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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, 2002.
[_] 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 001-16009
SPINNAKER EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware 76-0560101
(State or other
jurisdiction of
incorporation or (I.R.S. Employer
organization) Identification No.)
1200 Smith Street, Suite
800
Houston, Texas 77002
(Address of principal
executive offices) (Zip Code)
(713) 759-1770
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Securities Exchange
Act of 1934:
Name of each exchange on
Title of each class which registered
------------------- -------------------------
Common Stock, par value
$0.01 per share New York Stock Exchange
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]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [_]
The aggregate market value of the voting and non-voting common equity held
by non-affiliates of the registrant on June 30, 2002 was approximately $943.6
million.
The number of shares outstanding of the registrant's Common Stock, par value
$0.01 per share, on March 25, 2003 was 33,193,944.
Parts of the registrant's Definitive Proxy Statement for its 2003 Annual
Meeting of Stockholders are incorporated by reference into Part III of this
annual report on Form 10-K.
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TABLE OF CONTENTS
Page
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PART I
Item 1. Business.............................................................................. 1
Item 2. Properties............................................................................ 14
Item 3. Legal Proceedings..................................................................... 17
Item 4. Submission of Matters to a Vote of Security Holders................................... 17
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................. 18
Item 6. Selected Financial Data............................................................... 19
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. 20
Item 7A. Quantitative and Qualitative Disclosures About Market Risk............................ 37
Item 8. Financial Statements and Supplementary Data........................................... 39
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.. 39
PART III
Item 10. Directors and Executive Officers of the Registrant.................................... 40
Item 11. Executive Compensation................................................................ 40
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters............................................................................. 40
Item 13. Certain Relationships and Related Transactions........................................ 41
Item 14. Controls and Procedures............................................................... 41
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K...................... 41
Signatures..................................................................................... 43
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Spinnaker Exploration Company ("Spinnaker" or the "Company") has provided
definitions for some of the natural gas and oil industry terms used in this
report in the "Glossary of Natural Gas and Oil Terms" on page 12.
Cautionary Statement About Forward-Looking Statements
Some of the information in this annual report on Form 10-K contains
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934 (the
"Exchange Act"). The forward-looking statements speak only as of the date made,
and the Company undertakes no obligation to update such forward-looking
statements. These forward-looking statements may be identified by the use of
the words "believe," "expect," "anticipate," "will," "contemplate," "would" and
similar expressions that contemplate future events. These future events include
the following matters:
. financial position;
. business strategy;
. budgets;
. amount, nature and timing of capital expenditures, including future
development costs;
. drilling of wells;
. natural gas and oil reserves;
. timing and amount of future production of natural gas and oil;
. operating costs and other expenses;
. cash flow and anticipated liquidity;
. prospect development and property acquisitions; and
. marketing of natural gas and oil.
Numerous important factors, risks and uncertainties may affect the Company's
operating results, including:
. the risks associated with exploration;
. delays in anticipated start-up dates;
. 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;
. downward revisions of proved reserves and the related negative impact on
the depreciation, depletion and amortization rate;
. production and reserves concentrated in a small number of properties;
. operating hazards attendant to the natural gas and oil business;
. drilling and completion risks, which costs are generally not recoverable
from third parties or insurance;
. potential mechanical failure or under-performance of significant wells;
. impact of weather conditions on timing and costs of operations;
. availability and cost of material and equipment;
. actions or inactions of third-party operators of the Company's properties;
. the ability to find and retain skilled personnel;
. availability of capital;
. the strength and financial resources of competitors;
. regulatory developments;
. environmental risks; and
. general economic conditions.
Any of the factors listed above and other factors contained in this annual
report could cause the Company's actual results to differ materially from the
results implied by these or any other forward-looking statements made by the
Company or on its behalf. The Company cannot provide assurance that future
results will meet its expectations. You should pay particular attention to the
risk factors and cautionary statements described under "Risk Factors" in "Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations."
ii
PART I
Item 1. Business
General
Spinnaker Exploration Company, a Delaware corporation, 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"). Spinnaker's
Chief Executive Officer, Warburg, Pincus Ventures, L.P. ("Warburg") and
Petroleum Geo-Services ASA ("PGS") formed Spinnaker in December 1996.
At December 31, 2002, the Company had license rights to approximately 14,000
blocks of mostly contiguous 3-D seismic data in the Gulf of Mexico. This
database covers an area of approximately 40 million acres, which the Company
believes is one of the largest 3-D seismic databases of any independent
exploration and production company in the Gulf of Mexico. As of December 31,
2002, the Company had 293 leasehold interests located in federal and Texas
state waters of the Gulf of Mexico covering approximately 1,293,000 gross and
742,000 net acres. Within its current inventory of leasehold interests, the
Company has identified and captured approximately 125 exploratory prospects.
Based on 3-D seismic analysis on blocks where it currently has no leasehold
interest, the Company also has identified over 200 leads that may result in
additional prospects. The Company believes its regional 3-D seismic approach
allows it to create and maintain a large inventory of high-quality prospects
and provides the opportunity to enhance its exploration success and efficiently
deploy its capital resources. The Company also believes its license rights to
large quantities of high-quality seismic data and its management and technical
staff are important factors for its current and future success.
From inception through December 31, 2002, the Company participated in
drilling 120 wells in the Gulf of Mexico resulting in 70 discoveries. As of
December 31, 2002, Ryder Scott Company, L.P. estimated the Company's net proved
reserves at approximately 323.6 Bcfe. Spinnaker's current capital expenditure
budget for 2003 is $250.0 million, including approximately $94.0 million for
exploration activities, $114.0 million for development activities, $38.0
million for leasehold acquisitions and geological and geophysical expenditures
and $4.0 million for other property and equipment. The Company currently plans
to drill 18 wells on the shelf and 14 wells in the deep water in 2003.
Exploration and development in deep water requires significant capital
commitments. If the Company is successful in its deepwater exploration efforts
in 2003, currently budgeted capital requirements for development activities in
2003 will increase.
Spinnaker has a 25% non-operator working interest in a significant deepwater
oil discovery on Green Canyon Blocks 338/339 ("Front Runner"). The Company
participated in six consecutive successful wells and sidetracks to test the
reservoirs on these blocks through December 31, 2002. Of the Company's total
proved reserves as of December 31, 2002, 70% were proved undeveloped reserves.
Front Runner represented more than 60% of total proved undeveloped reserves.
Spinnaker has incurred capital expenditures associated with Front Runner of
$70.2 million through December 31, 2002 and expects to incur an aggregate of
approximately $67.0 million in future development costs during 2003 and 2004.
First production is anticipated during the summer of 2004.
On April 3, 2002, the Company completed a public offering of 5,750,000
shares of common stock, par value $0.01 per share ("Common Stock"), at $41.50
per share, including the over-allotment option consisting of 750,000 shares.
After payment of underwriting discounts and commissions, the Company received
net proceeds of $227.9 million. On April 3, 2002, the Company used a portion of
the proceeds from the offering to repay outstanding borrowings of $37.0
million. The remaining net proceeds were invested in short-term high quality
investments and used to fund a portion of the costs to develop Front Runner, to
fund a portion of exploration and other development activities and for general
corporate purposes.
Spinnaker files reports with the Securities and Exchange Commission
("Commission") on Forms 10-K, 10-Q and 8-K. The public may read and copy any
materials that the Company files with the Commission at the
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Commission's public reference room. The public may also access Spinnaker's
annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on
Form 8-K and all amendments to those reports filed or furnished to the
Commission pursuant to Section 13(a) or 15(d) of the Exchange Act on its
internet website at www.spinnakerexploration.com, free of charge, as soon as
reasonably practicable after Spinnaker electronically files or furnishes such
material with or to the Commission.
Business Strategy
Spinnaker's goals are to expand its reserve base, increase 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 while maintaining a
conservative balance sheet.
Focus on the Gulf of Mexico. Spinnaker has assembled a large 3-D seismic
database and focuses its exploration activities exclusively in the Gulf of
Mexico because it believes this area represents one of the most attractive
exploration regions in North America. The Gulf of Mexico has the following
characteristics that make it attractive to exploration and production companies:
. Prolific exploration and production history
. Access to acreage
. Existing oilfield service infrastructure
. Attractive taxation and royalty rates
. Relatively high-productivity wells
. Transportation infrastructure with geographic proximity to well-developed
markets for natural gas and oil
. Geologic diversity that offers a variety of exploration opportunities.
The Company also believes its geographic focus provides an excellent
opportunity to develop and maintain competitive advantages through the
combination of its 3-D seismic database and regional exploration and operating
expertise.
Maintain a large database of 3-D seismic data. Spinnaker believes its large
database of original and reprocessed 3-D seismic data allows it to generate and
maintain a large inventory of high-quality exploratory prospects. The Company's
3-D seismic database serves as the foundation for its exploration program. The
Company will continue to supplement this database with 3-D seismic data
acquisitions from various seismic data vendors and upgrade and improve the
existing 3-D seismic data through reprocessing.
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 existing well control. Through this process,
the Company enhances its understanding of the geology before selecting
prospects and increases the probability of accurately identifying
hydrocarbon-bearing zones.
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Emphasize technical expertise. Spinnaker's 15 explorationists have an
average of over 20 years experience in exploration in the Gulf of Mexico.
Spinnaker also has a team of six technical specialists with significant
experience in reprocessing seismic data, petrophysics and geologic modeling and
inversion. In its efforts to attract and retain explorationists and technical
specialists, the Company offers an entrepreneurial culture, an extensive 3-D
seismic database, state-of-the-art computer-aided exploration technology and
other technical tools.
Spinnaker generally retains larger working interests in prospects located in
water depths of less than 2,000 feet. The combination of larger working
interests and its technical expertise has allowed the Company to act as the
operator for a majority of these prospects, providing more control of costs,
the timing and amount of capital expenditures and the selection of technology.
Sustain a balanced, diversified exploration effort while maintaining a
conservative balance sheet. Spinnaker believes that its exploration approach
results in portfolio balance and diversity among:
. shallow water, or water depths of less than 600 feet, and deepwater
prospects;
. shallow drilling depth prospects and deep drilling depth prospects; and
. lower-risk, lower-potential prospects and higher-risk, higher-potential
prospects.
The broad coverage of the Gulf of Mexico by the Company's 3-D seismic data
allows it to participate in a variety of geologically diverse exploration
opportunities and to create a diversified prospect portfolio. The Company
intends to manage its exposure in deepwater exploration activities by focusing
on prospects where commercial feasibility of the prospect can be evaluated with
a small number of wells and where it believes 3-D seismic analysis provides
attractive risk/reward benefits. The Company also strives to diversify its
exploration efforts by seeking to limit the budgeted amount of the leasehold
acquisition and drilling costs of the first exploratory well on any one
prospect to less than 10% of the annual capital budget.
The Company believes that maintaining continuity in its exploration activity
during all phases of the commodity price cycles is an important element to
balance and diversification. By positioning the Company to have a continuous
exploration program, it can potentially take advantage of reduced competition
for prospects and lower drilling and other oilfield service costs during
periods of low natural gas and oil prices. Drilling deep depth prospects and
drilling in deep water is inherently more risky than drilling shallow depth
prospects and drilling in shallow water. Spinnaker's emphasis on maintaining a
lower debt-to-capitalization ratio than many of its peers has enhanced its
ability to pursue this strategy.
Seismic Data Agreements
Data Covered by Seismic Data Agreements
The initial data agreement with PGS provided Spinnaker with a minimum of
approximately 3,700 blocks of 3-D seismic data. The Company has acquired an
additional 10,300 blocks of standard and enhanced 3-D seismic data from various
seismic contractors, including approximately 3,900 blocks from PGS. The
Company's 3-D seismic database included a total of approximately 8,300 blocks
of standard data and 5,700 blocks of enhanced data as of December 31, 2002.
Seismic contractors acquire both proprietary and multi-client marine seismic
data. When a seismic contractor acquires proprietary data, it does so on an
exclusive contractual basis for its customers. When a seismic contractor
acquires multi-client data, it owns the data itself and licenses the possession
and use of copies of the data to the industry at large for a fee. Most of the
standard data that Spinnaker is entitled to use is multi-client seismic data.
Some of Spinnaker's enhanced data is proprietary, internally-reprocessed
seismic data.
Standard data is the basic 3-D, post-stack time-migrated seismic data
provided as the standard product to customers by seismic contractors. Enhanced
data is created through additional computer processing of standard data and
includes processed data referred to as pre-stack depth-migrated data, 3-D
amplitude versus offset
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processing, refined pre-stack time-migrated data and several seismic attributes
used for geologic delineation, rock property analysis and pore pressure
prediction.
Rights to Use the Data
In general, the Company may use the multi-client data from its seismic
contractors 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;
. to make maps and other work products from the data;
. to 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 are held
in confidence by those individuals; and
. to 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 are held in confidence by those
individuals.
The data agreements provide that the Company's rights to use the seismic
data continue for at least 25 years from the date of purchase subject to
certain termination provisions discussed below. The data the Company receives
under any data agreement remains the property of that seismic contractor
subject to the rights granted to the Company in the data agreement.
Restrictions on Transfer and Assignment
The various seismic data agreements provide provisions for transfer of data
licenses in the event the Company merges with or is acquired by another
company. In some cases, the Company will incur fees for the transfer of these
licenses.
Termination Events
In general, a seismic contractor may terminate substantially all of the
Company's rights under a data agreement by giving Spinnaker notice after the
occurrence of certain events, such as:
. the Company transfers data or its rights under the data agreement in
violation of the data agreement;
. a competitor of the seismic contractor acquires control of the Company;
. a second major customer of the seismic contractor acquires control of the
Company after an initial major customer of the seismic contractor has
previously acquired control of the Company;
. the Company knowingly breaches one of the provisions of the data
agreement relating to the use, transfer or disclosure of the data;
. the Company unknowingly breaches one of the previously mentioned
provisions of the data agreement 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 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.
4
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 3-D seismic data, as well as 2-D data in some cases, with
respect to a potential drilling location and correlating that data with
historical well control and production data from similar properties. The
available data is then analyzed using computer software and modeling techniques
to project the likely geologic setting of a potential drilling location and
potential locations of undiscovered natural gas and oil reserves. This process
relies on a comparison of actual data for the potential drilling location and
historical data for the density and sonic characteristics of different types of
rock formations, hydrocarbons and other subsurface minerals, resulting in a
projected 3-D image of the subsurface. This modeling is performed through the
use of advanced interactive computer workstations and various combinations of
available computer software developed solely for this application.
The Company has invested extensively in the advanced computer hardware and
software necessary for 3-D seismic exploration. 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.
Marketing
The Company sells its natural gas and oil production under fixed or floating
market price contracts. Revenues, profitability, cash flow and future growth
depend substantially on prevailing prices for natural gas and oil. The prices
received by the Company for its natural gas and oil production fluctuates
widely. For example, natural gas prices increased significantly in the second
half of 2002 after a sharp decline in 2001 from levels reached in the second
half of 2000 and early 2001. Oil prices have also increased recently as
compared to prior 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 and actual or threatened acts of war, terrorism or
hostilities in 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, 2002, sales to Duke Energy
Trade and Marketing LLC, Cinergy Marketing & Trading LP, Equiva Trading Company
and Kinder Morgan Ship Channel Pipeline LP accounted for approximately 52%,
13%, 11% and 11%, respectively, of the Company's natural gas and oil revenues,
excluding the effects of hedging activities. For the year ended December 31,
2001, sales to Enron North America Corp., Tejas Gas Marketing, LLC, Reliant
Energy Services, Inc. and Bridgeline Gas Marketing LLC accounted for
approximately 32%, 23%, 21% and 17%, respectively, of the Company's natural gas
and oil revenues, excluding the effects of hedging activities. For the year
ended December 31, 2000, sales to Enron North America Corp., Coral Energy
Resources, L.P. and Reliant Energy Services, Inc. accounted for approximately
61%, 11% and 11%, respectively, of the Company's natural gas and oil revenues,
excluding the effects of hedging activities. Spinnaker no longer sells its
natural gas and oil production to Enron North America Corp. Spinnaker believes
the loss of this customer has not materially affected its ability to market its
natural gas and oil production.
Customers purchase all of the Company's natural gas production at current
market prices. The terms of the arrangements require the customers to pay the
Company within 60 days after delivery of the production. As a result, if the
customers were to default on their payment obligations to the Company,
near-term earnings and cash flows would be adversely affected. However, due to
the availability of other markets and pipeline connections, the Company does
not believe that the loss of these customers or any other single customer would
adversely affect its ability to market production.
5
Spinnaker enters into hedging arrangements from time to time to reduce its
exposure to fluctuations in natural gas and oil prices and to achieve more
predictable cash flow. However, these contracts also limit the benefits the
Company would realize if prices increase. These financial arrangements take the
form of swap contracts or cashless collars and are placed with major trading
counterparties the Company believes represent minimal credit risks. Spinnaker
cannot provide assurance that these trading counterparties will not become
credit risks in the future. For further information concerning Spinnaker's
hedging transactions, see "Item 7A. Quantitative and Qualitative Disclosures
about Market Risk." Under its current hedging policy, the Company generally
does not hedge more than 66 2/3% of its estimated twelve-month production
quantities without the prior approval of the risk management committee of the
board of directors.
Competition
The Company competes with major and independent natural gas and oil
companies for leasehold acquisitions. Spinnaker also competes for the equipment
and labor required to operate and develop these properties. Most of the
Company's competitors have substantially greater financial and other resources.
As a result, in the deep water where exploration is more expensive, competitors
may be better able to withstand sustained periods of unsuccessful drilling. In
addition, larger competitors may be able to absorb the burden of any changes in
federal, state and local laws and regulations more easily than Spinnaker can,
which would adversely affect Spinnaker's 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 that
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. The FERC continues to review and modify its regulations
regarding the transportation of natural gas. In 2000, the FERC issued Order No.
637 and subsequent orders, which Spinnaker refers to collectively as "Order No.
637." Order No. 637 imposes a number of additional reforms designed to enhance
competition in natural gas markets. Among other things, Order No. 637 revised
the FERC pricing policy
6
by waiving price ceilings for short-term released capacity for a two-year
period ending September 30, 2002, and effected changes in the FERC regulations
relating to scheduling procedures, capacity segmentation, pipeline penalties,
rights of first refusal and information reporting. Several parties subsequently
filed appeals in the Court of Appeals for the District of Columbia Circuit
("D.C. Circuit") seeking court review of various aspects of Order 637,
particularly (i) the right of customers to segment their contractual capacity
in a manner that allows a forwardhaul/backhaul to a single point and (ii) the
rights of first refusal granted to existing customers to extend contracts
beyond the end of the contract's term. On April 5, 2002, the D.C. Circuit
generally affirmed Order No. 637 but remanded certain issues to the FERC,
including the forwardhaul/backhaul and the rights of first refusal issues. The
FERC on remand affirmed its position on the forwardhaul/backhaul issue but
reversed itself on the rights of first refusal issue. Requests for rehearing of
this order are currently pending at the FERC.
Order No. 637 also required interstate natural gas pipelines to implement
the policies mandated by the order through individual compliance filings. The
FERC has now ruled on a number of the individual compliance filings, although
its decisions in such proceedings remain subject to the outcome of pending
rehearing requests and possible court appeals.
In addition, the FERC implemented new regulations governing the procedure
for obtaining authorization to construct new pipeline facilities and has issued
a policy statement, which it largely affirmed in recent orders on rehearing,
establishing a presumption in favor of requiring owners of new pipeline
facilities to charge rates based solely on the costs associated with such new
pipeline facilities. The Company cannot predict what further action the FERC
will take on these matters, nor can it accurately predict whether the FERC's
actions will achieve the goal of increasing competition in markets in which
natural gas is sold. However, the Company does not believe that any action
taken will affect it in a way that materially differs from the way it affects
other natural gas producers, gatherers and marketers.
The Outer Continental Shelf Lands Act ("OCSLA") requires that all pipelines
operating on or across the Outer Continental Shelf provide open-access,
non-discriminatory service. Although the FERC has opted not to impose the
regulations of Order No. 509, in which the FERC implemented the OCSLA, on
gatherers and other non-jurisdictional entities, the FERC has retained the
authority to exercise jurisdiction over those entities if necessary to permit
non-discriminatory access to service on the Outer Continental Shelf. The FERC
recently issued Order No. 639, requiring that virtually all non-proprietary
pipeline transporters of natural gas on the Outer Continental Shelf report
information on their affiliations, rates and conditions of service. Among the
FERC's stated purposes in issuing such rules was the desire to provide shippers
on the Outer Continental Shelf with greater assurance of open-access services
on pipelines located on the Outer Continental Shelf and non-discriminatory
rates and conditions of service on such pipelines. A federal district court
determined that the FERC has exceeded its statutory authority in promulgating
Order Nos. 639 and 639-A, and the court permanently enjoined the FERC from
enforcing the orders. The FERC's appeal of the district court's decision is
currently pending at the D.C. Circuit.
Additional proposals and proceedings that might affect the natural gas
industry are pending before Congress, the FERC and the courts. The natural gas
industry historically has been very heavily regulated; therefore, there is no
assurance that the less stringent regulatory approach recently pursued by the
FERC and Congress will continue.
