 21,063 9,718
Valuation allowance..................................... (732) (599)
------- ------
Net deferred income tax assets.......................... 20,331 9,119
------- ------
Net deferred income tax liabilities..................... $ -- $ --
======= ======
</TABLE>
The difference between the provision for income taxes and the amount that
would be determined by applying the statutory federal income tax rate of 35%
to the loss before income taxes is analyzed as below (in thousands):
<TABLE>
<CAPTION>
For the Year
Ended
December 31,
--------------
1998 1999
------- -----
<S> <C> <C>
Federal income tax benefit at statutory rates............ $(2,400) $(468)
Non-deductible compensation expense ..................... -- 558
Increase in non-deductible expenses and other............ -- 43
Increase resulting from change in tax status............. 1,668 --
Valuation allowance...................................... 732 (133)
------- -----
Total provision........................................ $ -- $ --
======= =====
</TABLE>
11. Commitments and Contingencies:
The Company is, from time to time, party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters
to have a materially adverse effect on the financial position, results of
operations or cash flows of the Company.
53
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Seismic Data Agreement
The Company has agreed to purchase $2,000,000 of seismic related services
from PGS prior to December 31, 2002. The Company paid to PGS approximately
$59,000, $122,000 and $318,000 in 1997, 1998 and 1999, respectively, for
seismic-related services.
Employment Contracts
As of December 31, 1997, 1998 and 1999, the Company had employment contracts
with its chief executive officer and chief financial officer which provide for
annual base salaries, bonus compensation and various benefits. The contracts
provide for the continuation of salary and benefits for the respective terms
of the agreements in the event of termination of employment for various
reasons, and whether by the Company or the employee. These agreements
initially expire on December 31, 2000, but are subject to automatic annual
extensions unless terminated. Compensation expense pertaining to officers of
the Company is charged to general and administrative expense.
Employee 401(k) Retirement Plan
In July 1998, the Company instituted a 401(k) retirement and profit sharing
plan ("Plan") for its employees. The Plan provides that all qualified
employees may defer the maximum income allowed under current tax law. The Plan
covers all employees at least 21 years of age who have completed at least six
months of service subsequent to employment. The Company may make discretionary
contributions allocated to eligible participants. No discretionary
contributions were made in 1998 and 1999.
Leases
The Company leases administrative offices under non-cancelable operating
leases expiring in 2002. Certain of the lease agreements require that the
Company pay for utilities, maintenance and other operational expenses of the
building. Additionally, the leases contain escalation clauses. Minimum future
obligations under non-cancelable operating leases at December 31, 1999 for the
following five years are $435,000, $444,000, $190,000, $12,000 and $11,000,
respectively.
54
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
12. Pro Forma Financial Information (Unaudited)
The pro forma condensed consolidated statements of operations for the years
ended December 31, 1998 and 1999 assume the completion of the initial public
offering, the conversion of each share of Preferred Stock into two shares of
Common Stock, the reinvestment of Preferred Stock dividends into shares of
Common Stock and the retirement of all outstanding debt occurred on January 1,
1998 and 1999, respectively, and are as follows (in thousands, except per
share data):
<TABLE>
<CAPTION>
For the Year
Ended December
31,
----------------
1998 1999
------- -------
(Pro Forma)
<S> <C> <C>
Revenues..................................................... $ 3,298 $34,258
Expenses..................................................... 10,100 32,923
------- -------
Income (loss) from operations................................ (6,802) 1,335
Other income (expense)....................................... 458 (269)
------- -------
Income (loss) before income taxes............................ (6,344) 1,066
Income tax provision....................................... -- --
------- -------
Income (loss) before cumulative effect of change in
accounting principle........................................ (6,344) 1,066
Cumulative effect of change in accounting principle........ -- (395)
------- -------
Pro forma net income (loss).................................. $(6,344) $ 671
======= =======
Pro forma basic income (loss) per common share:
Income (loss) before cumulative effect of change in
accounting principle...................................... $ (0.45) $ 0.05
Cumulative effect of change in accounting principle........ -- (0.02)
------- -------
Pro forma net income (loss) per common share................. $ (0.45) $ 0.03
======= =======
Pro forma diluted income (loss) per common share:
Income (loss) before cumulative effect of change in
accounting principle...................................... $ (0.45) $ 0.05
Cumulative effect of change in accounting principle........ -- (0.02)
------- -------
Pro forma net income (loss) per common share................. $ (0.45) $ 0.03
======= =======
Pro forma weighted average number of common shares
outstanding:
Basic...................................................... 14,078 19,274
======= =======
Diluted.................................................... 14,078 19,926
======= =======
</TABLE>
The pro forma condensed consolidated statement of operations for the year
ended December 31, 1998 reflects adjustments of approximately $516,000 to
eliminate interest expense as a result of the retirement of all outstanding
debt and $7.1 million to eliminate dividends as a result of the conversion of
each share of Preferred Stock into two shares of Common Stock.