Federal Leases
A substantial portion of the Company's operations is located on federal
natural gas and oil leases, which are administered by the Minerals Management
Service ("MMS"). Such leases are issued through competitive bidding, contain
relatively standardized terms and require compliance with detailed MMS
regulations and orders pursuant to the OCSLA that 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,
7
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. Similarly, the MMS has promulgated other
regulations governing the plugging and abandonment of wells located offshore
and the installation and removal of all production facilities. To cover the
various obligations of lessees on the Outer Continental Shelf, the MMS
generally requires that lessees have substantial net worth or post bonds or
other acceptable assurances that such obligations will be met. The cost of
these bonds or other surety can be substantial, and there is no assurance that
bonds or other surety can be obtained in all cases. The Company is currently in
compliance with the bonding requirements of the MMS. Under some circumstances,
the MMS may require any of the Company's operations on federal leases to be
suspended or terminated. Any such suspension or termination could materially
adversely affect the Company's financial condition and results of operations.
The MMS has issued a final rule that governs the calculation of royalties
and the valuation of crude oil produced from federal leases. This rule amends
the way that the MMS values crude oil produced from federal leases for
determining royalties by eliminating posted prices as a measure of value and
relying instead on arm's-length sales prices and spot market prices as
indicators of value. The lawfulness of the new rule has been challenged at the
D.C. Circuit. The Company cannot predict whether this new rule will be upheld
in federal court, nor can the Company predict whether the MMS will take further
action on this matter. The Company believes this rule will not have a material
impact on its financial condition, liquidity or results of operations.
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 occasionally may conduct operations in the
state waters offshore Louisiana and 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
disposal of waste materials, unitization and pooling of natural gas and oil
properties and establishment of maximum rates of production from natural gas
and oil wells. Some states prorate production to the market demand for natural
gas and oil.
Oil Price Controls and Transportation Rates
Sales of crude oil, condensate and natural gas liquids by the Company are
not currently regulated and are made at market prices. The price the Company
receives from the sale of these products may be affected by the cost of
transporting the products to market. Effective as of January 1, 1995, the FERC
implemented regulations generally grandfathering all previously unchallenged
interstate transportation rates and establishing an indexing system for those
rates by which adjustments are made annually based on the rate of inflation,
subject to certain conditions and limitations. As required by its own
regulations, in July 2000, the FERC issued a Notice of Inquiry seeking comment
on whether to retain or to change the existing methodology underlying its then
current indexing system, which was based on the Producer Price Index for
Finished Goods ("PPI-FG") minus one percent. In December of 2000, the FERC
issued an order concluding that the PPI-FG minus one percent methodology
reasonably estimated the actual cost changes in the pipeline industry and
should be continued for another five-year period, subject to review in July
2005. In February 2003, on remand of its December 2000 order from the D.C.
Circuit, the FERC changed the rate indexing methodology to the PPI-FG, but
without the subtraction of 1% as had been done previously. The FERC made the
change prospective only, but did allow oil pipelines to recalculate their
maximum ceiling rates as though the new rate indexing methodology had been in
effect since July 1, 2001. The FERC's regulation of oil transportation rates
may tend to increase the cost of transporting oil and natural gas liquids by
interstate pipeline, although the annual adjustments may result in decreased
rates in a given year. The Company is unable at this time to predict the
effects of these regulations, if any, on the transportation costs associated
with oil production from its properties. However, the Company does not believe
that these regulations affect it any differently than other producers.
8
Environmental Regulations
The Company's operations are subject to numerous stringent and complex laws
and regulations at the federal, state and local levels governing the discharge
of materials into the environment or otherwise relating to environmental
protection. These laws and regulations may:
. require acquisition of a permit before drilling commences;
. restrict the types, quantities and concentrations of various materials
that can be released into the environment in connection with drilling and
production activities;
. limit or prohibit construction or drilling activities in certain
ecologically sensitive and other protected areas;
. require remedial action to prevent pollution from former operations; and
. impose substantial liabilities for pollution resulting from the Company's
operations.
Failure to comply with these laws and regulations may result in the assessment
of administrative, civil and criminal penalties, imposition of remedial
requirements and the imposition of injunctions to force future compliance.
Moreover, 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 imposes strict, joint and several liability on
responsible parties for oil removal costs and a variety of public and private
damages, including natural resource damages. While liability limits apply in
some circumstances, a party cannot take advantage of liability limits if the
spill was caused by gross negligence or willful misconduct or resulted from
violation of a federal safety, construction or operating regulation. If the
party fails to report a spill or to cooperate fully in the cleanup, liability
limits likewise do not apply. Even if applicable, the liability limits for
offshore facilities require the responsible party to pay all removal costs,
plus up to $75.0 million in other damages. Few defenses exist to the liability
imposed by the OPA.
The OPA also requires a responsible party to submit proof of its financial
ability to cover environmental cleanup and restoration costs that could be
incurred in connection with an oil spill. As amended by the Coast Guard
Authorization Act of 1996, the OPA requires parties responsible for offshore
facilities to provide financial assurance in the amount of $35.0 million to
cover potential OPA liabilities. This amount can be increased up to $150.0
million in certain limited circumstances where the MMS believes such an amount
is justified based on the operational, environmental, human health and other
risks posed by the quantity or quality of oil that is explored for, drilled for
or produced by the responsible party. The Company is in compliance with its
financial assurance obligations.
The OPA also imposes other requirements, such as the preparation of oil
spill response plans. The Company has such plans 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 administrative, civil
or criminal enforcement actions.
9
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.
The Comprehensive Environmental Response, Compensation, and Liability Act
("CERCLA"), also known as the "Superfund" law, and analogous state laws impose
liability, without regard to fault or the legality of the original conduct, on
some classes of persons that are considered to have contributed to the release
of a "hazardous substance" into the environment. These persons include the
owner or operator of the disposal site or sites where the release occurred and
companies that disposed or arranged for the disposal of the hazardous
substances found at the site. Persons who are or were responsible for releases
of hazardous substances under the CERCLA may be subject to joint and several
liability for the costs of cleaning up the hazardous substances that have been
released into the environment and for damages to natural resources.
Additionally, it is not uncommon for neighboring landowners and other third
parties to file tort claims for personal injury and property damage allegedly
caused by the hazardous substances released into the environment.
The Company's operations are also subject to regulation of air emissions
under the Clean Air Act, comparable state and local requirements and the OCSLA.
Future regulations under these laws could lead to the gradual imposition of new
air pollution control requirements on the Company's operations. The Company
does not believe that its operations would be materially affected by any such
requirements, nor does it expect such requirements to be any more burdensome to
it than to other companies of its size involved in natural gas and oil
exploration and production activities.
In addition, legislation has been proposed in Congress from time to time
that would reclassify some natural gas and oil exploration and production
wastes as "hazardous wastes," which would make the reclassified wastes subject
to 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.
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 its results of operations.
Operating Hazards and Insurance
The natural gas and oil business involves a variety of operating risks,
including fires, explosions, blow-outs and surface cratering, uncontrollable
flows of underground natural gas, oil and formation water, natural disasters,
pipe or cement failures, casing collapses, embedded oilfield drilling and
service tools, abnormally pressured formations and environmental hazards such
as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic
gases. If any of these events occur, the Company could incur substantial losses
as a result of injury or loss of life, severe damage to and destruction of
property, natural resources and equipment, pollution and other environmental
damage, clean-up responsibilities, regulatory investigation and penalties,
suspension of the Company's operations and repairs to resume operations. If the
Company experiences any of these problems, it could affect well bores,
platforms, gathering systems and processing facilities, which could adversely
affect its ability to conduct operations.
As part of its strategy, the Company explores for natural gas and oil in the
deep waters of the Gulf of Mexico where operations are more difficult than in
shallower waters. The Company's deepwater drilling and operations require the
application of recently developed technologies that involve a higher risk of
mechanical failure. Furthermore, the deep waters of the Gulf of Mexico lack the
physical and oilfield service infrastructure present in the shallower waters.
As a result, deepwater 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 risks involved with these operations.
10
Offshore operations are also subject to a variety of operating risks
specific 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. Management reviews
Spinnaker's coverage at least annually. 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, 2002, the Company had 65 full-time employees. The Company
believes that it maintains excellent relationships with its employees. 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.
11
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, of crude oil
or other liquid hydrocarbons.
Bcf. Billion cubic feet of natural gas.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Block. A block depicted on the Outer Continental Shelf Leasing and Official
Protraction Diagrams issued by the U.S. Minerals Management Service or a
similar depiction on official protraction or similar diagrams issued by a state
bordering on the Gulf of Mexico.
Btu or British Thermal Unit. The quantity of heat required to raise the
temperature of one pound of water by one degree Fahrenheit.
Completion. The installation of permanent equipment for the production of
natural gas or oil, or in the case of a dry hole, the reporting of abandonment
to the appropriate agency.
Condensate. Liquid hydrocarbons associated with the production of a
primarily natural gas reserve.
Developed acreage. The number of acres that are allocated or assignable to
productive wells or wells capable of production.
Development well. A well drilled into a proved natural gas or oil reservoir
to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in
sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce natural gas or oil
reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of natural gas or oil in another reservoir or
to extend a known reservoir.
Farm-in or farm-out. An agreement under which the owner of a working
interest in a natural gas and oil lease assigns the working interest or a
portion of the working interest to another party who desires to drill on the
leased acreage. Generally, the assignee is required to drill one or more wells
in order to earn its interest in the acreage. The assignor usually retains a
royalty or reversionary interest in the lease. The interest received by an
assignee is a "farm-in" while the interest transferred by the assignor is a
"farm-out."
Field. An area consisting of either a single reservoir or multiple
reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.
Lead. A specific geographic area which, based on supporting geological,
geophysical or other data, is deemed to have potential for the discovery of
commercial hydrocarbons.
12
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
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 interests owned
in gross acres or wells, as the case may be.
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 individual and separate from other
reservoirs.
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of natural gas and oil regardless of whether or not 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.
13
Item 2. Properties
Since inception, the Company has concentrated on the exploration for natural
gas and oil exclusively in the Gulf of Mexico. As of December 31, 2002, proved
reserves associated with Spinnaker's discoveries were located on 30 different
blocks, including one property in which the Company has only a royalty
interest, with production established from 26 blocks. Spinnaker operates 41 of
its 70 discoveries, and the Company's working interests in these wells range
from 12.5% to 100%. Six blocks account for approximately 73% of the Company's
total proved reserves.
As of December 31, 2002, the Company had license rights to approximately
14,000 blocks of mostly contiguous 3-D seismic data in the Gulf of Mexico. This
database covers an area of approximately 40 million acres, which the Company
believes is one of the largest 3-D seismic databases of any independent
exploration and production company in the Gulf of Mexico. As of December 31,
2002, the Company had 293 leasehold interests located in federal and Texas
state waters of the Gulf of Mexico covering approximately 1,293,000 gross and
742,000 net acres.
Natural Gas and Oil Reserves
Spinnaker has a 25% non-operator working interest in its significant
deepwater oil discovery at Front Runner. The Company participated in six
consecutive successful wells and sidetracks in testing the reservoirs on these
blocks through December 31, 2002. Of the Company's total proved reserves as of
December 31, 2002, 70% were proved undeveloped reserves. Front Runner
represented more than 60% of total proved undeveloped reserves.
The following table presents estimated net proved natural gas and oil
reserves and the related net present value of the reserves at December 31, 2002
as prepared by Ryder Scott Company, L.P. The present value of future net cash
flows (before income taxes) discounted at 10% and the standardized measure of
discounted future net cash flows shown in the table are not intended to
represent the current market value of the estimated natural gas and oil
reserves Spinnaker owns. For further information concerning the present value
of future net cash flows associated with these proved reserves, see Note 14 of
the Notes to Consolidated Financial Statements.
The present value of future net cash flows and the standardized measure of
discounted future net cash flows as of December 31, 2002 was determined by
using prices of $4.91 per Mcf of natural gas and $30.50 per barrel of oil as of
December 31, 2002.
Proved Reserves
------------------------------
Developed Undeveloped Total
--------- ----------- --------
Natural gas (MMcf).......................................... 84,139 59,392 143,531
Oil and condensate (MBbls).................................. 2,219 27,789 30,008
Total proved reserves (MMcfe)............................... 97,456 226,121 323,577
Present value of future net cash flows (before income taxes)
discounted at 10% (in thousands)(1)....................... $323,426 $523,847 $847,273
Standardized measure of discounted future net cash flows (in
thousands)(1)............................................. $259,878 $420,920 $680,798
--------
(1) Excludes pre-tax unrealized losses of $19.9 million for the effects of
hedging activities using natural gas and oil prices in effect at December
31, 2002.
The process of estimating natural gas and oil reserves is complex. It
requires various assumptions, including 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.
14
Actual future production, natural gas and oil prices, revenues, taxes,
development expenditures, operating expenses and quantities of recoverable
natural gas and oil reserves most likely will vary from estimates. Any
significant variance could materially affect the estimated quantities and net
present value of reserves. In addition, the Company may adjust estimates of
proved reserves to reflect production history, results of exploration and
development, prevailing natural gas and oil prices and other factors, many of
which are beyond the Company's control. At December 31, 2002, approximately 82%
of the Company's proved reserves were either undeveloped or non-producing.
Because most of the reserve estimates are not based on a lengthy production
history and are calculated using volumetric analysis, these estimates are less
reliable than estimates based on a lengthy production history.
At December 31, 2002, approximately 70% of the Company's proved reserves
were undeveloped and primarily related to Front Runner. Recovery of undeveloped
reserves generally requires significant capital expenditures and successful
drilling operations. The reserve data assumes that the Company will make these
expenditures. Although the Company estimates its reserves and the costs
associated with developing them in accordance with industry standards, the
estimated costs may be inaccurate, development may not occur as scheduled and
results may not be as estimated.
It should not be assumed that the present value of future net cash flows is
the current market value of the Company's estimated natural gas and oil
reserves. In accordance with requirements of the Commission, the Company bases
the estimated discounted future net cash flows from proved reserves on prices
and costs on the date of the estimate. Actual future prices and costs may
differ materially from those used in the present value estimate.
Volumes, Prices and Operating Expenses
The following table presents information regarding the production volumes
of, average sales prices received for and average production costs associated
with Spinnaker's sales of natural gas and oil and condensate for the periods
indicated:
Year Ended December 31,
------------------------
2002 2001 2000
------- ------- -------
Production:
Natural gas (MMcf)............................................ 45,180 51,234 28,845
Oil and condensate (MBbls).................................... 1,040 310 225
Total (MMcfe)............................................. 51,419 53,094 30,194
Average sales price per unit:
Natural gas revenues from production (per Mcf)................ $ 3.46 $ 4.14 $ 4.62
Effects of hedging activities (per Mcf)....................... 0.10 (0.18) (0.59)
------- ------- -------
Average price (per Mcf)................................... $ 3.56 $ 3.96 $ 4.03
Oil and condensate revenues from production (per Bbl)......... $ 26.39 $ 24.90 $ 30.14
Effects of hedging activities (per Bbl)....................... -- -- (7.16)
------- ------- -------
Average price (per Bbl)................................... $ 26.39 $ 24.90 $ 22.98
Total revenues from production (per Mcfe)..................... $ 3.57 $ 4.14 $ 4.64
Effects of hedging activities (per Mcfe)...................... 0.09 (0.18) (0.62)
------- ------- -------
Total average price (per Mcfe)............................ $ 3.66 $ 3.96 $ 4.02
Expenses (per Mcfe):
Lease operating expenses(1)................................... $ 0.35 $ 0.23 $ 0.30
Depreciation, depletion and amortization--natural gas and oil
properties.................................................. $ 2.12 $ 1.60 $ 1.57
--------
(1) The lease operating expense rate includes $0.03 per Mcfe associated with
workovers in 2002, $0.04 per Mcfe associated with workovers in 2001 and
$0.03 per Mcfe associated with workovers in 2000.
15
Development, Exploration and Acquisition Capital Expenditures
The following table presents information regarding Spinnaker's net costs
incurred in acquisition, exploration and development activities. Acquisition
costs include costs incurred to purchase, lease or otherwise acquire property.
Exploration costs include the costs of drilling exploratory wells, including
those in progress, geological and geophysical service costs and depreciation of
support equipment used in exploration activities. Development costs include the
costs of drilling development wells and costs of completions, platforms,
facilities and pipelines.
Year Ended December 31,
--------------------------
2002 2001 2000
-------- -------- --------
Acquisition costs:
Unproved..................... $ 39,789 $ 34,524 $ 21,421
Proved....................... -- -- --
Exploration costs............... 163,322 187,720 121,451
Development costs............... 139,368 80,276 51,144
-------- -------- --------
Total costs incurred..... $342,479 $302,520 $194,016
======== ======== ========
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.
Year Ended December 31,
--------------------------------
2002 2001 2000
---------- ---------- ----------
Gross Net Gross Net Gross Net
----- ---- ----- ---- ----- ----
Exploratory Wells:
Productive........ 11 5.1 17 8.2 16 10.4
Nonproductive..... 11 6.2 16 9.4 12 4.7
-- ---- -- ---- -- ----
Total............. 22 11.3 33 17.6 28 15.1
== ==== == ==== == ====
Development Wells:
Productive........ 3 2.0 2 0.5 -- --
Nonproductive..... 1 0.4 -- -- -- --
-- ---- -- ---- -- ----
Total............. 4 2.4 2 0.5 -- --
== ==== == ==== == ====
In 1999, the Company drilled an exploratory well that was preliminarily
determined to be unsuccessful and was temporarily abandoned. Upon reprocessing
of the seismic data, further analysis of the well and related sidetrack and
examination of proved category reserves, the Company determined that the
development would be commercial, and the well was reclassified as a discovery
in 2000. This well commenced production in 2002.
Since December 31, 2002 and through March 25, 2003, the Company has drilled
two gross (1.3 net) productive exploratory wells, one gross (0.3 net)
productive development well and one gross (0.5 net) nonproductive exploratory
well. As of March 25, 2003, the Company was drilling four gross (1.1 net)
exploratory wells and one gross (0.4 net) development well.
16
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, 2002:
Total
Productive
Wells
----------
Gross Net
----- ----
Natural gas 60 32.1
Oil........ 10 3.1
-- ----
Total... 70 35.2
== ====
Productive wells consist of producing wells and wells capable of production,
including wells awaiting pipeline connections to commence deliveries and wells
awaiting connection to production facilities.
Acreage Data
The following table presents information regarding developed and undeveloped
lease acreage. Developed acreage is considered to be those lease acres that are
allocated or assignable to productive wells or wells capable of production.
Undeveloped acreage is considered to be those lease acres 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 or not such
acreage contains proved reserves. Spinnaker's developed and undeveloped lease
acreage as of December 31, 2002 was as follows (in thousands):
Developed Undeveloped
Acreage Acreage Total
--------- ----------- ---------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ---
Federal Waters Offshore Louisiana 60 34 730 370 790 404
Federal Waters Offshore Texas.... 58 38 405 284 463 322
Texas State Waters............... 15 5 25 11 40 16
--- -- ----- --- ----- ---
Total......................... 133 77 1,160 665 1,293 742
=== == ===== === ===== ===
The Company's lease agreements generally terminate if wells have not been
drilled on the acreage within a period of five years from the date of the lease
if located on the shelf in less than 200 meters of water or ten years if
located in the deep waters of the Gulf of Mexico. Excluding lease acreage held
by production, average remaining lease terms were 6.3 years, 4.4 years and 1.5
years for leases in federal waters offshore Louisiana, federal waters offshore
Texas and Texas state waters, respectively.
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 2002.
17
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Spinnaker's Common Stock trades on the New York Stock Exchange under the
symbol "SKE." The following table sets forth the range of high and low sales
prices per share of Common Stock for each quarter by period.
Sales Price
-------------
High Low
------ ------
2001:
First Quarter.......................... $44.50 $33.00
Second Quarter......................... $48.00 $36.60
Third Quarter.......................... $43.96 $30.00
Fourth Quarter......................... $45.55 $33.30
2002:
First Quarter.......................... $44.64 $34.45
Second Quarter......................... $44.89 $35.77
Third Quarter.......................... $36.90 $24.46
Fourth Quarter......................... $29.71 $18.45
2003:
First Quarter (through March 25, 2003). $22.70 $17.15
On March 25, 2003, the closing sale price of Spinnaker's Common Stock, as
reported by the New York Stock Exchange, was $18.52 per share. On that date,
there were 39 holders of record.
The Company has never declared or paid any dividends on its Common Stock.
The Company currently intends to retain future earnings, if any, for the
operation and development of its business and does not anticipate paying any
dividends on its Common Stock in the foreseeable future. In addition, the
Company's $200.0 million credit agreement ("Credit Facility") contains
restrictions and limitations on paying cash dividends on its Common Stock. For
a description of the covenants and restrictive provisions in the Credit
Facility, see "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources--Financing
Activities" and Note 4 of the Notes to Consolidated Financial Statements.
The table of "Securities Authorized for Issuance Under Equity Compensation
Plans" is set forth under "Item 12. Security Ownership of Certain Beneficial
Owners and Management and Related Stockholder Matters" and is incorporated by
reference herein.
18
Item 6. Selected Financial Data
The following table sets forth some of the Company's historical consolidated
financial data. The following data should be read in conjunction with "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements and Notes thereto
included elsewhere herein. The selected consolidated financial data provided
below are not necessarily indicative of the future results of operations or
financial performance of the Company.
Year Ended December 31,
------------------------------------------------
2002 2001 2000 1999 1998
-------- -------- -------- -------- --------
(In thousands, except per share data)
Statement of Operations Data:
Revenues............................................................ $188,326 $210,376 $121,383 $ 34,258 $ 3,298
Expenses:
Lease operating expenses........................................ 18,212 12,132 9,009 5,411 474
Depreciation, depletion and amortization--natural gas and oil
properties..................................................... 108,998 85,059 47,451 20,788 2,738
Depreciation and amortization--other............................ 914 398 309 213 437
Write-down of natural gas and oil properties(1)................. -- -- -- -- 2,642
General and administrative...................................... 10,984 9,443 7,350 4,860 3,809
Charges related to Enron bankruptcy(2).......................... 128 3,059 -- -- --
Stock appreciation rights expense(3)............................ -- -- -- 1,651 --
-------- -------- -------- -------- --------
Total expenses............................................... 139,236 110,091 64,119 32,923 10,100
-------- -------- -------- -------- --------
Income (loss) from operations....................................... 49,090 100,285 57,264 1,335 (6,802)
Other income (expense):
Interest income................................................. 1,014 3,574 2,908 528 221
Interest expense, net........................................... (762) (381) (748) (2,805) (279)
-------- -------- -------- -------- --------
Total other income (expense)................................. 252 3,193 2,160 (2,277) (58)
-------- -------- -------- -------- --------
Income (loss) before income taxes................................... 49,342 103,478 59,424 (942) (6,860)
Income tax expense.............................................. 17,763 37,252 20,858 -- --
-------- -------- -------- -------- --------
Income (loss) before cumulative effect of change in accounting
principle.......................................................... 31,579 66,226 38,566 (942) (6,860)
Cumulative effect of change in accounting principle(4).......... -- -- -- (395) --
-------- -------- -------- -------- --------
Net income (loss)................................................... 31,579 66,226 38,566 (1,337) (6,860)
Accrual of dividends on preferred stock............................. -- -- -- (7,911) (7,094)
-------- -------- -------- -------- --------
Net income (loss) available to common stockholders.................. $ 31,579 $ 66,226 $ 38,566 $ (9,248) $(13,954)
======== ======== ======== ======== ========
Basic income (loss) per common share(5)(6):
Income (loss) before cumulative effect of change in
accounting principle........................................... $ 1.00 $ 2.45 $ 1.70 $ (1.06) $ (3.44)
Cumulative effect of change in accounting principle(4).......... -- -- -- (0.05) --
-------- -------- -------- -------- --------
Net income (loss) per common share.................................. $ 1.00 $ 2.45 $ 1.70 $ (1.11) $ (3.44)
======== ======== ======== ======== ========
Diluted income (loss) per common share(5)(6):
Income (loss) before cumulative effect of change in
accounting principle........................................... $ 0.97 $ 2.34 $ 1.61 $ (1.06) $ (3.44)
Cumulative effect of change in accounting principle(4).......... -- -- -- (0.05) --
-------- -------- -------- -------- --------
Net income (loss) per common share.................................. $ 0.97 $ 2.34 $ 1.61 $ (1.11) $ (3.44)
======== ======== ======== ======== ========
Weighted average number of common shares outstanding(5)(6):
Basic........................................................... 31,695 27,079 22,679 8,355 4,059
======== ======== ======== ======== ========
Diluted......................................................... 32,653 28,360 24,011 8,355 4,059
======== ======== ======== ======== ========
Summary Balance Sheet Data:
Working capital (deficit)........................................... $ (6,359) $(20,654) $ 74,005 $ 19,675 $(30,641)
Property and equipment, net......................................... 760,854 522,573 304,381 157,397 95,607
Total assets........................................................ 842,715 587,316 442,704 189,553 102,769
Short-term debt..................................................... -- -- -- -- 19,000
Accrued preferred dividends payable(6).............................. -- -- -- -- 8,478
Total equity(6)..................................................... 692,977 458,492 361,259 177,102 56,913
19
--------
(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 Company had in place both financial hedge and physical contracts with
Enron North America Corp. at the time Enron Corp. and its subsidiaries
filed for bankruptcy in December 2001. Spinnaker did not receive payment
for fixed price swap contracts totaling $2.1 million which were intended to
hedge December 2001 natural gas sales, and $1.4 million related to November
2001 natural gas production sold to Enron entities. The Company has
recorded a net reserve of $3.2 million against these receivables.
(3) Prior to July 1999, the stock option agreements of two of the Company's
officers provided that they could elect to have Spinnaker deliver shares
equal to the appreciation in the value of the stock over the option price
in lieu of purchasing the amount of shares under option. Based on
management's estimate of the share value of Spinnaker, the Company recorded
compensation expense of approximately $1.7 million in 1999 related to the
stock appreciation rights of the stock option agreements. In July 1999,
these two officers agreed to eliminate the stock appreciation rights
feature of their stock option agreements.
(4) The cumulative effect of change in accounting principle represents the
adoption of Statement of Position 98-5 "Reporting on the Costs of Start-Up
Activities."
(5) Spinnaker was originally formed as a limited liability company, and the
Company issued common units and preferred units. In connection with its
conversion to a corporation in January 1998, the Company exchanged Common
Stock for all then outstanding common units and Preferred Stock for all
then outstanding preferred units. The Company expresses all historical unit
data in shares of Common Stock.
(6) On April 3, 2002, the Company completed a public offering of 5,750,000
shares of Common Stock. On August 16, 2000, the Company completed a public
offering of 5,600,000 shares of Common Stock. In connection with its
initial public offering in 1999, the Company issued 8,000,000 shares of
Common Stock, converted all then outstanding shares of Preferred Stock into
6,061,840 shares of Common Stock and issued 1,200,248 shares of Common
Stock to certain holders of the previously outstanding Preferred Stock in
lieu of payment of accrued cash dividends.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Overview
Financial and operating results in 2002 compared to 2001 included:
. Revenues of $188.3 million, down 10%.
. Income from operations of $49.1 million, down 51%.
. Net income of $31.6 million, or $0.97 per diluted share, down 52%.
. Production of 51.4 Bcfe, down 3%.
. Proved reserves of 323.6 Bcfe, reserve replacement was 101% of production
in 2002.
Spinnaker's results of operations and financial position were significantly
impacted by lower commodity prices and production in 2002. Of the $22.1 million
net decrease in revenues, $29.4 million was due to a lower average commodity
price on an equivalent basis and $6.9 million related to decreased production,
offset in part by an increase in net hedging income of $14.2 million. The
Company had $32.5 million in cash and cash equivalents and no debt at
December 31, 2002.
20
Risk Factors
In addition to the other information set forth elsewhere in this annual
report, the following factors should be carefully considered when evaluating
Spinnaker.
Exploration is a high-risk activity, and the 3-D seismic data and other
advanced technologies the Company uses cannot eliminate exploration risk and
require experienced technical personnel whom the Company may be unable to
attract or retain.
The Company's future success will depend on the success of its exploratory
drilling program. Exploration activities involve numerous risks, including the
risk that no commercially productive natural gas or oil reservoirs will be
discovered. In addition, the Company often is uncertain as to the future cost
or timing of drilling, completing and producing wells. Furthermore, drilling
operations may be curtailed, delayed or canceled as a result of the additional
exploration time and expense associated with a variety of factors, including
unexpected drilling conditions, pressure or irregularities in formations,
equipment failures or accidents, adverse weather conditions, compliance with
governmental requirements and shortages or delays in the availability of
drilling rigs or equipment.
Even when used and properly interpreted, 3-D seismic data and visualization
techniques only assist geoscientists in identifying subsurface structures and
hydrocarbon indicators. They do not allow the interpreter to know conclusively
if hydrocarbons are present or economically producible. The Company could incur
losses as a result of expenditures on unsuccessful wells. Poor results from
exploration activities could materially and adversely affect future cash flows
and results of operations.
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.
A substantial portion of Spinnaker's proved reserves are associated with its
deepwater oil discovery at Front Runner. The development of Front Runner will
require significant financial resources before initial production and remains
subject to other uncertainties that could have a material impact on the
development of this discovery.
Spinnaker's deepwater oil discovery at Front Runner, in which the Company
has a 25% non-operator working interest, has required and will continue to
require significant financial resources in advance of the expected initial
production date in the summer of 2004. The Company has incurred $70.2 million
in capital expenditures for Front Runner through December 31, 2002 and expects
to incur an aggregate of approximately $67.0 million in future development
costs during 2003 and 2004. Because another oil and gas exploration and
production company operates Front Runner, the Company has a limited ability to
influence the operations and costs associated with this property.
Front Runner is located in approximately 3,500 feet of water and wells have
been drilled in the Front Runner area to total depths in excess of 20,000 feet.
The Company has limited experience with large deepwater and deep drilling depth
discoveries similar to Front Runner as most of its prior discoveries have
occurred in shallower waters and at shallower drilling depths. As a result of
these uncertainties and risks, the Company may encounter difficulties and
delays that could cause actual expenditures to exceed anticipated amounts.
J. Ray McDermott Inc. ("McDermott"), the contractor responsible for
construction, delivery and installation of the Front Runner spar production
facility, has announced that it is experiencing liquidity concerns. If
McDermott experiences additional significant unanticipated costs in the future,
it may be unable to fund all of its
21
anticipated operating and capital needs, which may delay the expected delivery
date of the spar production facility as well as the initial production date and
actual expenditures may exceed anticipated amounts.
The hull of the spar production facility is being constructed in Dubai,
U.A.E. Due to the current military conflict in the Middle East, the delivery
date of the hull to the Gulf of Mexico may be delayed. Additionally, weather
and other conditions may delay the installation of the spar production facility
on location. Any delays in the delivery or installation dates would cause a
delay in the initial production date.
Front Runner accounted for more than 60% of Spinnaker's proved undeveloped
reserves at December 31, 2002. If the actual reserves associated with Front
Runner are substantially less than the estimated reserves, the Company's
results of operations and financial condition could be adversely affected.
When production ultimately commences for this discovery, it may produce
substantially less oil and natural gas than currently projected. Additionally,
the Company cannot predict commodity prices when production commences. If
production is substantially less than currently projected or commodity prices
are low, the Company's results of operations and financial condition could be
adversely affected.
These uncertainties and other risks described in this "Risk Factors" section
and elsewhere in this annual report make it difficult to predict whether Front
Runner can be successfully or economically developed. If Front Runner cannot be
successfully and economically developed, the Company's future business,
financial condition and operating results will be materially and 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,
pipe or cement failures, casing collapses, embedded oilfield drilling and
service tools, abnormally pressured formations and environmental hazards such
as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic
gases. If any of these events occur, the Company could incur substantial losses
as a result of injury or loss of life, severe damage to and destruction of
property, natural resources and equipment, pollution and other environmental
damage, clean-up responsibilities, regulatory investigation and penalties,
suspension of the Company's operations and repairs to resume operations. If the
Company experiences any of these problems, it could affect well bores,
platforms, gathering systems and processing facilities, which could adversely
affect its ability to conduct operations.
Offshore operations are also subject to a variety of operating risks
specific to the marine environment, such as capsizing, collisions and damage or
loss from hurricanes or other adverse weather conditions. These conditions can
cause substantial damage to facilities and interrupt production. As a result,
the Company could incur substantial liabilities that could reduce or eliminate
the funds available for exploration, development or leasehold acquisitions, or
result in loss of equipment and properties.
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 at deeper drilling depths and in the deep
waters of the Gulf of Mexico involves greater operational and financial risks
than exploration at shallower depths and in shallower waters. These risks could
result in substantial losses.
The Company explores for natural gas and oil at deeper drilling depths and
in the deep waters of the Gulf of Mexico where operations are more difficult
and costly than at shallower depths and in shallower waters. Deep depth and
deepwater drilling and operations require the application of recently developed
technologies that
22
involve a higher risk of mechanical failure. The Company has experienced and
will continue to experience significantly higher drilling costs for its deep
depth and deepwater prospects.
At December 31, 2002, approximately 92% of the Company's proved undeveloped
reserves were located in deep water. The deep water lacks the physical and
oilfield service infrastructure present in the shallower waters. As a result,
deepwater projects require long-term commitments of significant financial
resources. Deepwater operations may also require a significant amount of time
between the discovery date and the initial production date when the Company can
market the natural gas or oil, increasing both the financial and operational
risk involved with these operations.
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,
drilling rig and other oilfield services and compliance with environmental and
other laws and regulations.
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 2002, approximately 44% of the Company's production came from three
of its properties in the Gulf of Mexico. If mechanical problems, storms or
other events curtailed a substantial portion of this production, the Company's
cash flow would be adversely affected. In addition, at December 31, 2002, the
Company's proved reserves were located on 26 different blocks in the Gulf of
Mexico, with approximately 73% of the proved reserves attributable to six of
these properties. One property, Front Runner, accounted for more than 60% of
total proved undeveloped reserves and more than 40% of total proved reserves.
If the actual reserves associated with any one of these six properties are
substantially less than the estimated reserves, the Company's results of
operations and financial condition could be adversely affected.
The Commission is currently reviewing information from Spinnaker and other
oil and gas companies operating in the Gulf of Mexico to assess how the
industry is determining proved reserves related to new discoveries. Rules and
regulations of the Commission allow companies to recognize proved reserves if
economic producibility is supported by either actual production or a conclusive
formation test. The Commission believes that a production flow test of reserves
satisfies the requirements of a conclusive formation test. In the absence of a
production flow test, compelling technical data must exist to recognize proved
reserves. The industry has increasingly depended on advanced technical testing
to support economic producibility. Spinnaker has recorded most of its proved
reserves in deep water based on various advanced technical tests rather than
production flow tests. The Company expects initial production from the majority
of its proved undeveloped reserves in deep water to commence no later than the
summer of 2004. The Company believes these proved reserves are properly
recorded and classified. Spinnaker has furnished the information requested by
the Commission and is unable to predict the outcome of the Commission's review
of Spinnaker's and the industry's practices.
If any seismic contractor terminates its data agreement with Spinnaker, the
Company's ability to find additional reserves could be impaired.
The Company's success depends heavily on its access to 3-D seismic data. If
any seismic contractor terminates its data agreement with Spinnaker, the
Company would lose access to a portion of its 3-D seismic
23
data, which loss could have an adverse effect on its ability to find additional
reserves. A seismic contractor may terminate its data agreement with Spinnaker
on several grounds, including if a competitor of the seismic contractor
acquires control of Spinnaker or if the Company breaches the data agreement
with that seismic contractor, subject to certain exceptions. See "Item 1.
Business--Seismic Data Agreements--Termination Events" for a description of
these exceptions.
Competitors may use superior technology which the Company may be unable to
afford or which would require costly investments in order to compete.
The industry is subject to rapid and significant advancements in technology,
including the introduction of new products and services using new technologies.
As competitors use or develop new technologies, the Company may be placed at a
competitive disadvantage, and competitive pressures may force it to implement
new technologies at a substantial cost. In addition, competitors may have
greater financial, technical and personnel resources that allow them to enjoy
technological advantages and may in the future allow them to implement new
technologies before the Company can. The Company cannot be certain that it will
be able to implement technologies on a timely basis or at a cost that is
acceptable to it. One or more of the technologies that the Company currently
uses or that it may implement in the future may become obsolete, which may
adversely affect the Company's results of operations and financial condition.
For example, marine seismic acquisition technology has undergone rapid
technological advancements in recent years and further significant
technological developments could substantially impair the value of Spinnaker's
3-D seismic data.
Reserve estimates depend on many assumptions that may turn out to be
inaccurate. Any material inaccuracies in these reserve estimates or their
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 the 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 the 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. Moreover, some of the
producing wells included in the reserve report had produced for only a
relatively short period of time as of December 31, 2002. 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.
It should not be assumed 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 requirements, the
Company bases the estimated discounted future net cash flows from its proved
reserves on prices and costs on the date of the estimate. Actual future prices
and costs may differ materially from those used in the net present value
estimate.
24
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
and mechanical issues. The Company's total proved reserves decline as reserves
are produced unless it conducts other successful exploration and development
activities or acquires properties containing proved reserves, or both. The
Company's ability to make the necessary capital investment to maintain or
expand its asset base of natural gas and oil reserves would be impaired to the
extent cash flow from operations is reduced and external sources of capital
become limited or unavailable. The Company may not be successful in exploring
for, developing or acquiring additional reserves. If the Company is not
successful, its future production and revenues will be adversely affected.
Relatively short production periods for Gulf of Mexico properties subject the
Company to higher reserve replacement needs, require the Company to incur
capital expenditures more frequently to replace production and may impair its
ability to slow or shut-in production during periods of low prices for natural
gas and oil.
Reservoirs in the Gulf of Mexico are generally sandstone reservoirs
characterized by high porosity, permeability, pressure and temperature.
Production of these reservoirs is generally constant for a relatively shorter
period of time with a rapid decline in production at the end of the reservoir
life compared to production of reservoirs in many other producing regions of
the world. As a result, reserve replacement needs from new prospects in the
Gulf of Mexico are greater and require the Company to incur capital
expenditures more frequently to replace production than would typically be
required in many other producing regions of the world. The Company expects a
decline in production during the first quarter of 2003 due to the rapid
production decline of certain producing wells and a shut-in for pipeline
repairs.
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 future indebtedness may limit its ability to slow or shut-in production
from producing wells in the future during periods of low prices for natural gas
and oil.
Natural gas and oil prices fluctuate widely, and low prices could have a
material adverse impact on the Company's business and financial results.
The Company's revenues, profitability and future growth depend substantially
on prevailing prices for natural gas and oil. Prices also affect the amount of
cash flow available for capital expenditures and the Company's ability to
borrow and raise additional capital. The amount the Company can borrow under
the Credit Facility is subject to periodic re-determination based in part on
changing expectations of future prices. Lower prices may also reduce the amount
of natural gas and oil that the Company can economically produce.
Prices for natural gas and oil fluctuate widely. 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. If natural gas and
oil prices decline, even if for only a short period of time, it is possible
that write-downs of natural gas and oil properties could occur in the future.
Hedging production has limited and may continue to limit potential gains from
increases in commodity prices or result in losses.
The Company enters into hedging arrangements from time to time to reduce its
exposure to fluctuations in natural gas and oil prices and to achieve more
predictable cash flow. These financial arrangements take the form of swap
contracts or cashless collars and are placed with major trading counterparties
the Company believes represent minimum credit risks. The Company cannot provide
assurance that these trading counterparties will not
25
become credit risks in the future. Hedging arrangements expose the Company to
risks in some circumstances, including situations when the other party to the
hedging contract defaults on its contract obligations or there is a change in
the expected differential between the underlying price in the hedging agreement
and actual prices received. These hedging arrangements have limited and may
continue to limit the benefit the Company could receive from increases in the
prices for natural gas and oil. The Company cannot provide assurance that the
hedging transactions it has entered into, or will enter into, will adequately
protect it from fluctuations in natural gas and oil prices. The Company may
choose not to engage in hedging transactions in the future. As a result, the
Company may be adversely affected during periods of declining natural gas and
oil prices.
Natural gas prices have fluctuated widely in early 2003. The Company will
recognize net hedging losses of $17.7 million in the first quarter of 2003
based on natural gas price settlements. If natural gas prices remain at current
levels, Spinnaker will incur significant hedging losses in the remainder of
2003.
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, including the Company's Vice
President--Exploration who will retire in early 2004. If Mr. Jarvis or other
key personnel resign or become unable to continue in their present role and if
they are not adequately replaced, the Company's business operations could be
adversely affected.
The Company is subject to complex laws and regulations, including environmental
regulations, that can adversely affect the cost, manner or feasibility of doing
business.
Exploration for and development, production and sale of natural gas and oil
in the U.S. and especially in the Gulf of Mexico are subject to extensive
federal, state and local laws and regulations, including environmental laws and
regulations. The Company may be required to make large expenditures to comply
with environmental and other governmental regulations. Matters subject to
regulation include discharge permits for drilling operations, drilling bonds,
reports concerning operations and taxation.
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 additional 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.
Competition in the industry is intense, and the Company is smaller and has a
more limited operating history than most of its competitors in the Gulf of
Mexico.
The Company competes with major and independent natural gas and oil
companies for property acquisitions. It also competes for the equipment and
labor required to operate and develop properties. Most of the competitors have
substantially greater financial and other resources than the Company. As a
result, in the deep water where exploration is more expensive, competitors may
be better able to withstand sustained periods of unsuccessful drilling. In
addition, larger competitors may be able to absorb the burden of any changes in
federal, state and local laws and regulations more easily than the Company can,
which would adversely affect its competitive position. These competitors may be
able to pay more for exploratory prospects and productive natural gas and oil
properties and may be able to define, evaluate, bid for and purchase a greater
number of properties and prospects than the Company can. The Company's ability
to explore for natural gas and oil
26
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.
The Company cannot control the activities on properties it does not operate.
Other companies operate some of the properties in which the Company has an
interest, including Front Runner. 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 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 expects it 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.
Warburg owns a significant number of shares of Common Stock, giving it
influence in corporate transactions and other matters, and the interests of
Warburg could differ from those of other stockholders.
At December 31, 2002, Warburg owned approximately 20% of the outstanding
shares of Common Stock. As a result, Warburg is in a position to significantly
influence 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. Its influence over Spinnaker may delay or prevent a
change of control of the Company and may adversely affect the voting and other
rights of other stockholders.
Furthermore, conflicts of interest could arise in the future between the
Company and Warburg concerning, among other things, potential competitive
business activities or business opportunities. Warburg is not restricted from
competitive natural gas and oil exploration and production activities or
investments. Warburg currently has significant equity interests in other public
and private natural gas and oil companies. The interests of Warburg could
differ from those of other stockholders.
A portion of the Company's outstanding shares owned by Warburg or other
significant stockholders 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 Common Stock in the market or the perception that such
sales could occur. This could make it more difficult to raise funds through any
future offering of Common Stock.
The certificate of incorporation and bylaws contain provisions that could
discourage an acquisition or change of control of the Company.
The certificate of incorporation authorizes the board of directors to issue
Preferred Stock without stockholder approval. If the board of directors elects
to issue Preferred Stock, it could be more difficult for a third
27
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.
Terrorist attacks on natural gas and oil production facilities, transportation
systems and storage facilities could have a material adverse impact on the
Company's business.