The pro forma condensed consolidated statement of operations for the year
ended December 31, 1999 reflects adjustments of approximately $3.0 million and
$966,000 to eliminate interest expense and capitalized interest as a result of
the retirement of all outstanding debt and $7.9 million to eliminate dividends
as a result of the conversion of each share of Preferred Stock into two shares
of Common Stock.
The pro forma weighted average number of common shares outstanding includes
adjustments for the issuance of Common Stock in connection with the initial
public offering, the conversion of each share of Preferred Stock into two
shares of Common Stock, the reinvestment of Preferred Stock dividends into
shares of Common Stock and an adjustment to shares issued to PGS and Warburg
as consideration for providing guarantees under the Credit Agreement.
55
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
13. Quarterly Financial Data (Unaudited):
Quarterly operating results for the years ended December 31, 1998 and 1999
are summarized as follows (in thousands, except per share amounts):
<TABLE>
<CAPTION>
For the Quarter Ended
----------------------------------------------
March 31, June 30, September 30, December 31,
--------- -------- ------------- ------------
(Unaudited)
<S> <C> <C> <C> <C>
1998:
Revenues....................... $ 249 $ 712 $ 603 $ 1,734
Loss from operations........... (1,015) (2,002) (470) (3,315)
Net loss....................... (959) (1,925) (426) (3,550)
Net loss available to common
stockholders.................. (1,854) (3,528) (2,549) (6,023)
Net loss per basic and diluted
common share.................. $ (0.46) $ (0.87) $ (0.63) $ (1.48)
1999:
Revenues....................... $ 1,839 $ 7,744 $10,300 $14,375
Income (loss) from operations.. (1,193) (2,019) 1,321 3,226
Net income (loss).............. (2,009) (2,886) 249 3,309
Net income (loss) available to
common stockholders........... (4,502) (5,481) (2,453) 3,188
Net income (loss) per basic and
diluted common share.......... $ (1.10) $ (1.33) $ (1.48) $ 0.16
</TABLE>
The fourth quarter of 1998 includes a write-down of natural gas and oil
properties of $2.6 million. The first quarter of 1999 includes a charge of
$395,000 related to a change in accounting principle associated with
previously capitalized organization costs. The second quarter of 1999 includes
compensation expense of approximately $1.7 million related to the stock
appreciation rights of two of the Company's officers' stock option agreements.
See Note 6. The 1998 and first two quarters of 1999 net loss per share amounts
have been retroactively adjusted for the Stock Split.
For purposes of the diluted earnings per share calculation, the Preferred
Stock and stock options are considered anti-dilutive and are therefore not
considered in the net loss per share calculations.
56
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
14. Supplementary Financial Information on Natural Gas and Oil Exploration,
Development and Production Activities (Unaudited):
The following tables set forth certain historical costs and operating
information related to the Company's natural gas and oil producing activities.
Capitalized Costs and Costs Incurred
Capitalized costs and costs incurred related to natural gas and oil
producing activities are summarized below (in thousands):
<TABLE>
<CAPTION>
For the Year
Ended December
31,
-----------------
1998 1999
------- --------
<S> <C> <C>
Capitalized costs:
Proved properties......... $71,091 $141,455
Unproved properties not
being amortized.......... 28,383 40,696
------- --------
Total................... 99,474 182,151
Accumulated depreciation,
depletion and
amortization............... (5,448) (26,236)
------- --------
Net capitalized costs... $94,026 $155,915
======= ========
</TABLE>
<TABLE>
<CAPTION>
For the Year Ended
December 31,
-----------------------
1997 1998 1999
------- ------- -------
<S> <C> <C> <C>
Property acquisition costs:
Unproved....................................... $ 4,458 $15,791 $13,911
Proved......................................... -- -- --
Exploration costs(a)............................. 7,116 46,620 45,152
Development costs(b)............................. 2,422 23,067 23,614
------- ------- -------
Total costs incurred......................... $13,996 $85,478 $82,677
======= ======= =======
</TABLE>
- --------
(a) Includes seismic data acquisitions of $1.4 million, $2.5 million and $10.5
million in 1997, 1998 and 1999, respectively.
(b) Includes costs of completions, platforms, facilities and pipelines
associated with exploratory wells.