Natural gas and oil production facilities, transportation systems and
storage facilities could be targets of terrorist attacks. These attacks could
have a material adverse impact if certain natural gas and oil infrastructure
integral to the Company's operations were destroyed or damaged.
Critical Accounting Policies
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 as of the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Significant estimates include depreciation, depletion and amortization ("DD&A")
of proved natural gas and oil properties. Natural gas and oil reserve
estimates, which are the basis for unit-of-production DD&A and the full cost
ceiling test, are inherently imprecise and are expected to change as future
information becomes available. In addition, alternatives may exist among
various accounting methods. In such cases, the choice of accounting method may
also have a significant impact on reported amounts. The Company's critical
accounting policies are as follows:
Full Cost Method of Accounting
The Company uses the full cost method of accounting for its investments in
natural gas and oil properties. Under this method, all acquisition, exploration
and development costs, including certain related employee costs, incurred for
the purpose of exploring for and developing natural gas and oil are
capitalized. Acquisition costs include costs incurred to purchase, lease or
otherwise acquire property. Exploration costs include the costs of drilling
exploratory wells, including those in progress, geological and geophysical
service costs and depreciation of support equipment used in exploration
activities. Development costs include the costs of drilling development wells
and costs of completions, platforms, facilities and pipelines. Costs associated
with production and general corporate activities are expensed in the period
incurred. Sales of natural gas and oil properties, whether or not being
amortized currently, are accounted for as adjustments of capitalized costs,
with no gain or loss recognized, unless such adjustments would significantly
alter the relationship between capitalized costs and proved reserves of natural
gas and oil. Application of the full cost method of accounting for oil and gas
properties generally results in higher capitalized costs, no exploration costs
and higher DD&A rates than the application of the successful efforts method of
accounting.
DD&A
The Company computes the provision for DD&A of natural gas and oil
properties using the unit-of-production method based upon production and
estimates of proved reserve quantities. Unevaluated costs and related carrying
costs are excluded from the amortization base until the properties associated
with these costs are evaluated. In addition to costs associated with evaluated
properties, the amortization base includes estimated future development costs
and dismantlement, restoration and abandonment costs, net of estimated salvage
values.
Certain future development costs may be excluded from amortization when
incurred in connection with major development projects expected to entail
significant costs to ascertain the quantities of proved reserves
28
attributable to the properties under development. The amounts that may be
excluded are portions of the costs that relate to the major development project
and have not previously been included in the amortization base and the
estimated future expenditures associated with the development project. Such
costs may be excluded from costs to be amortized until the earlier
determination of whether additional reserves are proved or impairment occurs.
As of December 31, 2002, the Company excluded from the amortization base
estimated future expenditures of $29.4 million associated with common
development costs for its deepwater discovery at Front Runner. This estimate of
future expenditures associated with common development costs is based on
existing proved reserves to total proved reserves expected to be established
upon completion of the Front Runner project.
If the $29.4 million had been included in the amortization base as of
December 31, 2002, and no additional reserves were assigned to the Front Runner
project, the DD&A rate in 2002 would have been $2.21 per Mcfe, or an increase
of $0.09 over the actual DD&A rate of $2.12 per Mcfe. All future development
costs associated with the deepwater discovery at Front Runner are included in
the determination of estimated future net cash flows from proved natural gas
and oil reserves used in the full cost ceiling calculation, as discussed below.
Full Cost Ceiling
Capitalized costs of natural gas and oil properties, net of accumulated DD&A
and related deferred taxes, are limited to the estimated future net cash flows
from proved natural gas and oil reserves, including the effects of hedging
activities in place as of December 31, 2002, discounted at 10%, plus the lower
of cost or fair value of unproved properties, as adjusted for related income
tax effects (full cost ceiling). If capitalized costs of the full cost pool
exceed the ceiling limitation, the excess is charged to expense.
As of December 31, 2002, the Company's full cost ceiling, including
estimated future net cash flows calculated using commodity prices of $4.91 per
Mcf of natural gas and $30.50 per barrel of oil and condensate, exceeded
capitalized costs of natural gas and oil properties, net of accumulated DD&A
and related deferred taxes, by approximately $139.9 million. Considering the
volatility of natural gas and oil prices, it is probable that the Company's
estimate of discounted future net cash flows from proved natural gas and oil
reserves will change in the near term. If natural gas or oil prices decline,
even if for only a short period of time, or if the Company has downward
revisions to its estimated proved reserves, it is possible that write-downs of
natural gas and oil properties could occur in the future.
Capitalized Employee and Other General and Administrative Costs
Under the full cost method of accounting, certain costs are capitalized that
are directly identified with acquisition, exploration and development
activities. These capitalized costs include salaries, employee benefits, costs
of consulting services and other related costs and do not include costs related
to production, general corporate overhead or similar activities. Spinnaker
capitalized employee and other general and administrative costs of $5.9
million, $5.1 million and $3.8 million in 2002, 2001 and 2000, respectively.
Unproved Properties
The costs associated with unproved properties and properties under
development are not initially included in the amortization base and relate to
unevaluated leasehold acreage and delay rentals, seismic data, wells
in-progress and wells pending determination. Unevaluated leasehold costs and
delay rentals are either transferred to the amortization base with the costs of
drilling the related well or are assessed quarterly for possible impairment or
reduction in value. Unevaluated leasehold costs and delay rentals are
transferred to the amortization base if a reduction in value has occurred. The
costs of seismic data are transferred to the amortization base using the
sum-of-the-year's-digits method over a period of six years. The costs
associated with wells in-progress and wells pending determination are
transferred to the amortization base once a determination is made whether or
not proved reserves can be assigned to the property. The costs of drilling
exploratory dry holes and associated
29
leasehold costs are included in the amortization base immediately upon
determination that the well is unsuccessful.
Natural Gas and Oil Reserves
The process of estimating natural gas and oil reserves is complex. It
requires various assumptions, including 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 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, 2002, approximately 82%
of the Company's proved reserves were either undeveloped or non-producing.
Because most of the reserve estimates are not based on a lengthy production
history and are calculated using volumetric analysis, these estimates are less
reliable than estimates based on a lengthy production history.
At December 31, 2002, approximately 70% of the Company's proved reserves
were undeveloped and primarily related to Front Runner. Recovery of undeveloped
reserves generally requires significant capital expenditures and successful
drilling operations. The reserve data assumes that the Company will make these
expenditures. Although the Company estimates its reserves and the costs
associated with developing them in accordance with industry standards, the
estimated costs may be inaccurate, development may not occur as scheduled and
results may not be as estimated.
Other Property and Equipment
The costs associated with seismic hardware and software are included in
other property and equipment. These costs are amortized into the full cost pool
using the straight-line method over three years. Amortization was $1.5 million,
$0.5 million and $1.2 million in 2002, 2001 and 2000, respectively.
Commodity Price Risk Management Activities
On January 1, 2001, the Company adopted Statement of Financial Accounting
Standards ("SFAS") No. 133, as amended, "Accounting for Derivative Instruments
and Hedging Activities." SFAS No. 133 established accounting and reporting
standards requiring that all derivative instruments be recorded in the balance
sheet as either an asset or liability measured at its fair value. SFAS No. 133
requires that changes in a derivative's fair value be realized currently in
earnings unless specific hedge accounting criteria are met. Accounting for
qualifying hedges allows derivative gains and losses to offset related results
on the hedged items in the statement of operations and requires a company to
formally document, designate and assess the effectiveness of transactions that
qualify for hedge accounting. See "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk."
Stock-Based Compensation
SFAS No. 148, "Accounting for Stock-Based Compensation--Transition and
Disclosure," amends SFAS No. 123 to provide alternative methods of transition
for an entity that voluntarily changes to the fair value based method of
accounting for stock-based employee compensation and to require prominent
disclosure about the effects on reported net income of an entity's accounting
policy decisions with respect to stock-based employee compensation. SFAS No.
148 amends Accounting Principles Board ("APB") Opinion No. 28, "Interim
Financial Reporting," to require disclosure about those effects in interim
financial information.
30
SFAS No. 123, "Accounting for Stock-Based Compensation," encourages, but
does not require, companies to record compensation cost for stock-based
employee compensation plans at fair value. The Company has chosen to account
for stock-based compensation using the intrinsic value method prescribed in APB
Opinion No. 25, "Accounting for Stock Issued to Employees," and related
interpretations. Accordingly, compensation cost for stock options is measured
as the excess, if any, of the fair value of the Common Stock at the date of the
grant over the amount an employee must pay to acquire the Common Stock.
Related Parties
The Company purchases oilfield goods, equipment and services from Baker
Hughes Incorporated ("Baker Hughes"), Cooper Cameron Corporation ("Cooper
Cameron") and other oilfield services companies in the ordinary course of
business. The Company incurred charges of approximately $16.1 million and $16.3
million in 2002 and 2001, respectively, from affiliates of Baker Hughes, of
which Mr. Michael E. Wiley, a director of Spinnaker since March 2001, serves as
Chairman of the Board, Chief Executive Officer and President. The Company
incurred charges of approximately $0.1 million, $0.1 million and $0.5 million
in 2002, 2001 and 2000, respectively, from Cooper Cameron, of which Mr. Sheldon
R. Erikson, a director of Spinnaker, serves as Chairman of the Board, Chief
Executive Officer and President. Spinnaker believes that these transactions are
at arm's-length and the charges it pays for such goods, equipment and services
are competitive with the charges and fees of other companies providing oilfield
goods, equipment and services to the oil and gas exploration and production
industry. Both of these companies are leaders in their respective segments of
the oilfield services sector. The Company could be at a disadvantage if it were
to discontinue using either company as vendors.
Results of Operations
The following table sets forth certain operating information with respect to
the natural gas and oil operations of the Company:
Year Ended December 31,
---------------------------
2002 2001 2000
-------- -------- --------
Production:
Natural gas (MMcf)............................................ 45,180 51,234 28,845
Oil and condensate (MBbls).................................... 1,040 310 225
Total (MMcfe)............................................. 51,419 53,094 30,194
Revenues (in thousands):
Natural gas................................................... $156,214 $212,238 $133,264
Oil and condensate............................................ 27,448 7,718 6,775
Net hedging income (loss)..................................... 4,664 (9,580) (18,656)
-------- -------- --------
Total..................................................... $188,326 $210,376 $121,383
Average sales price per unit:
Natural gas revenues from production (per Mcf)................ $ 3.46 $ 4.14 $ 4.62
Effects of hedging activities (per Mcf)....................... 0.10 (0.18) (0.59)
-------- -------- --------
Average price (per Mcf)................................... $ 3.56 $ 3.96 $ 4.03
Oil and condensate revenues from production (per Bbl)......... $ 26.39 $ 24.90 $ 30.14
Effects of hedging activities (per Bbl)....................... -- -- (7.16)
-------- -------- --------
Average price (per Bbl)................................... $ 26.39 $ 24.90 $ 22.98
Total revenues from production (per Mcfe)..................... $ 3.57 $ 4.14 $ 4.64
Effects of hedging activities (per Mcfe)...................... 0.09 (0.18) (0.62)
-------- -------- --------
Total average price (per Mcfe)............................ $ 3.66 $ 3.96 $ 4.02
Expenses (per Mcfe):
Lease operating expenses...................................... $ 0.35 $ 0.23 $ 0.30
Depreciation, depletion and amortization--natural gas and oil
properties.................................................. $ 2.12 $ 1.60 $ 1.57
Income from operations (in thousands)............................ $ 49,090 $100,285 $ 57,264
31
Year Ended December 31, 2002 as Compared to the Year Ended December 31, 2001
Revenues, including the effects of hedging activities, decreased $22.1
million in 2002 compared to 2001. Natural gas revenues decreased $56.0 million,
oil and condensate revenues increased $19.7 million and revenues from natural
gas hedging activities improved $14.2 million in 2002 compared to 2001.
Production decreased approximately 1.7 Bcfe in 2002 compared to 2001.
Average daily production in 2002 was 141 MMcfe compared to 145 MMcfe in 2001.
Natural gas revenues decreased $56.0 million due to lower volumes of 6.1 Bcf
and a lower average price in 2002 compared to 2001. The production declines of
certain producing wells, particularly in the High Island 202 area, resulted in
lower natural gas production in 2002. Oil and condensate revenues increased
$19.7 million primarily due to higher production volumes of 730 MBbls. The
Company expects a decline in production during the first quarter of 2003 due to
the rapid production decline of certain producing wells and shut-ins for
pipeline repairs.
Lease operating expenses increased $6.1 million in 2002 compared to 2001. Of
the total increase in lease operating expenses, approximately $7.3 million was
attributable to wells on ten new blocks that commenced production in 2002,
offset in part by a decrease of $0.9 million in operating expenses associated
with existing wells and a decrease of $0.3 million in workovers. The overall
increase in the lease operating expense rate per Mcfe in 2002 compared to 2001
was primarily due to the production declines of certain wells in the High
Island 202 area where the lease operating rate in 2001 was significantly lower
compared to other producing areas operated by the Company. Additionally, the
Company is experiencing higher lease operating rates associated with new wells
compared to historical average lease operating rates due to well locations,
transportation and gathering agreements and processing requirements.
DD&A increased $23.9 million in 2002 compared to 2001. Of the total increase
in DD&A, $26.6 million related to an increase in the DD&A rate, offset in part
by $2.7 million related to lower production volumes of 1.7 Bcfe in 2002
compared to 2001. The increase in the DD&A rate in 2002 was primarily due to
costs of $72.6 million associated with 12 unsuccessful wells and higher finding
costs associated with new discoveries in 2002.
General and administrative expenses increased $1.5 million in 2002 compared
to 2001. The increase in general and administrative expenses was primarily due
to higher employment-related costs resulting from the Company's recent growth
and increased professional services fees.
Interest income decreased $2.6 million in 2002 compared to 2001 primarily
due to lower average cash and short-term investment balances and significantly
lower interest rates in 2002. Interest expense increased $0.3 million in 2002
compared to 2001 primarily due to interest on borrowings of $37.0 million in
the first quarter of 2002 and higher commitment fees. On April 3, 2002, the
Company repaid all of its outstanding borrowings of $37.0 million under the
Credit Facility.
Income tax expense decreased $19.5 million in 2002 compared to 2001 due to
lower earnings in 2002. Income taxes were accrued at a 36% effective tax rate
in 2002 and 2001.
The Company recognized net income of $31.6 million, or $1.00 per basic share
and $0.97 per diluted share, in 2002 compared to net income of $66.2 million,
or $2.45 per basic share and $2.34 per diluted share, in 2001.
Year Ended December 31, 2001 as Compared to the Year Ended December 31, 2000
Revenues increased $89.0 million in 2001 compared to 2000. Excluding the
effects of hedging activities, natural gas revenues increased $79.0 million and
oil and condensate revenues increased $0.9 million. Losses resulting from
hedging activities decreased by $9.1 million in 2001 compared to 2000, thereby
improving revenues.
Production increased approximately 22.9 Bcfe in 2001 compared to 2000.
Average daily production in 2001 was 145 MMcfe compared to 82 MMcfe in 2000.
Natural gas production volumes increased 22.4 Bcf,
32
contributing $123.9 million of the increase in natural gas revenues, excluding
the effects of hedging activities, offset in part by $44.9 million related to
lower average natural gas prices in 2001 compared to 2000. Oil and condensate
production volumes increased 85 MBbls, contributing $2.8 million of the
increase in oil and condensate revenues, offset in part by $1.9 million related
to decreases in average oil and condensate prices. The rapid production
declines of certain producing wells, combined with pipeline-mandated
curtailments of certain facilities, shut-ins related to facility upgrades and
less than anticipated results from workovers resulted in lower production in
the fourth quarter of 2001 compared to the prior quarter.
Lease operating expenses increased $3.1 million in 2001 compared to 2000. Of
the total increase in lease operating expenses, $1.0 million was primarily
related to workover activities in 2001 and $0.4 million was attributable to
wells on new blocks that commenced production subsequent to December 31, 2000.
The lease operating expense rate decreased 23% to $0.23 per Mcfe in 2001
compared to 2000 primarily due to increased production coupled with continued
efficiencies gained in core operating areas, including the High Island 202 area.
DD&A increased $37.7 million in 2001 compared to 2000. The change in DD&A
was attributable to an increase in production of 22.9 Bcfe and a slightly
higher DD&A rate, which impacted DD&A by $36.0 million and $1.7 million,
respectively.
General and administrative expenses increased $2.1 million in 2001 compared
to 2000. The increase in general and administrative expenses was primarily due
to higher employment-related costs resulting from the Company's recent growth.
The Company had in place both financial hedge and physical contracts with
Enron North America Corp. at the time Enron Corp. and its subsidiaries filed
for bankruptcy in December 2001. Spinnaker did not receive payment for fixed
price swap contracts totaling $2.1 million which were intended to hedge
December 2001 natural gas sales, and $1.4 million related to November 2001
natural gas production sold to Enron entities. The Company has recorded a net
reserve of $3.2 million related to these receivables.
Interest income increased $0.7 million in 2001 compared to 2000 primarily
due to investment income associated with proceeds from the Company's public
offering of Common Stock completed on August 16, 2000. Interest expense
decreased $0.4 million in 2001 compared to 2000. The Company had no outstanding
borrowings in 2001 compared to 2000.
Income tax expense increased $16.4 million in 2001 compared to 2000 and
primarily relates to deferred income taxes accrued at a 36% effective tax rate
in 2001 and a 35% effective tax rate in 2000.
The Company recognized net income of $66.2 million, or $2.45 per basic share
and $2.34 per diluted share, in 2001 compared to net income of $38.6 million,
or $1.70 per basic share and $1.61 per diluted share, in 2000.
Liquidity and Capital Resources
The Company has experienced and expects to continue to experience
substantial capital requirements, primarily due to its active exploration and
development programs in the Gulf of Mexico. Spinnaker has capital expenditure
plans for 2003 totaling approximately $250.0 million. Spinnaker has
participated in a significant deepwater oil discovery, Front Runner, with a 25%
non-operator working interest. Spinnaker incurred capital expenditures
associated with Front Runner of $40.8 million in 2002 and $70.2 million from
inception through December 31, 2002. The Company expects to incur approximately
$86.0 million in future development costs related to Front Runner, including
approximately $46.0 million in 2003, $21.0 million in 2004 and $19.0 million
thereafter.
Natural gas and oil prices have a significant impact on the Company's cash
flows available for capital expenditures and its ability to borrow and raise
additional capital. The amount the Company can borrow under its
33
Credit Facility is subject to periodic re-determination based in part on
changing expectations of future prices. Lower prices may also reduce the amount
of natural gas and oil that the Company can economically produce. Additionally,
the rapid production declines of certain producing wells resulted in lower
production in 2002. The Company expects a decline in production during the
first quarter of 2003 from the 16.3 Bcfe reported in the fourth quarter of 2002
due to the rapid production decline of certain producing wells and shut-ins for
pipeline repairs. Lower prices and/or lower production may decrease revenues,
cash flows and the borrowing base under the Credit Facility, thus reducing the
amount of financial resources available to meet the Company's capital
requirements. The Company believes that working capital, cash flows from
operations and proceeds from available borrowings under its Credit Facility
will be sufficient to meet its capital requirements in the next twelve months.
However, additional debt or equity financing may be required in the future to
fund growth and exploration and development programs. In the event additional
capital resources are unavailable, the Company may curtail its drilling,
development and other activities or be forced to sell some of its assets on an
untimely or unfavorable basis.
On April 3, 2002, the Company completed a public offering of 5,750,000
shares of Common Stock at $41.50 per share, including the over-allotment option
consisting of 750,000 shares. After payment of underwriting discounts and
commissions, the Company received net proceeds of $227.9 million. On April 3,
2002, the Company used a portion of the proceeds from the offering to repay
outstanding borrowings of $37.0 million. The remaining net proceeds were
invested in short-term high quality investments and are being used to fund a
portion of the costs to develop the Company's deepwater oil discovery at Front
Runner, to fund a portion of exploration and other development activities and
for general corporate purposes, including possible acquisitions of properties
or seismic data.
Spinnaker has an effective shelf registration statement relating to the
potential public offer and sale by the Company or certain of its affiliates of
up to $500.0 million of any combination of debt securities, preferred stock,
common stock, warrants, stock purchase contracts and trust preferred securities
from time to time or when financing needs arise. The registration statement
does not provide assurance that the Company will or could sell any such
securities.
Cash and cash equivalents increased $18.5 million to $32.5 million at
December 31, 2002. The components of the increase in cash and cash equivalents
include $154.0 million provided by operating activities, $363.8 million used in
investing activities and $228.3 million provided by financing activities.
Operating Activities
Net cash provided by operating activities in 2002 decreased 26% to $154.0
million primarily due to lower commodity prices and production. Cash flow from
operations is dependent upon the Company's ability to increase production
through its exploration and development programs and the prices of natural gas
and oil. The Company has made significant investments to expand its operations
in the Gulf of Mexico. These investments increased the Company's average daily
production in the fourth quarter of 2002 as compared to prior quarters;
however, the Company expects a decline in production during the first quarter
of 2003 from the 16.3 Bcfe reported in the fourth quarter of 2002.
The Company sells its natural gas and oil production under fixed or floating
market price contracts. Spinnaker enters into hedging arrangements from time to
time to reduce its exposure to fluctuations in natural gas and oil prices and
achieve more predictable cash flow. However, these contracts also limit the
benefits the Company would realize if prices increase. See "Item 7A.
Quantitative and Qualitative Disclosures About Market Risk."