Estimates of Proved Natural Gas and Oil Reserves
Proved natural gas and oil reserve quantities at December 31, 1997, 1998 and
1999, and the related discounted future net cash flows before income taxes are
based on estimates prepared by Ryder Scott Company, L.P., independent
petroleum consultants. Such estimates have been prepared in accordance with
guidelines established by the Commission.
Proved reserves are estimated quantities of natural gas and oil which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.
57
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company's net ownership in estimated quantities of proved natural gas
and oil reserves and changes in net proved reserves, all of which are located
in the Gulf of Mexico, are summarized below:
<TABLE>
<CAPTION>
Millions of Cubic
Feet of Natural Gas
at December 31,
-----------------------
1997 1998 1999
------ ------ -------
<S> <C> <C> <C>
Proved developed and undeveloped reserves--
Beginning of year.................................... -- 12,607 50,946
Extensions and discoveries......................... 12,677 40,014 43,270
Revisions of previous estimates.................... -- -- 7,776
Production......................................... (70) (1,675) (11,962)
------ ------ -------
End of year.......................................... 12,607 50,946 90,030
====== ====== =======
Proved developed reserves at the end of year........... 5,615 30,806 50,756
====== ====== =======
</TABLE>
<TABLE>
<CAPTION>
Barrels of Oil,
Condensate and Natural
Gas Liquids at
December 31,
---------------------------
1997 1998 1999
------- ------- ---------
<S> <C> <C> <C>
Proved developed and undeveloped reserves--
Beginning of year................................ -- 125,128 470,023
Extensions and discoveries..................... 125,230 356,982 2,039,245
Revisions of previous estimates................ -- -- 82,981
Production..................................... (102) (12,087) (180,417)
------- ------- ---------
End of year...................................... 125,128 470,023 2,411,832
======= ======= =========
Proved developed reserves at the end of year....... 46,122 318,087 384,276
======= ======= =========
</TABLE>
Standardized Measure
The standardized measure of discounted future net cash flows relating to the
Company's ownership interests in proved natural gas and oil reserves as of
year-end is shown below (in thousands):
<TABLE>
<CAPTION>
For the Year Ended
December 31,
---------------------------
1997 1998 1999
------- -------- --------
<S> <C> <C> <C>
Future cash inflows.............................. $31,086 $ 99,436 $275,539
Future operating expenses........................ (1,460) (16,562) (36,396)
Future development costs......................... (6,424) (18,059) (48,717)
------- -------- --------
Future net cash flows............................ 23,202 64,815 190,426
10% annual discount per annum.................... (4,221) (12,706) (38,862)
------- -------- --------
Standardized measure of discounted future net
cash flows (a).................................. $18,981 $ 52,109 $151,564
======= ======== ========
</TABLE>
- --------
(a) Net operating loss carryforwards and basis in natural gas and oil
properties have eliminated the requirement for future income taxes.
Future cash flows are computed by applying year-end prices of natural gas
and oil to year-end quantities of proved natural gas and oil reserves. Future
operating expenses and development costs are computed primarily by the
Company's petroleum engineers by estimating the expenditures to be incurred in
developing and producing the proved natural gas and oil reserves at the end of
the year, based on the year-end costs and assuming
58
<PAGE>
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
continuation of existing economic conditions. Future income taxes are based on
year-end statutory rates, adjusted for tax basis and applicable tax credits. A
discount factor of 10% was used to reflect the timing of future net cash
flows. The standardized measure of discounted future net cash flows is not
intended to represent the replacement cost or fair market value of the
Company's natural gas and oil properties. An estimate of fair value would also
take into account, among other things, the recovery of reserves not presently
classified as proved, anticipated future changes in prices and costs, and a
discount factor more representative of the time value of money and the risks
inherent in reserve estimates.
Changes in Standardized Measure
Changes in the standardized measure of future net cash flows relating to
proved natural gas and oil reserves are summarized below (in thousands):
<TABLE>
<CAPTION>
For the Year Ended
December 31,
--------------------------
1997 1998 1999
------- ------- --------
<S> <C> <C> <C>
Standardized measure, beginning of year............ $ -- $18,981 $ 52,109
Extensions and discoveries, net of related
costs........................................... 19,110 35,952 75,572
Sales of natural gas and oil produced, net of
production costs................................ (129) (2,824) (28,097)
Net changes in prices and production costs....... -- (4,329) 22,869
Change in future development costs............... -- 2,713 (1,957)
Development costs incurred during the period that
reduced future development costs................ -- 2,246 14,494
Revisions of quantity estimates.................. -- -- 13,624
Accretion of discount............................ -- 1,898 5,211
Change in production rates and other............. -- (2,528) (2,261)
------- ------- --------
Standardized measure, end of year.................. $18,981 $52,109 $151,564
======= ======= ========
</TABLE>
Sales of natural gas and oil, net of related operating expenses, are based
on historical pre-tax results. Sales of natural gas and oil properties,
extensions and discoveries, purchases of minerals in place and the changes due
to revisions in standardized variables are reported on a pretax discounted
basis, while the accretion of discount is presented on an after-tax basis.