The Company's cash flow from operations also depends on its ability to
manage working capital, including accounts receivable, accounts payable and
accrued liabilities. The net increase of $13.4 million in accounts receivable
was primarily related to an increase in the natural gas and oil revenue accrual
due to higher production and commodity prices in December 2002 compared to
December 2001. The net decrease of $15.1 million in
34
accounts payable and accrued liabilities was primarily due to the reversal of
current deferred taxes of $7.2 million related to the fair value of open
derivative contracts at December 31, 2001. In connection with the fair value of
open derivative contracts at December 31, 2002, the Company recorded a net
deferred tax asset of $7.2 million in other current assets.
Investing Activities
Net cash used in investing activities in 2002 increased 37% to $363.8
million compared to 2001. Net oil and gas property capital expenditures were
$356.6 million and other property and equipment capital expenditures were $7.2
million.
As part of its strategy, the Company explores for natural gas and oil at
deeper drilling depths and in the deep waters of the Gulf of Mexico, where
operations are more difficult and costly than at shallower drilling depths and
in shallower waters. Along with higher risks and costs associated with these
areas, greater opportunity exists for reserve additions. The Company has
experienced and will continue to experience significantly higher drilling costs
for its deep shelf and deepwater projects relative to the drilling costs on
shallower depth shelf projects in the Gulf of Mexico. The Company drilled 26
wells in 2002, 14 of which were successful. In 2001, the Company drilled 35
wells, 19 of which were successful. Since inception and through December 31,
2002, the Company has drilled 120 wells, 70 of which were successful,
representing a success rate of 58%. Dry hole costs, including associated
leasehold costs, were $72.6 million in 2002.
Purchases of other property and equipment increased to $7.2 million in 2002
primarily due to expenditures for seismic hardware and software of $4.1
million, leasehold improvements of $1.4 million and other hardware and software
upgrades and other equipment of $1.7 million.
The Company has capital expenditure plans for 2003 totaling approximately
$250.0 million, primarily for costs related to exploration and development
programs. The Company does not anticipate any significant abandonment or
dismantlement costs in 2003. Actual levels of capital expenditures may vary due
to many factors, including drilling results, natural gas and oil prices, the
availability of capital, industry conditions, acquisitions, decisions of
operators and other prospect owners and the prices of drilling rig dayrates and
other oilfield goods and services. In 2002, the Company incurred acquisition,
exploration and development costs of $39.8 million, $163.3 million and $139.4
million, respectively. The costs associated with unproved properties and
properties under development not included in the amortization base were $141.3
million and $102.9 million as of December 31, 2002 and 2001, respectively, and
included the following (in thousands):
As of December 31,
-----------------
2002 2001
-------- --------
Leasehold, delay rentals and seismic data $122,409 $ 92,150
Wells in-progress........................ 17,639 10,112
Other.................................... 1,278 619
-------- --------
Total................................. $141,326 $102,881
======== ========
Financing Activities
Net cash provided by financing activities of $228.3 million in 2002 included
proceeds from the public offering of Common Stock and $37.0 million in proceeds
from and subsequent payments on borrowings. The Company received net proceeds
of $227.9 million from the Common Stock offering on April 3, 2002, and used a
portion of the proceeds from the offering to repay outstanding borrowings of
$37.0 million.
On December 28, 2001, the Company replaced its $75.0 million credit facility
with an unsecured $200.0 million Credit Facility with a group of seven banks.
The borrowing base of the three-year Credit Facility is
35
re-determined on or about April 30 and September 30 each year. The banks and
Spinnaker also have the option to request one additional re-determination each
year. The banks determine the borrowing base at their sole discretion and in
their usual and customary manner. The amount of the borrowing base is a
function of the banks' view of the Company's reserve profile as well as
commodity prices. The current borrowing base is $100.0 million. The Company has
the option to elect to use a base interest rate as described below or the LIBOR
rate plus, for each such rate, a spread based on the percentage of the
borrowing base used at that time. The base interest rate under the Credit
Facility is a fluctuating rate of interest equal to the higher of either
Toronto-Dominion Bank's base rate for dollar advances made in the United States
or the Federal Funds Rate plus 0.5% per annum. The commitment fee rate ranges
from 0.3% to 0.5%, depending on the borrowing base usage.
The Credit Facility contains various 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 arising under hedging agreements, indebtedness incurred in
the ordinary course of business not to exceed $1.0 million, unsecured
vendor indebtedness of the Company related to purchases of 2-D and 3-D
seismic data made in the ordinary course of business in an amount not to
exceed $25.0 million, other unsecured indebtedness in an amount not to
exceed $10.0 million in the aggregate;
. may not incur any liens upon properties or assets other than permitted
liens securing indebtedness of up to $1.0 million, liens on the 2-D and
3-D seismic data securing the indebtedness permitted to acquire such
data, pledges or deposits to secure hedging agreements up to $15.0
million, liens on property required as a condition to enter into a
synthetic lease transaction in the ordinary course of business and other
liens in the ordinary course of business;
. may not dispose of any assets or properties except obsolete equipment,
inventory sold in the ordinary course of business, reserves in non-proved
categories, a second license in certain seismic data, or interests in
natural gas and oil properties included in the borrowing base in an
aggregate amount not to exceed $25.0 million in any fiscal year;
. may not make or pay any dividend, distribution or payment in respect of
capital stock nor purchase, redeem, acquire, retire or permit any
reduction or retirement of capital stock in excess of $10.0 million in
any fiscal year;
. must maintain the ratio of consolidated current assets to consolidated
current liabilities as of the end of each fiscal quarter so that it is
not less than 1.00 to 1.00. For purposes of the calculation, availability
under the Credit Facility is included as current assets, any payments of
principal owing under the Credit Facility required to be repaid within
one year from the time of the calculation are excluded from current
liabilities and mark-to-market hedging exposure is excluded from both
current assets and current liabilities;
. must maintain a tangible net worth so that it is not less than the sum of
80% of the tangible net worth as of September 30, 2001, plus 50% of the
adjusted consolidated net income for each fiscal quarter since the
closing of the Credit Facility, plus 75% of the proceeds from the sale of
any security, including without limitation, common equity, preferred
equity or other equity interests or equity securities including warrants,
options and the like issued after the closing of the Credit Facility; and
. may not enter into any hedging agreement unless the percent of volumes to
be hedged to estimated production volumes for such month from total
internally-projected proved reserves does not exceed: 100% for the period
one to three months from and after the hedging agreement transaction
date, 66 2/3% for the period four to 18 months from and after the hedging
agreement transaction date and 33 1/3% for the period 19 to 36 months
from and after the hedging agreement transaction date. Additionally, at
no time will any hedging agreement of any nature have a counterparty with
a minimum long-term senior unsecured indebtedness rating less than "BBB+"
by Standard & Poor's or "Baa1" by Moody's Investors Services, Inc. at the
time that such counterparty entered into the relevant transaction under
such hedging
36
agreement and at no time will exposure to any single counterparty exceed
25% of the estimated twelve-month production volumes from total proved
reserves.
At December 31, 2002, the Company was in compliance with the covenants and
restrictive provisions and had no outstanding borrowings under the Credit
Facility. The Company expects to borrow under the Credit Facility in 2003 and
be in compliance with the covenants and restrictive provisions for the next
twelve months.
Contractual Obligations
The Company leases administrative offices, office equipment and oil and gas
equipment under non-cancelable operating leases. The Company had no long-term
debt, capital lease or purchase obligations or other contractual long-term
liabilities as of December 31, 2002. The Company has incurred obligations in
the ordinary course of business under purchase and service agreements that are
not included in the table below, including obligations of approximately $35.4
million and $6.7 million in 2003 and 2004, respectively, for construction of
the Front Runner spar production facility. Operating lease obligations as of
December 31, 2002 are as follows (in thousands):
Payments Due by Period
-------------------------------------
Less than 1-3 4-5 After
Total 1 Year Years Years 5 Years
------ --------- ------ ----- -------
Operating leases............. $6,032 $1,708 $3,800 $524 $--
Other contractual obligations -- -- -- -- --
------ ------ ------ ---- ---
Total........................ $6,032 $1,708 $3,800 $524 $--
====== ====== ====== ==== ===
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 cash and cash equivalents and the interest
rate paid on borrowings under the Credit Facility. The Company does not
currently use interest rate derivative instruments to manage exposure to
interest rate changes, but may do so in the future.
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. Lower prices may also reduce the amount of
natural gas and oil that the Company can economically produce. The Company
sells its natural gas and oil production under fixed or floating market price
contracts. Spinnaker enters into hedging arrangements from time to time to
reduce its exposure to fluctuations in natural gas and oil prices and to
achieve more predictable cash flow. Spinnaker does not enter into such hedging
arrangements for trading purposes. However, these contracts also limit the
benefits the Company would realize if prices increase. These financial
arrangements are fixed price swap contracts and cashless collar arrangements
and are placed with major trading counterparties the Company believes represent
minimum credit risks. Spinnaker cannot provide assurance that these trading
counterparties will not become credit risks in the future. Under its current
hedging practice, the Company generally does not hedge more than 66 2/3% of its
estimated twelve-month production quantities without the prior approval of the
risk management committee of the board of directors.
On January 1, 2001, the Company adopted SFAS No. 133, as amended,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
established accounting and reporting standards requiring that all derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in a
derivative's fair value be realized currently in earnings unless
37
specific hedge accounting criteria are met. Accounting for qualifying hedges
allows derivative gains and losses to offset related results on the hedged
items in the statement of operations and requires a company to formally
document, designate and assess the effectiveness of transactions that qualify
for hedge accounting.
The Company enters into New York Mercantile Exchange ("NYMEX") related swap
contracts and collar arrangements from time to time. The Company's swap
contracts and collar arrangements will settle based on the reported settlement
price on the NYMEX for the last trading day of each month for natural gas.
In a swap transaction, the counterparty is required to make a payment to the
Company for the difference between the fixed price and the settlement price if
the settlement price is below the fixed price. The Company is required to make
a payment to the counterparty for the difference between the fixed price and
the settlement price if the settlement price is above the fixed price. As of
December 31, 2002, Spinnaker's commodity price risk management positions in
fixed price natural gas swap contracts and related fair value were as follows:
Average Weighted
Daily Average
Volume Price Fair Value
Period (MMBtus) (Per MMBtu) (in thousands)
------ -------- ----------- --------------
First Quarter 2003. 60,000 $3.71 $ (5,979)
Second Quarter 2003 53,297 3.55 (4,411)
Third Quarter 2003. 50,000 3.55 (4,068)
Fourth Quarter 2003 50,000 3.63 (4,340)
--------
Year 2003.......... 53,288 $3.61 $(18,798)
========
In a collar arrangement, the counterparty is required to make a payment to
the Company for the difference between the fixed floor price and the settlement
price if the settlement price is below the fixed floor price. The Company is
required to make a payment to the counterparty for the difference between the
fixed ceiling price and the settlement price if the settlement price is above
the fixed ceiling price. Neither party is required to make a payment if the
settlement price falls between the fixed floor price and the fixed ceiling
price. As of December 31, 2002, Spinnaker's commodity price risk management
positions in natural gas collar arrangements and related fair value were as
follows:
Average Weighted Weighted
Daily Average Average
Volume Floor Price Ceiling Price Fair Value
Period (MMBtus) (Per MMBtu) (Per MMBtu) (in thousands)
------ -------- ----------- ------------- --------------
First Quarter 2003. 15,000 $3.25 $5.21 $ (228)
Second Quarter 2003 15,000 3.25 5.21 (262)
Third Quarter 2003. 15,000 3.25 5.21 (287)
Fourth Quarter 2003 15,000 3.25 5.21 (342)
-------
Year 2003.......... 15,000 $3.25 $5.21 $(1,119)
=======
38
The Company reported a net liability of $19.9 million and a net asset of
$22.3 million related to its derivative contracts at December 31, 2002 and
2001, respectively. Amounts related to hedging activities as of December 31,
2002 and 2001 were as follows (in thousands):
As of December 31,
-----------------
2002 2001
-------- -------
Current assets:
Hedging asset......................................... $ -- $20,593
Deferred tax asset related to hedging activities...... 7,170 --
Non-current assets:
Hedging asset......................................... $ -- $ 1,726
Current liabilities:
Hedging liability..................................... $ 19,917 $ --
Deferred tax liability related to hedging activities.. -- 7,208
Non-current liabilities:
Deferred tax liability related to hedging activities.. $ -- $ 604
Accumulated other comprehensive income (loss):
Accumulated other comprehensive income (loss)......... $(19,917) $22,319
Income taxes.......................................... 7,170 (7,812)
-------- -------
Accumulated other comprehensive income (loss)..... $(12,747) $14,507
The Company recognized a net hedging gain of $4.7 million and net hedging
losses of $9.6 million and $18.7 million in revenues in 2002, 2001 and 2000,
respectively. There was no ineffective component of the derivatives recognized
in earnings in 2002 and 2001. Based on future natural gas prices as of December
31, 2002, the Company would reclassify a net loss of $12.7 million from
accumulated other comprehensive income (loss) to earnings within the next
twelve months. The amounts ultimately reclassified into earnings will vary due
to changes in the fair value of the open derivative contracts prior to
settlement.
Subsequent to December 31, 2002, Spinnaker has not entered into additional
hedging arrangements. Natural gas prices have fluctuated widely in early 2003.
The Company will recognize net hedging losses of $17.7 million in the first
quarter of 2003 based on natural gas price settlements. If natural gas prices
remain at current levels, Spinnaker will incur significant hedging losses in
the remainder of 2003.
To calculate the potential effect of the derivative contracts on future
revenues, the Company applied NYMEX natural gas forward prices as of December
31, 2002 to the quantity of the Company's natural gas production covered by
those derivative contracts as of that date. The following table shows the
estimated potential effects of the derivative financial instruments on future
revenues (in thousands):
Estimated Estimated
Estimated Decrease in Decrease in
Decrease in Revenues Revenues
Revenues at with 10% with 10%
Current Decrease in Increase in
Derivative Instrument Prices Prices Prices
--------------------- ----------- ----------- -----------
Fixed price swap transactions $(18,798) $(10,926) $(26,912)
Collar arrangements.......... $ (1,119) $ (289) $ (2,216)
Item 8. Financial Statements and Supplementary Data
The consolidated financial statements and supplementary data of the Company
appear on pages 46 through 71 hereof and are incorporated by reference into
this Item 8. Selected quarterly financial data is set forth in Note 13 of the
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 disagreements with the Company's accountants or any
reportable events regarding accounting principles or practices or financial
statement disclosures.
39
PART III
Item 10. Directors and Executive Officers of the Registrant
The Company's Definitive Proxy Statement for its 2003 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this annual report
on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide
the information required under Part III, Item 10.
Item 11. Executive Compensation
The Company's Definitive Proxy Statement for its 2003 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this annual report
on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide
the information required under Part III, Item 11.
Item 12. Security Ownership of Certain Beneficial Owners and Management and
Related Stockholder Matters
The Company's Definitive Proxy Statement for its 2003 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this annual report
on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide
the information required under Part III, Item 12.
At December 31, 2002, officers, directors and employees had been granted
options to purchase Common Stock under stock plans adopted in 1998, 1999, 2000
and 2001. The following table provides "Securities Authorized for Issuance
Under Equity Compensation Plans":
Number of Number of
securities to securities
be issued remaining
upon exercise Weighted-average available for
of outstanding exercise price of future issuance
options, outstanding under equity
warrants and options, warrants compensation
Plan category rights and rights plans
------------- -------------- ----------------- ---------------
Equity compensation plans approved by security holders.... 3,954,002 $23.00 137,476
Equity compensation plans not approved by security holders 432,531 $31.81 67,059
--------- -------
Total.................................................. 4,386,533 $23.87 204,535
========= =======
The Spinnaker Exploration Company 2000 Stock Option Plan (the "2000 Plan")
was adopted by the board of directors of Spinnaker without the approval of the
stockholders of the Company in order for Spinnaker to grant options to purchase
Common Stock as a material inducement to certain persons who were not
previously employed by the Company to enter into an employment contract with
the Company. The number of shares of Common Stock that may be issued under the
2000 Plan may not exceed 500,000 shares. The purchase price of any Common Stock
pursuant to any options granted under the 2000 Plan may not be less than 80% of
the fair market value of the Common Stock on the date the option is granted,
subject to certain limited exceptions. The Company has not granted nor does it
intend to grant any options under the 2000 Plan at a price below the fair
market value of the Common Stock on the date of grant.
40
Item 13. Certain Relationships and Related Transactions
The Company's Definitive Proxy Statement for its 2003 Annual Meeting of
Stockholders, when filed pursuant to Regulation 14A under the Securities
Exchange Act of 1934, will be incorporated by reference into this annual report
on Form 10-K pursuant to General Instruction G(3) of Form 10-K and will provide
the information required under Part III, Item 13.
Item 14. Controls and Procedures
(a) Evaluation of disclosure controls and procedures. Within 90 days
before the filing of this annual report on Form 10-K, the Company's principal
executive officer and principal financial officer evaluated the effectiveness
of the Company's disclosure controls and procedures. Based on the evaluation,
the Company's principal executive officer and principal financial officer
believe that:
. the Company's disclosure controls and procedures are designed to ensure
that information required to be disclosed by the Company in the reports
it files or submits under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods
specified in the Securities and Exchange Commission's rules and forms; and
. the Company's disclosure controls and procedures were effective to ensure
that material information was accumulated and communicated to the
Company's management, including the Company's principal executive officer
and principal financial officer, as appropriate to allow timely decisions
regarding required disclosure.
(b) Changes in internal controls. There have been no significant changes
in the Company's internal controls or in other factors that could significantly
affect the Company's internal controls subsequent to their evaluation, nor have
there been any corrective actions with regard to significant deficiencies or
material weaknesses.
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
(a) Financial Statements
(1) and (2) Financial Statements and Schedules
See "Index to Consolidated Financial Statements" on page 46.
(3) Exhibits
See "Exhibit Index" on page 72.
41
The management contracts and compensatory plans or arrangements required to
be filed as exhibits to this report are as follows:
Exhibit
Number Description
------- -----------
10.2 --Amended and Restated 1998 Spinnaker Stock Option Plan (incorporated by reference to Exhibit
10.2 to Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
10.6 --Employment Agreement between Spinnaker and Roger L. Jarvis dated December 20, 1996, as
amended (incorporated by reference to Exhibit 10.6 to Spinnaker's Registration Statement on
Form S-1 (Commission File No. 333-83093))
10.7 --Employment Agreement between Spinnaker and William D. Hubbard dated February 24, 1997, as
amended (incorporated by reference to Exhibit 10.8 to Spinnaker's Registration Statement on
Form S-1 (Commission File No. 333-83093))
10.8 --Employment Agreement between Spinnaker and Kelly M. Barnes dated February 24, 1997, as
amended (incorporated by reference to Exhibit 10.9 to Spinnaker's Registration Statement on
Form S-1 (Commission File No. 333-83093))
10.9 --1999 Spinnaker Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to Spinnaker's
Registration Statement on Form S-1 (Commission File No. 333-83093))
10.10 --1999 Spinnaker Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.11 to
Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
10.12 --Adjunct Stock Option Plan (incorporated by reference to Exhibit 4.3 to Spinnaker's Registration
Statement on Form S-8 (Commission File No. 333-36592))
10.13 --Spinnaker Exploration Company 2000 Stock Option Plan (incorporated by reference to Exhibit
10.13 to Spinnaker's Annual Report on Form 10-K for the year ended December 31, 2000)
10.14 --Spinnaker Exploration Company 2001 Stock Incentive Plan, as amended (incorporated by
reference to Exhibit 10.2 to Spinnaker's Registration Statement on Form S-8 (Commission File
No. 333-61888))
(b) Reports on Form 8-K
A Current Report on Form 8-K dated November 12, 2002 and filed on
November 13, 2002 furnished under "Item 9. Regulation FD Disclosure" the
certifications by each of the Chief Executive Officer and the Chief
Financial Officer that accompanied the Company's Quarterly Report on Form
10-Q for the period ended September 30, 2002 in accordance with 18 U.S.C.
Section 1350. No financial statements were filed therewith.
42
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 25, 2003 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.
Signature Title Date
--------- ----- ----
/s/ ROGER L. JARVIS Chairman, President, Chief March 25, 2003
----------------------------- Executive Officer and
Roger L. Jarvis Director
/s/ ROBERT M. SNELL Vice President, Chief March 25, 2003
----------------------------- Financial Officer and
Robert M. Snell Secretary (Principal
Financial Officer)
/s/ JEFFREY C. ZARUBA Vice President, Treasurer and March 25, 2003
----------------------------- Assistant Secretary
Jeffrey C. Zaruba (Principal Accounting
Officer)
/s/ SHELDON R. ERIKSON Director March 25, 2003
-----------------------------
Sheldon R. Erikson
/s/ JEFFREY A. HARRIS Director March 25, 2003
-----------------------------
Jeffrey A. Harris
/s/ MICHAEL E. MCMAHON Director March 25, 2003
-----------------------------
Michael E. McMahon
/s/ MICHAEL G. MORRIS Director March 25, 2003
-----------------------------
Michael G. Morris
/s/ HOWARD H. NEWMAN Director March 25, 2003
-----------------------------
Howard H. Newman
/s/ MICHAEL E. WILEY Director March 25, 2003
-----------------------------
Michael E. Wiley
43
CERTIFICATION OF
PRINCIPAL EXECUTIVE OFFICER
OF SPINNAKER EXPLORATION COMPANY
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT
I, Roger L. Jarvis, certify that:
1. I have reviewed this annual report on Form 10-K of Spinnaker Exploration
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 25, 2003
/s/ ROGER L. JARVIS
--------------------------------------
Name: Roger L. Jarvis
Title: Chief Executive Officer
44
CERTIFICATION OF
PRINCIPAL FINANCIAL OFFICER
OF SPINNAKER EXPLORATION COMPANY
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT
I, Robert M. Snell, certify that:
1. I have reviewed this annual report on Form 10-K of Spinnaker Exploration
Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
annual report (the "Evaluation Date"); and
c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of
the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any
corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 25, 2003
/s/ ROBERT M. SNELL
--------------------------------------
Name: Robert M. Snell
Title: Chief Financial Officer
45
SPINNAKER EXPLORATION COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
----
Independent Auditors' Report.............................................................. 47
Consolidated Balance Sheets as of December 31, 2002 and 2001.............................. 48
Consolidated Statements of Operations for each of the years in the three-year period ended
December 31, 2002....................................................................... 49
Consolidated Statements of Equity for each of the years in the three-year period ended
December 31, 2002....................................................................... 50
Consolidated Statements of Cash Flows for each of the years in the three-year period ended
December 31, 2002....................................................................... 51
Notes to Consolidated Financial Statements................................................ 52
Independent Auditors' Report on Consolidated Financial Statement Schedule................. 70
Schedule II--Valuation and Qualifying Accounts and Reserves............................... 71
46
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Spinnaker Exploration Company:
We have audited the accompanying consolidated balance sheets of Spinnaker
Exploration Company and subsidiaries, as of December 31, 2002 and 2001, and the
related consolidated statements of operations, equity and cash flows for each
of the years in the three-year period ended December 31, 2002. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. 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 consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Spinnaker
Exploration Company and subsidiaries as of December 31, 2002 and 2001, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
As explained in Note 2 to the consolidated financial statements, effective
January 1, 2001, the Company changed its method of accounting for its
derivative instruments.
KPMG LLP
Houston, Texas
February 7, 2003
47
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
As of December 31,
---------------------
2002 2001
---------- ---------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents........................................................ $ 32,543 $ 14,061
Accounts receivable, net of allowance for doubtful accounts of $3,232 and $3,059
at December 31, 2002 and 2001, respectively.................................... 37,572 24,129
Hedging assets................................................................... -- 20,593
Other............................................................................ 11,438 3,664
---------- ---------
Total current assets......................................................... 81,553 62,447
PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties.............................................................. 879,840 575,806
Unproved properties and properties under development, not being amortized...... 141,326 102,881
Other............................................................................ 14,461 7,245
---------- ---------
1,035,627 685,932
Less--Accumulated depreciation, depletion and amortization....................... (274,773) (163,359)
---------- ---------
Total property and equipment................................................. 760,854 522,573
OTHER ASSETS........................................................................ 308 2,296
---------- ---------
Total assets................................................................. $ 842,715 $ 587,316
========== =========
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable................................................................. $ 29,453 $ 32,383
Accrued liabilities and other.................................................... 38,542 50,718
Hedging liabilities.............................................................. 19,917 --
---------- ---------
Total current liabilities.................................................... 87,912 83,101
DEFERRED INCOME TAXES............................................................... 61,826 45,723
COMMITMENTS AND CONTINGENCIES (Note 11)
EQUITY:
Preferred stock, $0.01 par value; 10,000,000 shares authorized; no shares issued
and outstanding at December 31, 2002 and 2001, respectively.................... -- --
Common stock, $0.01 par value; 50,000,000 shares authorized; 33,184,463 shares
issued and 33,171,759 shares outstanding at December 31, 2002 and
27,308,912 shares issued and 27,293,264 shares outstanding at December 31,
2001........................................................................... 332 273
Additional paid-in capital....................................................... 596,087 365,993
Retained earnings................................................................ 109,337 77,758
Less: Treasury stock, at cost, 12,704 and 15,648 shares at December 31, 2002 and
2001, respectively............................................................. (32) (39)
Accumulated other comprehensive income (loss).................................... (12,747) 14,507
---------- ---------
Total equity................................................................. 692,977 458,492
---------- ---------
Total liabilities and equity................................................. $ 842,715 $ 587,316
========== =========
The accompanying notes are an integral part of these consolidated financial
statements.
48
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
Year Ended December 31,
----------------------------
2002 2001 2000
-------- -------- --------
REVENUES......................................................... $188,326 $210,376 $121,383
EXPENSES:
Lease operating expenses...................................... 18,212 12,132 9,009
Depreciation, depletion and amortization--natural gas and oil
properties.................................................. 108,998 85,059 47,451
Depreciation and amortization--other.......................... 914 398 309
General and administrative.................................... 10,984 9,443 7,350
Charges related to Enron bankruptcy........................... 128 3,059 --
-------- -------- --------
Total expenses............................................ 139,236 110,091 64,119
-------- -------- --------
INCOME FROM OPERATIONS........................................... 49,090 100,285 57,264
OTHER INCOME (EXPENSE):
Interest income............................................... 1,014 3,574 2,908
Interest expense, net......................................... (762) (381) (748)
-------- -------- --------
Total other income (expense).............................. 252 3,193 2,160
-------- -------- --------
INCOME BEFORE INCOME TAXES....................................... 49,342 103,478 59,424
Income tax expense............................................ 17,763 37,252 20,858
-------- -------- --------
NET INCOME....................................................... $ 31,579 $ 66,226 $ 38,566
======== ======== ========
NET INCOME PER COMMON SHARE:
Basic......................................................... $ 1.00 $ 2.45 $ 1.70
======== ======== ========
Diluted....................................................... $ 0.97 $ 2.34 $ 1.61
======== ======== ========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING:
Basic......................................................... 31,695 27,079 22,679
======== ======== ========
Diluted....................................................... 32,653 28,360 24,011
======== ======== ========
The accompanying notes are an integral part of these consolidated financial
statements.
49
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands, except share data)
Retained Accumulated
Shares Issued Par Value Additional Earnings Other
-------------------- ---------------- Paid-In (Accumulated Treasury Comprehensive Total
Preferred Common Preferred Common Capital Deficit) Stock Income (Loss) Equity
--------- ---------- --------- ------ ---------- ------------ -------- ------------- --------
Balance, December 31, 1999.... -- 20,426,192 $-- $204 $203,987 $(27,034) $(55) $ -- $177,102
Net income.................. -- -- -- -- -- 38,566 -- -- 38,566
Comprehensive income........
Common stock issuance, net
of issuance costs.......... -- 5,600,000 -- 56 138,342 -- -- -- 138,398
Exercise of stock options... -- 462,478 -- 5 3,195 -- 11 -- 3,211
Employer contributions to
401(k) Plan................ -- 5,923 -- -- 148 -- -- -- 148
Stock compensation costs.... -- -- -- -- 158 -- -- -- 158
Tax benefit associated with
exercise of non-qualified
stock options.............. -- -- -- -- 3,676 -- -- -- 3,676
-- ---------- ---- ---- -------- -------- ---- -------- --------
Balance, December 31, 2000.... -- 26,494,593 $ -- $265 $349,506 $ 11,532 $(44) $ -- $361,259
Net income.................. -- -- -- -- -- 66,226 -- -- 66,226
Other comprehensive income,
net of tax:
Cumulative effect of
accounting change for
derivative financial
instruments................ -- -- -- -- -- -- -- (27,126) (27,126)
Net change in fair value of
derivative financial
instruments................ -- -- -- -- -- -- -- 35,502 35,502
Financial derivative
settlements reclassed to
income..................... -- -- -- -- -- -- -- 6,131 6,131
Comprehensive income........
Exercise of stock options... -- 808,863 -- 8 7,142 -- 5 -- 7,155
Employer contributions to
401(k) Plan................ -- 5,456 -- -- 216 -- -- -- 216
Stock compensation costs.... -- -- -- -- 114 -- -- -- 114
Tax benefit associated with
exercise of non-qualified
stock options.............. -- -- -- -- 9,015 -- -- -- 9,015
-- ---------- ---- ---- -------- -------- ---- -------- --------
Balance, December 31, 2001.... -- 27,308,912 $ -- $273 $365,993 $ 77,758 $(39) $ 14,507 $458,492
Net income.................. -- -- -- -- -- 31,579 -- -- 31,579
Other comprehensive income,
net of tax:
Net change in fair value of
derivative financial
instruments................ -- -- -- -- -- -- -- (24,269) (24,269)
Financial derivative
settlements reclassed to
income..................... -- -- -- -- -- -- -- (2,985) (2,985)
Comprehensive income........
Common stock issuance, net
of issuance costs.......... -- 5,750,000 -- 58 227,326 -- -- -- 227,384
Exercise of stock options... -- 116,489 -- 1 948 -- 7 -- 956
Employer contributions to
401(k) Plan................ -- 9,062 -- -- 287 -- -- -- 287
Stock compensation costs.... -- -- -- -- 177 -- -- -- 177
Tax benefit associated with
exercise of non-qualified
stock options.............. -- -- -- -- 1,356 -- -- -- 1,356
-- ---------- ---- ---- -------- -------- ---- -------- --------
Balance, December 31, 2002.... -- 33,184,463 $ -- $332 $596,087 $109,337 $(32) $(12,747) $692,977
== ========== ==== ==== ======== ======== ==== ======== ========
Comprehensive
Income (Loss)
-------------
Balance, December 31, 1999....
Net income.................. $ 38,566
--------
Comprehensive income........ $ 38,566
========
Common stock issuance, net
of issuance costs..........
Exercise of stock options...
Employer contributions to
401(k) Plan................
Stock compensation costs....
Tax benefit associated with
exercise of non-qualified
stock options..............
Balance, December 31, 2000....
Net income.................. $ 66,226
Other comprehensive income,
net of tax:
Cumulative effect of
accounting change for
derivative financial
instruments................ (27,126)
Net change in fair value of
derivative financial
instruments................ 35,502
Financial derivative
settlements reclassed to
income..................... 6,131
--------
Comprehensive income........ $ 80,733
========
Exercise of stock options...
Employer contributions to
401(k) Plan................
Stock compensation costs....
Tax benefit associated with
exercise of non-qualified
stock options..............
Balance, December 31, 2001....
Net income.................. $ 31,579
Other comprehensive income,
net of tax:
Net change in fair value of
derivative financial
instruments................ (24,269)
Financial derivative
settlements reclassed to
income..................... (2,985)
--------
Comprehensive income........ $ 4,325
========
Common stock issuance, net
of issuance costs..........
Exercise of stock options...
Employer contributions to
401(k) Plan................
Stock compensation costs....
Tax benefit associated with
exercise of non-qualified
stock options..............
Balance, December 31, 2002....
The accompanying notes are an integral part of these consolidated financial
statements.
50
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Year Ended December 31,
-------------------------------
2002 2001 2000
--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................................... $ 31,579 $ 66,226 $ 38,566
Adjustments to reconcile net income to net cash provided by (used in)
operating activities:
Depreciation, depletion and amortization........................... 109,912 85,457 47,760
Deferred income tax expense........................................ 18,063 36,977 20,833
Other.............................................................. 881 549 306
Change in operating assets and liabilities:
Accounts receivable.............................................. (13,443) 21,465 (34,799)
Accounts payable and accrued liabilities......................... 7,726 (3,216) 14,861
Other assets..................................................... (759) 1,979 (5,523)
--------- --------- ---------
Net cash provided by operating activities...................... 153,959 209,437 82,004
CASH FLOWS FROM INVESTING ACTIVITIES:
Oil and gas properties............................................... (356,601) (287,225) (161,811)
Proceeds from sale of natural gas and oil assets..................... -- -- 5,971
Purchases of other property and equipment............................ (7,216) (1,603) (1,928)
Purchases of short-term investments.................................. -- (29,627) (22,387)
Sales of short-term investments...................................... -- 52,014 --
--------- --------- ---------
Net cash used in investing activities.......................... (363,817) (266,441) (180,155)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings............................................. 37,000 -- 17,000
Payments on borrowings............................................... (37,000) -- (17,000)
Proceeds from issuance of common stock............................... 227,873 -- 138,936
Common stock issuance costs.......................................... (489) -- (538)
Proceeds from exercise of stock options.............................. 956 7,155 3,211
--------- --------- ---------
Net cash provided by financing activities...................... 228,340 7,155 141,609
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS......................................................... 18,482 (49,849) 43,458
CASH AND CASH EQUIVALENTS, beginning of year.......................... 14,061 63,910 20,452
--------- --------- ---------
CASH AND CASH EQUIVALENTS, end of year................................ $ 32,543 $ 14,061 $ 63,910
========= ========= =========
SUPPLEMENTAL CASH FLOW DISCLOSURES:
Cash paid for interest, net of amounts capitalized................... $ 468 $ 190 $ 380
========= ========= =========
Cash paid (received) for income taxes, net........................... $ (300) $ 275 $ 25
========= ========= =========
The accompanying notes are an integral part of these consolidated financial
statements.
51
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization:
Spinnaker Exploration Company ("Spinnaker" or the "Company") was formed in
1996 and engages in the exploration, development and production of natural gas
and oil properties in the U.S. Gulf of Mexico.
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"),
and commenced trading the following day. After payment of underwriting
discounts and commissions, the Company received net proceeds of $108.7 million
on October 4, 1999. With a portion of the proceeds, the Company retired all
outstanding debt of $72.0 million. In connection with the initial public
offering, the Company converted all outstanding 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.
2. Summary of Significant Accounting Policies:
A summary of significant accounting policies followed in the preparation of
the accompanying consolidated financial statements is set forth below:
General
The accompanying consolidated financial statements of the Company have been
prepared in accordance with accounting principles generally accepted in the
United States and pursuant to the rules and regulations of the Securities and
Exchange Commission (the "Commission").
Principles of Consolidation
The accompanying consolidated financial statements include the activities
and accounts of the Company and its subsidiaries, all of which are wholly
owned. 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 as of the date
of the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
Significant estimates include depreciation, depletion and amortization ("DD&A")
of proved natural gas and oil properties. Natural gas and oil reserve
estimates, which are the basis for unit-of-production DD&A and the full cost
ceiling test, are inherently imprecise and are expected to change as future
information becomes available.
Cash Equivalents
The Company considers all highly liquid investments with a maturity of three
months or less when purchased to be cash equivalents.
Other Current Assets
Other current assets include unamortized debt financing costs of $0.3
million and $0.3 million at December 31, 2002 and 2001, respectively. Other
non-current assets include unamortized debt financing costs of $0.3 million and
$0.6 million at December 31, 2002 and 2001, respectively. These costs are
amortized to interest
52
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
expense over the three-year term of the related credit facility. Amortization
of these and other debt financing costs included in interest expense was $0.3
million, $0.2 million and $0.4 million for the years ended December 31, 2002,
2001 and 2000, respectively.
Full Cost Method of Accounting
The Company uses the full cost method of accounting for its investments in
natural gas and oil properties. Under this method, all acquisition, exploration
and development costs, including certain related employee costs, incurred for
the purpose of exploring for and developing natural gas and oil are
capitalized. Acquisition costs include costs incurred to purchase, lease or
otherwise acquire property. Exploration costs include the costs of drilling
exploratory wells, including those in progress, geological and geophysical
service costs and depreciation of support equipment used in exploration
activities. Development costs include the costs of drilling development wells
and costs of completions, platforms, facilities and pipelines. Costs associated
with production and general corporate activities are expensed in the period
incurred. Sales of natural gas and oil properties, whether or not being
amortized currently, are accounted for as adjustments of capitalized costs,
with no gain or loss recognized, unless such adjustments would significantly
alter the relationship between capitalized costs and proved reserves of natural
gas and oil. 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.
DD&A
The Company computes the provision for DD&A of natural gas and oil
properties using the unit-of-production method based upon production and
estimates of proved reserve quantities. Unevaluated costs and related carrying
costs are excluded from the amortization base until the properties associated
with these costs are evaluated. In addition to costs associated with evaluated
properties, the amortization base includes estimated future development costs
and dismantlement, restoration and abandonment costs, net of estimated salvage
values.
Certain future development costs may be excluded from amortization when
incurred in connection with major development projects expected to entail
significant costs to ascertain the quantities of proved reserves attributable
to the properties under development. The amounts that may be excluded are
portions of the costs that relate to the major development project and have not
previously been included in the amortization base and the estimated future
expenditures associated with the development project. Such costs may be
excluded from costs to be amortized until the earlier determination of whether
additional reserves are proved or impairment occurs.
As of December 31, 2002, the Company excluded from the amortization base
estimated future expenditures of $29.4 million associated with common
development costs for its deepwater discovery at Front Runner. This estimate of
future expenditures associated with common development costs is based on
existing proved reserves to total proved reserves expected to be established
upon completion of the Front Runner project.
Full Cost Ceiling
Capitalized costs of natural gas and oil properties, net of accumulated DD&A
and related deferred taxes, are limited to the estimated future net cash flows
from proved natural gas and oil reserves, including the effects of hedging
activities in place as of December 31, 2002, 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 of the full cost pool
exceed the ceiling limitation, the excess is charged to expense.
53
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Capitalized Employee and Other General and Administrative Costs
Under the full cost method of accounting, certain costs are capitalized that
are directly identified with acquisition, exploration and development
activities. These capitalized costs include salaries, employee benefits, costs
of consulting services and other related costs and do not include costs related
to production, general corporate overhead or similar activities. Spinnaker
capitalized employee and other general and administrative costs of $5.9
million, $5.1 million and $3.8 million in 2002, 2001 and 2000, respectively.
Unproved Properties
The costs associated with unproved properties and properties under
development are not initially included in the amortization base and relate to
unevaluated leasehold acreage and delay rentals, seismic data, wells
in-progress and wells pending determination. Unevaluated leasehold costs and
delay rentals are either transferred to the amortization base with the costs of
drilling the related well or are assessed quarterly for possible impairment or
reduction in value. Unevaluated leasehold costs and delay rentals are
transferred to the amortization base if a reduction in value has occurred. The
costs of seismic data are transferred to the amortization base using the
sum-of-the-year's-digits method over a period of six years. The costs
associated with wells in-progress and wells pending determination are
transferred to the amortization base once a determination is made whether or
not proved reserves can be assigned to the property. The costs of drilling
exploratory dry holes and associated leasehold costs are included in the
amortization base immediately upon determination that the well is unsuccessful.
Of the $141.3 million of net unproved property costs at December 31, 2002
excluded from the amortizable base, net costs of $38.4 million, $19.7 million
and $42.5 million were incurred in 2002, 2001 and 2000, respectively, and $40.7
million was incurred prior to 2000. The majority of the costs will be evaluated
over the next five years.
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.
The costs associated with seismic hardware and software are included in
other property and equipment. These costs are amortized into the full cost pool
using the straight-line method over three years. Amortization was $1.5 million,
$0.5 million and $1.2 million in 2002, 2001 and 2000, respectively.
Revenue Recognition Policy
The Company records as revenue only that portion of production sold and
delivered 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-imbalances included in accounts receivable were $0.6 million
and $0.7 million at December 31, 2002 and 2001, respectively. Over-imbalances
included in accrued liabilities were $2.5 million and $0.7 million at December
31, 2002 and 2001, respectively.
Income Taxes
Under Statement of Financial Accounting Standards ("SFAS") No. 109,
"Accounting for Income Taxes," deferred income taxes are recognized at each
year-end for the future tax consequences of differences between the
54
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
Stock-Based Compensation
SFAS No. 148, "Accounting for Stock-Based Compensation--Transition and
Disclosure," amends SFAS No. 123 to provide alternative methods of transition
for an entity that voluntarily changes to the fair value based method of
accounting for stock-based employee compensation and to require prominent
disclosure about the effects on reported net income of an entity's accounting
policy decisions with respect to stock-based employee compensation. SFAS No.
148 amends Accounting Principles Board ("APB") Opinion No. 28, "Interim
Financial Reporting," to require disclosure about those effects in interim
financial information.
SFAS No. 123, "Accounting for Stock-Based Compensation," encourages, but
does not require, companies to record compensation cost for stock-based
employee compensation plans at fair value. The Company has chosen to account
for stock-based compensation using the intrinsic value method prescribed in APB
Opinion No. 25, "Accounting for Stock Issued to Employees," and related
interpretations. Accordingly, compensation cost for stock options is measured
as the excess, if any, of the fair value of the Common Stock at the date of the
grant over the amount an employee must pay to acquire the Common Stock. In
accordance with APB Opinion No. 25, compensation expense related to stock-based
compensation was $0.2 million, $0.1 million and $0.2 million in 2002, 2001 and
2000, respectively. Had compensation cost for the Company's stock option
compensation plans been determined based on the fair value at the grant dates
for awards under these plans consistent with the method of SFAS No. 123, the
Company's pro forma net income and pro forma net income per common share would
have been as follows (in thousands, except per share amounts):
Year Ended December 31,
-------------------------
2002 2001 2000
------- ------- -------
Net income, as reported................................................. $31,579 $66,226 $38,566
Add: Stock-based employee compensation expense included in reported net
income, net of related tax effects.................................... 114 73 103
Deduct: Total stock-based employee compensation expense determined under
fair value based method for all awards, net of related tax effects.... (8,902) (8,920) (3,126)
------- ------- -------
Pro forma net income.................................................... $22,791 $57,379 $35,543
======= ======= =======
Net income per common share:
Basic, as reported................................................... $ 1.00 $ 2.45 $ 1.70
======= ======= =======
Basic, pro forma..................................................... $ 0.72 $ 2.12 $ 1.57
======= ======= =======
Diluted, as reported................................................. $ 0.97 $ 2.34 $ 1.61
======= ======= =======
Diluted, pro forma................................................... $ 0.70 $ 2.02 $ 1.48
======= ======= =======
For purposes of the SFAS No. 123 disclosure, the fair value of each option
grant is estimated on the date of grant using the Black-Scholes option-pricing
model with assumptions for grants in 2002, 2001 and 2000 as follows:
Year Ended December 31,
-----------------------------------
2002 2001 2000
----------- ----------- -----------
Risk-free interest rate............. 3.98%-5.28% 4.85%-5.57% 5.14%-6.82%
Volatility factor................... 62.2% 43.0% 42.5%
Dividend yield...................... 0% 0% 0%
Expected life of the options (years) 4 4 4
55
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Financial Instruments and Price Risk Management Activities
At December 31, 2002, the Company's financial instruments consisted of cash
and cash equivalents, receivables, payables and derivative instruments. The
carrying amounts of cash and cash equivalents, receivables and payables
approximate fair value because of the short-term nature of these items. The
Company enters into hedging arrangements from time to time to reduce its
exposure to fluctuations in natural gas and oil prices and to achieve more
predictable cash flow. These hedging arrangements take the form of swap
contracts or cashless collars and are placed with major trading counterparties.