59
<PAGE>
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description
------- -----------
<C> <S>
3.1* --Certificate of Incorporation of Spinnaker, as amended.
3.2* --Bylaws of Spinnaker.
4.1* --Specimen Common Stock certificate.
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* --Amended and Restated 1998 Spinnaker Stock Option Plan.
10.3* --Amended and Restated Stockholders Agreement by and among Spinnaker,
Warburg, Pincus Ventures, Petroleum Geo-Services, Roger L. Jarvis,
James M. Alexander, William D. Hubbard, Kelly M. Barnes and the
other stockholders of Spinnaker (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, as amended.
10.4.1** --Amended and Restated 364-Day Credit Agreement dated as of October
29, 1999 among Spinnaker Exploration Company, L.L.C., as borrower
and certain financial institutions, as lenders, Bank of Montreal, as
administrative agent and Credit Suisse First Boston, as
documentation agent.
10.5* --Form of Lock-Up Agreement.
10.6* --Employment Agreement between Spinnaker and Roger L. Jarvis dated
December 20, 1996, as amended.
10.7* --Employment Agreement between Spinnaker and James M. Alexander dated
December 20, 1996, as amended.
10.8* --Employment Agreement between Spinnaker and William D. Hubbard dated
February 24, 1997, as amended.
10.9* --Employment Agreement between Spinnaker and Kelly M. Barnes dated
February 24, 1997, as amended.
10.10* --1999 Spinnaker Stock Incentive Plan.
10.11* --1999 Spinnaker Employee Stock Purchase Plan.
10.12* --Form of Indemnification Agreement.
21.1* --Subsidiaries of Spinnaker Exploration Company.
23.1 --Consent of Arthur Andersen LLP.
23.2 --Consent of Ryder Scott Company, L.P.
27 --Financial Data Schedule.
</TABLE>
- --------
* Incorporated herein by reference to the exhibit filed with the Company's
Registration Statement on Form S-1 (Commission File No. 333-83093).
** Incorporated herein by reference to the exhibit filed with the Company's
Quarterly Report on Form 10-Q for the quarter ended September 30, 1999.
60
<PAGE>
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of
our report dated February 23, 2000, included in the Annual Report of Spinnaker
Exploration Company on Form 10-K for the year ended December 31, 1999, into
Spinnaker Exploration Company's previously filed Registration Statement No.
33-89779 on Form S-8.
ARTHUR ANDERSEN LLP
Houston, Texas
March 1, 2000
<PAGE>
Exhibit 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
We hereby consent to all references to Ryder Scott Company, L.P. and/or the
reports prepared by Ryder Scott Company, L.P. entitled, "Estimated Future
Reserves and Income Attributable to Certain Leasehold Interests SEC Case as of
December 31, 1997 and 1998" and "Estimated Future Reserves and Income
Attributable to Certain Leasehold and Royalty Interests SEC Case as of
December 31, 1999" in the Form 10-K for the year ended December 31, 1999.
RYDER SCOTT COMPANY, L.P.
March 1, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
This schedule contains summary financial information extracted from the
Consolidated Statements of Operations and the Consolidated Balance Sheets and is
qualified in its entirety by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 20,452
<SECURITIES> 0
<RECEIVABLES> 10,795
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 32,126
<PP&E> 185,865
<DEPRECIATION> 28,468
<TOTAL-ASSETS> 189,553
<CURRENT-LIABILITIES> 12,451
<BONDS> 0
0
0
<COMMON> 204
<OTHER-SE> 176,898
<TOTAL-LIABILITY-AND-EQUITY> 189,553
<SALES> 34,258
<TOTAL-REVENUES> 34,258
<CGS> 0
<TOTAL-COSTS> 5,411
<OTHER-EXPENSES> 27,512
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 2,805
<INCOME-PRETAX> (942)
<INCOME-TAX> 0
<INCOME-CONTINUING> (942)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> (395)
<NET-INCOME> (1,337)
<EPS-BASIC> (1.11)
<EPS-DILUTED> (1.11)
</TABLE>