On January 1, 2001, the Company adopted SFAS No. 133, as amended,
"Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133
established accounting and reporting standards requiring that all derivative
instruments be recorded in the balance sheet as either an asset or liability
measured at its fair value. SFAS No. 133 requires that changes in a
derivative's fair value be realized currently in earnings unless specific hedge
accounting criteria are met. Accounting for qualifying hedges allows derivative
gains and losses to offset related results on the hedged items in the statement
of operations and requires a company to formally document, designate and assess
the effectiveness of transactions that qualify for hedge accounting. Upon
adoption of SFAS No. 133 on January 1, 2001, the Company designated its open
derivative contracts as cash flow hedges and recorded (i) a net current
liability of $41.7 million, representing the fair market value of all
derivatives on that date and (ii) a reduction of equity through accumulated
other comprehensive income (loss) of $27.1 million, representing the fair
market value of the derivatives as of January 1, 2001, net of deferred income
taxes of $14.6 million.
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. Derivative contracts also subject the Company to concentration of
credit risk. Management believes that the credit risk posed by this
concentration is mitigated by its hedging policy. The hedging policy requires
that (i) at no time will any hedging agreement of any nature have a
counterparty with a minimum long-term senior unsecured indebtedness rating less
than "BBB+" by Standard & Poor's or "Baa1" by Moody's Investors Services, Inc.
at the time that such counterparty entered into the relevant transaction under
such hedging agreement and (ii) at no time will exposure to any single
counterparty exceed 25% of the estimated twelve-month production volumes from
total proved reserves.
The Company had in place both financial hedge and physical contracts with
Enron North America Corp. at the time Enron Corp. and its subsidiaries filed
for bankruptcy in December 2001. Spinnaker did not receive payment for fixed
price swap contracts totaling $2.1 million which were intended to hedge
December 2001 natural gas sales, and $1.4 million related to November 2001
natural gas production sold to Enron entities. The Company has recorded a net
reserve of $3.2 million related to these receivables.
New Accounting Pronouncements
SFAS No. 143, "Accounting for Asset Retirement Obligations," requires
entities to record a liability for asset retirement obligations at fair value
in the period in which it is incurred and a corresponding increase in the
carrying amount of the related long-lived asset. SFAS No. 143 is effective for
financial statements issued for fiscal years beginning after June 30, 2002
using a cumulative effect approach to recognize transition amounts for asset
retirement obligations, asset retirement costs and accumulated depreciation,
depletion and amortization. The Company will adopt SFAS No. 143 effective
January 1, 2003. The Company expects the adoption of this statement to result
in the recognition of a liability for asset retirement obligations of
approximately $22-$26 million, approximately $2-$4 million of which will be
included in current liabilities and approximately $20-$22
56
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
million of which will be included in non-current liabilities, an increase in
property and equipment of approximately $18-$22 million in the Company's
balance sheets, and a cumulative accounting adjustment of approximately $2-$4
million recorded as expense, net of taxes of $1-$2 million, as the effect of
the change in accounting principle.
SFAS No. 148, "Accounting for Stock-Based Compensation--Transition and
Disclosure," amends SFAS No. 123 to provide alternative methods of transition
for an entity that voluntarily changes to the fair value based method of
accounting for stock-based employee compensation and to require prominent
disclosure about the effects on reported net income of an entity's accounting
policy decisions with respect to stock-based employee compensation. SFAS No.
148 amends APB Opinion No. 28, "Interim Financial Reporting," to require
disclosure about those effects in interim financial information. SFAS No. 148
is effective for financial statements for fiscal years ending after December
15, 2002.
3. Accounts Receivable, Other Current Assets and Accrued Liabilities and Other:
Supplemental disclosures related to accounts receivable, other current
assets and accrued liabilities and other are as follows (in thousands):
As of December 31,
----------------
2002 2001
------- -------
Accounts receivable:
Natural gas and oil sales................................ $24,434 $10,679
Hedging receivable....................................... 2,093 2,093
Joint interest billings.................................. 10,430 8,735
Insurance claims receivable.............................. 3,127 4,593
Other receivables........................................ 720 1,088
Allowance for doubtful accounts.......................... (3,232) (3,059)
------- -------
Total accounts receivable............................ $37,572 $24,129
======= =======
Other current assets:
Deferred tax assets associated with hedging activities... $ 7,170 $ 115
Drilling advances........................................ 2,060 710
Prepaid insurance........................................ 648 1,664
Prepaid debt financing costs............................. 301 328
Other.................................................... 1,259 847
------- -------
Total other current assets........................... $11,438 $ 3,664
======= =======
Accrued liabilities and other:
Accrued liabilities...................................... $38,542 $43,510
Deferred income taxes associated with hedging activities. -- 7,208
------- -------
Total accrued liabilities and other.................. $38,542 $50,718
======= =======
4. Debt:
In October 1999, the Company, Bank of Montreal and Credit Suisse First
Boston entered into the $25.0 million Amended and Restated 364-Day Credit
Agreement ("First Amended Credit Agreement"). The First Amended Credit
Agreement was amended on July 20, 2000. The Second Amended and Restated Credit
Agreement provided a $75.0 million credit facility ("Second Amended Credit
Agreement") with an initial borrowing base of $40.0 million and an original
term of 364 days. The borrowing base as of December 31, 2000
57
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
was $30.0 million. The Second Amended Credit Agreement was renewed for an
additional 364-day term on July 18, 2001 before being terminated on December
28, 2001.
On December 28, 2001, the Company replaced its $75.0 million credit facility
with an unsecured $200.0 million credit facility ("Credit Facility") with a
group of seven banks. The borrowing base of the three-year Credit Facility is
re-determined on or about April 30 and September 30 each year. The banks and
Spinnaker also have the option to request one additional re-determination each
year. The banks determine the borrowing base at their sole discretion and in
their usual and customary manner. The amount of the borrowing base is a
function of the banks' view of the Company's reserve profile as well as
commodity prices. The current borrowing base is $100.0 million. The Company has
the option to elect to use a base interest rate as described below or the LIBOR
rate plus, for each such rate, a spread based on the percentage of the
borrowing base used at that time. The base interest rate under the Credit
Facility is a fluctuating rate of interest equal to the higher of either
Toronto-Dominion Bank's base rate for dollar advances made in the United States
or the Federal Funds Rate plus 0.5% per annum. The commitment fee rate ranges
from 0.3% to 0.5%, depending on the borrowing base usage.
The Credit Facility contains various 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 arising under hedging agreements, indebtedness incurred in
the ordinary course of business not to exceed $1.0 million, unsecured
vendor indebtedness of the Company related to purchases of 2-D and 3-D
seismic data made in the ordinary course of business in an amount not to
exceed $25.0 million, other unsecured indebtedness in an amount not to
exceed $10.0 million in the aggregate;
. may not incur any liens upon properties or assets other than permitted
liens securing indebtedness of up to $1.0 million, liens on the 2-D and
3-D seismic data securing the indebtedness permitted to acquire such
data, pledges or deposits to secure hedging agreements up to $15.0
million, liens on property required as a condition to enter into a
synthetic lease transaction in the ordinary course of business and other
liens in the ordinary course of business;
. may not dispose of any assets or properties except obsolete equipment,
inventory sold in the ordinary course of business, reserves in non-proved
categories, a second license in certain seismic data, or interests in
natural gas and oil properties included in the borrowing base in an
aggregate amount not to exceed $25.0 million in any fiscal year;
. may not make or pay any dividend, distribution or payment in respect of
capital stock nor purchase, redeem, acquire, retire or permit any
reduction or retirement of capital stock in excess of $10.0 million in
any fiscal year;
. must maintain the ratio of consolidated current assets to consolidated
current liabilities as of the end of each fiscal quarter so that it is
not less than 1.00 to 1.00. For purposes of the calculation, availability
under the Credit Facility is included as current assets, any payments of
principal owing under the Credit Facility required to be repaid within
one year from the time of the calculation are excluded from current
liabilities and mark-to-market hedging exposure is excluded from both
current assets and current liabilities;
. must maintain a tangible net worth so that it is not less than the sum of
80% of the tangible net worth as of September 30, 2001, plus 50% of the
adjusted consolidated net income for each fiscal quarter since the
closing of the Credit Facility, plus 75% of the proceeds from the sale of
any security, including without limitation, common equity, preferred
equity or other equity interests or equity securities including warrants,
options and the like issued after the closing of the Credit Facility; and
58
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
. may not enter into any hedging agreement unless the percent of volumes to
be hedged to estimated production volumes for such month from total
internally-projected proved reserves does not exceed: 100% for the period
one to three months from and after the hedging agreement transaction
date, 66 2/3% for the period four to 18 months from and after the hedging
agreement transaction date and 33 1/3% for the period 19 to 36 months
from and after the hedging agreement transaction date. Additionally, at
no time will any hedging agreement of any nature have a counterparty with
a minimum long-term senior unsecured indebtedness rating less than "BBB+"
by Standard & Poor's or "Baa1" by Moody's Investors Services, Inc. at the
time that such counterparty entered into the relevant transaction under
such hedging agreement and at no time will exposure to any single
counterparty exceed 25% of the estimated twelve-month production volumes
from total proved reserves.
At December 31, 2002, the Company was in compliance with the covenants and
restrictive provisions and had no outstanding borrowings under the Credit
Facility.
5. Equity:
Prior to Spinnaker's initial public offering in September 1999, the Company
sold Preferred Stock to various investors. On September 28, 1999, the Company
priced its initial public offering of 8,000,000 shares of Common Stock and
commenced trading the following day. In connection with the initial public
offering, the Company converted all outstanding Preferred Stock into 6,061,840
shares of Common Stock, and certain shareholders reinvested preferred dividends
payable of $16.3 million into 1,200,248 shares of Common Stock. On August 16,
2000, the Company completed a public offering of 5,600,000 shares of Common
Stock at $26.25 per share. After payment of underwriting discounts and
commissions, the Company received net proceeds of $138.9 million. On December
20, 2000, PGS sold its 5,388,743 shares of Common Stock at $29.25 per share.
Spinnaker received no proceeds from this sale. On April 3, 2002, the Company
completed a public offering of 5,750,000 shares of Common Stock at $41.50 per
share, including the over-allotment option consisting of 750,000 shares. After
payment of underwriting discounts and commissions, the Company received net
proceeds of $227.9 million.
Spinnaker has an effective shelf registration statement relating to the
potential public offer and sale by the Company or certain of its affiliates of
up to $500.0 million of any combination of debt securities, preferred stock,
common stock, warrants, stock purchase contracts and trust preferred securities
from time to time or when financing needs arise. The registration statement
does not provide assurance that the Company will or could sell any such
securities.
6. Stock Plans:
At December 31, 2002, officers, directors and employees had been granted
options to purchase Common Stock under stock plans adopted in 1998, 1999, 2000
and 2001. The exercise price of each option equals the market price of
Spinnaker's Common Stock on the date of grant. Stock option grants generally
vest ratably over four years, with 20% vesting on the date of grant and 20%
vesting in each of the succeeding four years, and expire after ten years. In
the event of certain significant changes in control of the Company, all options
then outstanding generally will become immediately exercisable in full.
In January 1998, the stockholders approved the 1998 Stock Option Plan ("1998
Plan"). The 1998 Plan was amended and restated in September 1999 and authorized
the issuance of 2,673,242 shares of Common Stock. In September 1999, the
stockholders approved the 1999 Stock Incentive Plan ("1999 Plan"). The number
of shares of Common Stock that may be issued under the 1999 Plan may not exceed
1,300,000 shares. The maximum number of shares of Common Stock that may be
subject to awards granted under the 1999 Plan to any one individual during any
calendar year may not exceed 300,000 shares. In connection with the 1999 Plan,
the
59
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
stockholders approved the Adjunct Stock Option Plan ("Adjunct Plan"). The
number of shares of Common Stock that may be issued under the Adjunct Plan may
not exceed 21,920 shares. In November 2000, the board of directors adopted the
2000 Stock Option Plan ("2000 Plan"). Stockholder approval was not required for
the 2000 Plan. The number of shares of Common Stock that may be issued under
the 2000 Plan may not exceed 500,000 shares. In May 2001, the stockholders
approved the 2001 Stock Incentive Plan ("2001 Plan"). The number of shares of
Common Stock that may be issued under the 2001 Plan may not exceed 1,500,000
shares. The maximum number of shares of Common Stock that may be subject to
awards granted under the 2001 Plan to any one individual during any calendar
year may not exceed 300,000 shares.
Presented below is a summary of stock option activity.
2002 2001 2000
-------------------- -------------------- --------------------
Weighted Weighted Weighted
Shares Average Shares Average Shares Average
Under Exercise Under Exercise Under Exercise
Option Price Option Price Option Price
---------- -------- ---------- -------- ---------- --------
Outstanding, beginning of year........ 4,062,556 $22.08 3,718,886 $13.80 3,382,974 $10.56
Granted............................ 450,000 35.82 1,242,800 37.90 802,470 23.45
Exercised.......................... (119,433) 8.01 (810,991) 8.82 (466,558) 6.88
Forfeited.......................... (6,590) 27.64 (88,139) 17.57 -- --
---------- ---------- ----------
Outstanding, end of year.............. 4,386,533 $23.87 4,062,556 $22.08 3,718,886 $13.80
========== ========== ==========
Exercisable, end of year.............. 2,845,250 $19.30 2,273,548 $16.16 2,364,270 $11.38
========== ========== ==========
Available for grant, end of year...... 204,535 648,545 303,206
========== ========== ==========
Weighted average fair value of options
granted during the year............. $ 26.83 $ 23.76 $ 15.17
========== ========== ==========
The Company transferred treasury shares to certain employees in connection
with their exercises of 2,944, 2,128 and 4,080 options in 2002, 2001 and 2000,
respectively. Options to purchase 1,240 shares of Common Stock were forfeited
during 2002 and 1999 and are not currently available for future grants due to
exercise price restrictions under the 1998 Plan.
At December 31, 2002, the following options were outstanding and exercisable
and had the indicated weighted average remaining contractual lives:
Outstanding Exercisable
------------------- -------------------
Weighted Weighted Weighted
Average Average Average
Exercise Exercise Remaining
Number of Price Per Number of Price Per Contractual
Range of Exercise Prices Per Share Options Share Options Share Life (Years)
---------------------------------- --------- --------- --------- --------- ------------
$2.50-$5.00 541,004 $ 4.94 541,004 $ 4.94 4.2
$14.50-$16.13 1,749,699 15.36 1,462,164 15.36 5.7
$21.58-$26.88 322,700 26.05 172,200 26.41 8.2
$31.33-$36.81 173,220 32.74 60,932 32.23 8.8
$37.35-$38.63 1,407,210 37.84 529,530 37.86 8.4
$39.35-$42.06 192,700 40.50 79,420 40.80 8.6
--------- ---------
4,386,533 2,845,250
========= =========
60
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
7. Earnings Per Share:
Basic and diluted net income per common share is computed based on the
following information (in thousands, except per share amounts):
Year Ended December 31,
-----------------------
2002 2001 2000
------- ------- -------
Numerator:
Net income available to common stockholders.................... $31,579 $66,226 $38,566
======= ======= =======
Denominator:
Basic weighted average number of shares........................ 31,695 27,079 22,679
======= ======= =======
Dilutive securities:
Stock options.............................................. 958 1,281 1,332
------- ------- -------
Diluted adjusted weighted average number of shares and assumed
conversions.................................................. 32,653 28,360 24,011
======= ======= =======
Net income per common share:
Basic.......................................................... $ 1.00 $ 2.45 $ 1.70
======= ======= =======
Diluted........................................................ $ 0.97 $ 2.34 $ 1.61
======= ======= =======
For the years ended December 31, 2002, 2001 and 2000, 1,680,640, 113,200 and
399,920 stock options that could potentially dilute earnings per share are
excluded from the calculations as they were anti-dilutive.
8. Major Customers:
The Company had natural gas and oil sales to four customers accounting for
approximately 52%, 13%, 11% and 11%, respectively, of total natural gas and oil
revenues, excluding the effects of hedging activities, for the year ended
December 31, 2002. The Company had natural gas and oil sales to four customers
accounting for approximately 32%, 23%, 21% and 17%, respectively, of total
natural gas and oil revenues, excluding the effects of hedging activities, for
the year ended December 31, 2001. The Company had natural gas and oil sales to
three customers accounting for approximately 61%, 11% and 11%, respectively, of
total natural gas and oil revenues, excluding the effects of hedging
activities, for the year ended December 31, 2000. One of the customers in 2001
and 2000 was Enron North America Corp. Spinnaker no longer sells its natural
gas and oil production to this customer.
9. Related-Party Transactions:
The Company incurred charges of approximately $16.1 million and $16.3
million in 2002 and 2001, respectively, from affiliates of Baker Hughes
Incorporated, an oilfield services company of which Mr. Michael E. Wiley, a
director of Spinnaker since March 2001, serves as Chairman of the Board, Chief
Executive Officer and President. The Company incurred charges of approximately
$0.1 million, $0.1 million and $0.5 million in 2002, 2001 and 2000,
respectively, from Cooper Cameron Corporation, an oilfield services company of
which Mr. Sheldon R. Erikson, a director of Spinnaker, serves as Chairman of
the Board, Chief Executive Officer and President.
61
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
10. Income Taxes:
The significant items giving rise to the deferred income tax assets and
liabilities are as follows (in thousands):
As of December 31,
-----------------
2002 2001
-------- --------
Deferred income tax liabilities:
Basis differences in natural gas and oil properties. $156,588 $104,141
Hedging activities.................................. -- 7,812
-------- --------
Total deferred income tax liabilities........... 156,588 111,953
Deferred income tax assets:
Net operating losses................................ $ 92,650 $ 58,400
Hedging activities.................................. 7,170 --
Other............................................... 2,112 622
-------- --------
Total deferred income tax assets................ 101,932 59,022
-------- --------
Net deferred income tax liabilities.................... $ 54,656 $ 52,931
======== ========
Tax benefits of $1.4 million and $9.0 million associated with the exercise
of non-qualified stock options during the years ended December 31, 2002 and
2001 are reflected as a component of equity. The net deferred income tax
liabilities include a deferred tax asset of $7.2 million and a deferred tax
liability of $7.8 million related to the tax effect of the fair market value of
derivatives at December 31, 2002 and 2001, respectively, as required by SFAS
No. 133, as amended.
As of December 31, 2002, the Company had approximately $257.4 million of net
operating loss carryforwards ("NOLs") that will begin expiring in 2018. For
federal income tax purposes, certain limitations are imposed on an entity's
ability to utilize its NOLs in future periods if a change of control, as
defined for federal income tax purposes, has occurred. In general terms, the
limitation on utilization of NOLs and other tax attributes during any one year
is determined by the value of an entity at the date of the change of control
multiplied by the then-existing long-term, tax-exempt interest rate. The
Internal Revenue Service has not yet addressed the manner of determining an
entity's value. The Company has determined that, for federal income tax
purposes, a change of control occurred during 2000. However, the Company does
not believe such limitations will significantly impact its ability to utilize
the NOLs.
Significant components of the provision for income taxes are as follows (in
thousands):
Year Ended December 31,
------------------------
2002 2001 2000
------- ------- -------
Current............... $ (300) $ 275 $ 25
Deferred.............. 18,063 36,977 20,833
------- ------- -------
Income tax expense. $17,763 $37,252 $20,858
======= ======= =======
62
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The differences between income tax expense and the amount that would be
determined by applying the statutory federal income tax rate of 35% to the
income before income taxes are as follows (in thousands):
Year Ended December 31,
-----------------------
2002 2001 2000
------- ------- -------
Federal income tax expense at statutory rates $17,270 $36,217 $20,798
Non-deductible expenses and other............ 493 1,035 659
Valuation allowance.......................... -- -- (599)
------- ------- -------
Income tax expense........................ $17,763 $37,252 $20,858
======= ======= =======
During 2000, the Company expected that it would realize all of its deferred
tax assets and therefore decreased the valuation allowance to $0.
11. Commitments and Contingencies:
The Company is, from time to time, party to certain legal actions and claims
arising in the ordinary course of business. While the outcome of these events
cannot be predicted with certainty, management does not expect these matters to
have a materially adverse effect on the financial position, results of
operations or cash flows of the Company.
Employment Contracts
The Company has employment contracts with certain of its executive officers.
These contracts provide for annual base salaries, bonus compensation, various
benefits and the continuation of salary and benefits for the respective terms
of the agreements in the event of termination of employment for various
reasons, and whether by the Company or the employee. These agreements are
subject to automatic annual extensions unless terminated.
Employee 401(k) Retirement Plan
In July 1998, the Company instituted a 401(k) retirement savings plan
("401(k) Plan") for its employees. The 401(k) Plan provides that all qualified
employees may defer the maximum income allowed under current tax law. The
401(k) Plan covers all employees at least 21 years of age.
Effective January 1, 2000, the Company began matching employee contributions
to the 401(k) Plan. The Company matches 100% of each participant's
contributions up to 6% of the participant's annual base salary. In connection
with the employer match, the Company issued 9,062 shares of Common Stock valued
at $0.3 million in 2002, 5,456 shares of Common Stock valued at $0.2 million in
2001 and 5,923 shares of Common Stock valued at $0.1 million in 2000.
Leases
The Company leases administrative offices under a non-cancelable operating
lease expiring in 2007. The lease agreement requires the Company pay for
utilities, maintenance and other operational expenses of the building.
Additionally, the lease contains escalation clauses. The Company also leases
office equipment and oil and gas equipment under non-cancelable operating
leases. Rental expense was $1.6 million, $0.7 million and $0.5 million in 2002,
2001 and 2000, respectively. Minimum future obligations under non-cancelable
operating
63
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
leases at December 31, 2002 for the following five years are $1.7 million, $1.3
million, $1.3 million, $1.2 million and $0.5 million, respectively.
Summary of Contractual Obligations
The Company had no long-term debt, capital lease or purchase obligations or
other contractual long-term liabilities as of December 31, 2002. The Company
has incurred obligations in the ordinary course of business under purchase and
service agreements that are not included in the table below, including
obligations of approximately $35.4 million and $6.7 million in 2003 and 2004,
respectively, for construction of the Green Canyon Blocks 338/339 ("Front
Runner") spar production facility. Contractual obligations as of December 31,
2002 are as follows:
Payments Due by Period
-------------------------------------
Less than 1-3 4-5 After
Total 1 Year Years Years 5 Years
------ --------- ------ ----- -------
Operating leases............. $6,032 $1,708 $3,800 $524 $--
Other contractual obligations -- -- -- -- --
------ ------ ------ ---- ---
Total..................... $6,032 $1,708 $3,800 $524 $--
====== ====== ====== ==== ===
12. Commodity Price Risk Management Activities:
The Company enters into New York Mercantile Exchange ("NYMEX") related swap
contracts and collar arrangements from time to time. The Company's swap
contracts and collar arrangements will settle based on the reported settlement
price on the NYMEX for the last trading day of each month for natural gas.
In a swap transaction, the counterparty is required to make a payment to the
Company for the difference between the fixed price and the settlement price if
the settlement price is below the fixed price. The Company is required to make
a payment to the counterparty for the difference between the fixed price and
the settlement price if the settlement price is above the fixed price. As of
December 31, 2002, Spinnaker's commodity price risk management positions in
fixed price natural gas swap contracts and related fair value were as follows:
Average Weighted
Daily Average
Volume Price Fair Value
Period (MMBtus) (Per MMBtu) (in thousands)
------ -------- ----------- --------------
First Quarter 2003. 60,000 $3.71 $ (5,979)
Second Quarter 2003 53,297 3.55 (4,411)
Third Quarter 2003. 50,000 3.55 (4,068)
Fourth Quarter 2003 50,000 3.63 (4,340)
--------
Year 2003.......... 53,288 $3.61 $(18,798)
========
64
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
In a collar arrangement, the counterparty is required to make a payment to
the Company for the difference between the fixed floor price and the settlement
price if the settlement price is below the fixed floor price. The Company is
required to make a payment to the counterparty for the difference between the
fixed ceiling price and the settlement price if the settlement price is above
the fixed ceiling price. Neither party is required to make a payment if the
settlement price falls between the fixed floor price and the fixed ceiling
price. As of December 31, 2002, Spinnaker's commodity price risk management
positions in natural gas collar arrangements and related fair value were as
follows:
Average Weighted Weighted
Daily Average Average
Volume Floor Price Ceiling Price Fair Value
Period (MMBtus) (Per MMBtu) (Per MMBtu) (in thousands)
------ -------- ----------- ------------- --------------
First Quarter 2003. 15,000 $3.25 $5.21 $ (228)
Second Quarter 2003 15,000 3.25 5.21 (262)
Third Quarter 2003. 15,000 3.25 5.21 (287)
Fourth Quarter 2003 15,000 3.25 5.21 (342)
-------
Year 2003.......... 15,000 $3.25 $5.21 $(1,119)
=======
The Company reported a net liability of $19.9 million and a net asset of
$22.3 million related to its derivative contracts at December 31, 2002 and
2001, respectively. Amounts related to hedging activities as of December 31,
2002 and 2001 were as follows (in thousands):
As of December 31,
-----------------
2002 2001
-------- -------
Current assets:
Hedging asset............................................... $ -- $20,593
Deferred income tax asset related to hedging activities..... 7,170 --
Non-current assets:
Hedging asset............................................... $ -- $ 1,726
Current liabilities:
Hedging liability........................................... $ 19,917 $ --
Deferred income tax liability related to hedging activities. -- 7,208
Non-current liabilities:
Deferred income tax liability related to hedging activities. $ -- $ 604
Accumulated other comprehensive income (loss):
Accumulated other comprehensive income (loss)............... $(19,917) $22,319
Income taxes................................................ 7,170 (7,812)
-------- -------
Accumulated other comprehensive income (loss)........... $(12,747) $14,507
The Company recognized a net hedging gain of $4.7 million and net hedging
losses of $9.6 million and $18.7 million in revenues in 2002, 2001 and 2000,
respectively. There was no ineffective component of the derivatives recognized
in earnings in 2002 and 2001. Based on future natural gas prices as of December
31, 2002, the Company would reclassify a net loss of $12.7 million from
accumulated other comprehensive income (loss) to earnings within the next
twelve months. The amounts ultimately reclassified into earnings will vary due
to changes in the fair value of the open derivative contracts prior to
settlement.
65
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
13. Quarterly Financial Data (Unaudited):
Quarterly operating results for the years ended December 31, 2002 and 2001
are summarized as follows (in thousands, except per share amounts):
(Unaudited)
Quarter Ended
---------------------------------------------
March 31, June 30, September 30, December 31,
--------- -------- ------------- ------------
2002:
Revenues.................... $32,600 $37,164 $51,558 $67,004
Income from operations...... 8,963 9,256 11,042 19,829
Net income.................. 5,576 6,222 7,146 12,635
Net income per common share:
Basic.................... $ 0.20 $ 0.19 $ 0.22 $ 0.38
Diluted.................. $ 0.20 $ 0.18 $ 0.21 $ 0.37
2001:
Revenues.................... $67,453 $59,500 $44,818 $38,605
Income from operations...... 42,792 32,886 16,150 8,457
Net income.................. 28,148 21,781 10,803 5,494
Net income per common share:
Basic.................... $ 1.05 $ 0.80 $ 0.40 $ 0.20
Diluted.................. $ 1.00 $ 0.77 $ 0.38 $ 0.19
14. Supplementary Financial Information on Oil and Gas Exploration, Development
and Production Activities (Unaudited):
Capitalized Costs Related to Oil and Gas Producing Activities
(In thousands)
As of December 31,
---------------------
2002 2001
---------- ---------
Capitalized costs:
Proved properties................................... $ 879,840 $ 575,806
Unproved properties not being amortized............. 141,326 102,881
---------- ---------
Total........................................... 1,021,166 678,687
Accumulated depreciation, depletion and amortization(1) (267,744) (158,746)
---------- ---------
Net capitalized costs........................... $ 753,422 $ 519,941
========== =========
--------
(1) Depreciation, depletion and amortization per Mcfe was $2.12, $1.60 and
$1.57 in 2002, 2001 and 2000, respectively.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development
Activities
(In thousands)
Year Ended December 31,
--------------------------
2002 2001 2000
-------- -------- --------
Acquisition costs:
Unproved..................... $ 39,789 $ 34,524 $ 21,421
Proved....................... -- -- --
Exploration costs............... 163,322 187,720 121,451
Development costs............... 139,368 80,276 51,144
-------- -------- --------
Total costs incurred..... $342,479 $302,520 $194,016
======== ======== ========
66
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Acquisition costs include costs incurred to purchase, lease or otherwise
acquire property. Exploration costs include the costs of drilling exploratory
wells, including those in progress, geological and geophysical service costs
and depreciation of support equipment used in exploration activities.
Development costs include the costs of drilling development wells and costs of
completions, platforms, facilities and pipelines.
Costs being excluded from amortization consist of the following (in
thousands):
Year Ended December 31,
-------------------------------------------
1999 and
Total 2002 2001 2000 Prior
-------- ------- ------- ------- --------
Unproved property costs $ 89,837 $28,635 $22,362 $ 4,910 $33,930
Exploration costs...... 49,751 11,306 (5,880) 37,559 6,766
Development costs...... 1,738 (1,496) 3,234 -- --
-------- ------- ------- ------- -------
Total............... $141,326 $38,445 $19,716 $42,469 $40,696
======== ======= ======= ======= =======
Results of Operations for Oil and Gas Producing Activities
(In thousands)
Year Ended December 31,
--------------------------
2002 2001 2000
-------- -------- --------
Revenues................................ $188,326 $210,376 $121,383
Operating expenses(1)................... 18,212 12,132 9,009
Depreciation, depletion and amortization 108,998 85,059 47,451
Charges related to Enron bankruptcy..... 128 3,059 --
Income tax expense(2)................... 21,956 39,645 23,372
-------- -------- --------
Results of operations................ $ 39,032 $ 70,481 $ 41,551
======== ======== ========
--------
(1) Operating expenses represent costs incurred to operate and maintain wells
and related equipment and facilities. These costs include, among other
things, workover expenses, labor, materials, supplies, property taxes,
insurance, severance taxes and transportation expenses.
(2) Income tax expense is calculated by applying the statutory tax rate to
operating profit, then adjusting for any applicable permanent tax
differences or tax credits and allowances.
Proved natural gas and oil reserve quantities and the related discounted
future net cash flows before income taxes are based on estimates prepared by
Ryder Scott Company, L.P., independent petroleum consultants. Such estimates
have been prepared in accordance with guidelines established by the Commission.
Proved reserves are estimated quantities of natural gas and oil 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 developed reserves are proved reserves that can
reasonably be expected to be recovered through existing wells with existing
equipment and operating methods.
67
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Reserve Quantity Information
Natural
Natural Oil and Gas
Gas Condensate Equivalents
(MMcf) (MBbls) (MMcfe)
------- ---------- -----------
Proved reserves as of December 31, 1999........ 90,030 2,412 104,501
Extensions, discoveries and other additions. 97,665 1,027 103,829
Revisions of previous estimates............. 5,248 (116) 4,552
Production.................................. (28,845) (225) (30,194)
------- ------ -------
Proved reserves as of December 31, 2000........ 164,098 3,098 182,688
Extensions, discoveries and other additions. 74,531 18,921 188,057
Revisions of previous estimates............. (11,414) 2,829 5,556
Production.................................. (51,234) (310) (53,094)
------- ------ -------
Proved reserves as of December 31, 2001(1)..... 175,981 24,538 323,207
Extensions, discoveries and other additions. 24,666 7,678 70,733
Revisions of previous estimates(2).......... (11,936) (1,168) (18,944)
Production.................................. (45,180) (1,040) (51,419)
------- ------ -------
Proved reserves as of December 31, 2002(1)..... 143,531 30,008 323,577
======= ====== =======
Proved developed reserves:
December 31, 2002(1)........................ 84,139 2,219 97,456
======= ====== =======
December 31, 2001(1)........................ 82,221 748 86,711
======= ====== =======
December 31, 2000........................... 112,315 1,042 118,568
======= ====== =======
December 31, 1999........................... 50,756 384 53,062
======= ====== =======
--------
(1) Spinnaker has a 25% non-operator working interest in a significant
deepwater oil discovery at Front Runner. This significant oil discovery
changed Spinnaker's reserve profile. Proved oil and condensate reserves
were 56% and 46% of total proved reserves at December 31, 2002 and 2001,
respectively, compared to 10% at December 31, 2000. Of the Company's total
proved reserves as of December 31, 2002, 70% were proved undeveloped
reserves. Front Runner represented more than 60% of total proved
undeveloped reserves.
(2) Front Runner area reserves are subject to royalty relief on the first 87.5
million equivalent barrels of oil produced. As new reserves are added in
the Front Runner area, changes in future production assumptions result in a
reallocation of reserves subject to royalty relief. These reallocations
resulted in downward revisions to previous estimates of approximately 671
MMcf and 1,002 MBbls, or natural gas equivalents of 6,681 MMcfe. No
downward revision on any individual property exceeded 1% of proved reserves
as of December 31, 2001.
The standardized measure of discounted future net cash flows from production
of proved reserves was developed as follows:
. Estimates are made of quantities of proved reserves and the future
periods during which they are expected to be produced based on year-end
economic conditions.
. The estimated future gross revenues of proved reserves are priced on the
basis of year-end market prices.
. The future gross revenue streams are reduced by estimated future costs to
develop and to produce the proved reserves, as well as certain
abandonment costs based on year-end cost estimates and the estimated
effect of future income taxes.
68
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the
estimated permanent differences applicable to future natural gas and oil
producing activities and tax carryforwards.
The standardized measure of discounted future net cash flows is not intended
to present the fair market value of the Company's natural gas and oil reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes
in prices and costs, an allowance for return on investment and the risks
inherent in reserve estimates. Given the volatility of natural gas and oil
prices, it is reasonably possible that the Company's estimate of discounted
future net cash flows from proved natural gas and oil reserves will change in
the near term. If natural gas and oil prices decline, even if for only a short
period of time, or if the Company has significant downward revisions to its
estimated proved reserves, it is possible that write-downs of natural gas and
oil properties could occur in the future.
Standardized Measure of Discounted Future Net Cash Flows
(In thousands)
Year Ended December 31,
---------------------------------
2002 2001 2000
---------- --------- ----------
Future cash inflows(1).................................. $1,613,724 $ 944,861 $1,730,754
Future operating expenses............................... (185,782) (164,105) (60,259)
Future development costs................................ (184,441) (191,711) (68,929)
---------- --------- ----------
Future net cash flows before income taxes............... 1,243,501 589,045 1,601,566
Future income taxes..................................... (259,436) (120,489) (516,488)
---------- --------- ----------
Future net cash flows................................... 984,065 468,556 1,085,078
10% annual discount..................................... (303,267) (139,000) (185,941)
---------- --------- ----------
Standardized measure of discounted future net cash flows $ 680,798 $ 329,556 $ 899,137
========== ========= ==========
--------
(1) Prices for natural gas and oil used to calculate future cash inflows were
$4.91, $2.71 and $9.99 per Mcf of natural gas and $30.50, $19.23 and $30.41
per barrel of oil as of December 31, 2002, 2001 and 2000, respectively.
Principal Sources of Change in the Standardized Measure of Discounted Future
Net Cash Flows
(In thousands)
Year Ended December 31,
-------------------------------
2002 2001 2000
--------- --------- ---------
Standardized measure, beginning of year............................. $ 329,556 $ 899,137 $ 151,564
Extensions and discoveries, net of related costs................. 215,800 198,709 719,694
Sales of natural gas and oil produced, net of production costs... (165,450) (207,824) (131,030)
Net changes in prices and production costs....................... 403,728 (958,755) 486,496
Change in future development costs............................... (26,795) (18,959) (3,501)
Development costs incurred during the period that reduced future
development costs.............................................. 56,831 47,463 37,851
Revisions of quantity estimates.................................. (57,991) 6,092 34,749
Accretion of discount............................................ (640) 132,067 15,156
Net change in income taxes....................................... (80,892) 335,952 (421,535)
Change in production rates and other............................. 6,651 (104,326) 9,693
--------- --------- ---------
Standardized measure, end of year................................... $ 680,798 $ 329,556 $ 899,137
========= ========= =========
69
INDEPENDENT AUDITORS' REPORT ON CONSOLIDATED
FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and Stockholders of
Spinnaker Exploration Company:
Under date of February 7, 2003, we reported on the consolidated balance
sheets of Spinnaker Exploration Company and subsidiaries, as of December 31,
2002 and 2001, and the related consolidated statements of operations, equity
and cash flows for each of the years in the three-year period ended December
31, 2002. In connection with our audits of the aforementioned consolidated
financial statements, we also audited the related consolidated financial
statement schedule. This consolidated financial statement schedule is the
responsibility of the Company's management. Our responsibility is to express an
opinion on the consolidated financial statement schedule based on our audits.
In our opinion, the consolidated financial statement schedule, when
considered in relation to the basic consolidated financial statements taken as
a whole, presents fairly, in all material respects, the information set forth
therein.
KPMG LLP
Houston, Texas
February 7, 2003
70
Schedule II
SPINNAKER EXPLORATION COMPANY
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
For the Years Ended December 31, 2002, 2001 and 2000
(In thousands)
Balance at Charged to Balance
Beginning Costs Deductions at End
of Year and Expenses and Other of Year
---------- ------------ ---------- -------
Year ended December 31, 2002:
Allowance for doubtful accounts. $3,059 $ 128 $45 $3,232
Year ended December 31, 2001:
Allowance for doubtful accounts. $ -- $3,059 $-- $3,059
Year ended December 31, 2000:
Allowance for doubtful accounts. $ -- $ -- $-- $ --
71
EXHIBIT INDEX
Exhibit
Number Description
------- -----------
3.1 --Certificate of Incorporation of Spinnaker, as amended (incorporated by reference to Exhibit 3.1 to
Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
3.2 --Restated Bylaws of Spinnaker (incorporated by reference to Exhibit 3.2 to Spinnaker's
Registration Statement on Form S-1 (Commission File No. 333-83093))
4.1 --Specimen Common Stock certificate (incorporated by reference to Exhibit 4.1 to Spinnaker's
Registration Statement on Form S-3 (Commission File No. 333-72238))
10.1 --Second Amended and Restated Data Contribution Agreement between Petroleum Geo-Services
ASA, Seismic Energy Holdings, Inc., Spinnaker Exploration Company, L.L.C. and Spinnaker
dated June 30, 1999 (incorporated by reference to Exhibit 10.1 to Spinnaker's Registration
Statement on Form S-1 (Commission File No. 333-83093))
10.2 --Amended and Restated 1998 Spinnaker Stock Option Plan (incorporated by reference to Exhibit
10.2 to Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
10.3 --Amended and Restated Stockholders Agreement by and among Spinnaker, Warburg, Pincus
Ventures, Petroleum Geo-Services, Roger L. Jarvis, James M. Alexander, William D. Hubbard,
Kelly M. Barnes and certain other stockholders of Spinnaker (including the Registration Rights
Agreement as Exhibit A to the Stockholders Agreement) (incorporated by reference to Exhibit
10.3 to Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
10.3.1 --First Amendment to the Amended and Restated Stockholders Agreement by and among Spinnaker,
Warburg, Pincus Ventures, Petroleum Geo-Services, Roger L. Jarvis, James M. Alexander,
William D. Hubbard, Kelly M. Barnes and certain other stockholders of Spinnaker (incorporated
by reference to Exhibit 10.3.1 to Spinnaker's Quarterly Report on Form 10-Q for the quarter ended
June 30, 2000)
10.5 --Credit Agreement for a $200 million credit facility dated as of December 28, 2001 (incorporated
by reference to Exhibit 10.5 to Spinnaker's Annual Report on Form 10-K for the year ended
December 31, 2001)
10.6 --Employment Agreement between Spinnaker and Roger L. Jarvis dated December 20, 1996, as
amended (incorporated by reference to Exhibit 10.6 to Spinnaker's Registration Statement on
Form S-1 (Commission File No. 333-83093))
10.7 --Employment Agreement between Spinnaker and William D. Hubbard dated February 24, 1997, as
amended (incorporated by reference to Exhibit 10.8 to Spinnaker's Registration Statement on
Form S-1 (Commission File No. 333-83093))
10.8 --Employment Agreement between Spinnaker and Kelly M. Barnes dated February 24, 1997, as
amended (incorporated by reference to Exhibit 10.9 to Spinnaker's Registration Statement on
Form S-1 (Commission File No. 333-83093))
10.9 --1999 Spinnaker Stock Incentive Plan (incorporated by reference to Exhibit 10.10 to Spinnaker's
Registration Statement on Form S-1 (Commission File No. 333-83093))
10.10 --1999 Spinnaker Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.11 to
Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
10.11 --Form of Indemnification Agreement (incorporated by reference to Exhibit 10.12 to Spinnaker's
Registration Statement on Form S-1 (Commission File No. 333-83093))
10.12 --Adjunct Stock Option Plan (incorporated by reference to Exhibit 4.3 to Spinnaker's Registration
Statement on Form S-8 (Commission File No. 333-36592))
10.13 --Spinnaker Exploration Company 2000 Stock Option Plan (incorporated by reference to
Exhibit 10.13 to Spinnaker's Annual Report on Form 10-K for the year ended December 31, 2000)
72
Exhibit
Number Description
------- -----------
10.14 --Spinnaker Exploration Company 2001 Stock Incentive Plan, as amended (incorporated by
reference to Exhibit 10.2 to Spinnaker's Registration Statement on Form S-8 (Commission File
No. 333-61888))
12.1* --Calculation of Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred
Dividends
21.1 --Subsidiaries of Spinnaker Exploration Company (incorporated by reference to Exhibit 21.1 to
Spinnaker's Registration Statement on Form S-1 (Commission File No. 333-83093))
23.1* --Consent of KPMG LLP
23.2* --Consent of Ryder Scott Company, L.P.
99.1* --Certification of Chief Executive Officer of Spinnaker Exploration Company pursuant to 18
U.S.C. Section 1350
99.2* --Certification of Chief Financial Officer of Spinnaker Exploration Company pursuant to 18
U.S.C. Section 1350
--------
* Filed herewith.
73