Item 1. Business
General
Spinnaker Exploration Company, a Delaware corporation, is an independent energy company engaged in the exploration, development and production of oil and gas 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. On December 20, 2000, PGS sold all of its shares of Spinnaker common stock, par value $0.01 per share (“Common Stock”). Spinnaker received no proceeds from this sale.
As of December 31, 2003, the Company had license rights to approximately 17,700 blocks of mostly contiguous 3-D seismic data in the Gulf of Mexico. This database covers an area of approximately 45 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, 2003, the Company had 294 leasehold interests located in federal and Texas state waters of the Gulf of Mexico covering approximately 1,419,000 gross and 819,000 net acres. Most of these leasehold interests were acquired through a competitive bid process at federal and state lease sales. Within its current inventory of leasehold interests, the Company has identified and captured approximately 140 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, 2003, the Company participated in drilling 149 wells in the Gulf of Mexico resulting in 90 discoveries. As of December 31, 2003, Ryder Scott Company, L.P. (“Ryder Scott”), the Company’s independent reserve engineers, estimated the Company’s net proved reserves at approximately 332.6 Bcfe. Spinnaker’s current capital expenditure budget for 2004 is approximately $250.0 million, including $135.0 million for exploration activities, $69.0 million for development activities, $42.0 million for leasehold acquisitions and geological and geophysical expenditures and $4.0 million for other property and equipment. The Company currently plans to drill approximately 20 wells on the shelf and 13 wells in the deep water in 2004. Exploration and development in deep water requires significant capital commitments. If the Company is successful in its shelf and deepwater exploration efforts in 2004, currently budgeted capital requirements in 2004 will increase.
Spinnaker has a 25% non-operator working interest in a significant deepwater oil discovery on Green Canyon Blocks 338/339/382 (“Front Runner”). The Company participated in drilling eight successful wells on these blocks. Of the Company’s total proved reserves as of December 31, 2003, 68% were proved undeveloped reserves. Front Runner represented approximately 70% of total proved undeveloped reserves. Spinnaker has incurred capital expenditures associated with Front Runner of $129.4 million through December 31, 2003 and expects to incur an aggregate of approximately $22.5 million in future development costs during 2004 and $34.6 million after 2004. First production is anticipated during the second half of 2004.
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 Commission’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. 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.
Spinnaker’s board of directors (“Board of Directors”) has adopted corporate governance guidelines, committee charters and a code of business conduct and ethics for directors, officers and employees. Each of these documents is available on the Company’s internet website at www.spinnakerexploration.com and available in print, free of charge, upon written request to Spinnaker Exploration Company, 1200 Smith Street, Suite 800, Houston, Texas 77002, Attention: Corporate Secretary.
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; and
• Sustain a balanced, diversified exploration effort while maintaining a low debt-to-capitalization ratio.
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 oil and gas; and
• 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 mostly 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. Spinnaker uses a probabilistic approach for prospect reserve assessment where reservoir parameters generate a reserve distribution, and the mean of this distribution is used to better represent the prospect-expected reserves. A geologic risk is assessed for each prospect accounting for risk of finding, in the minimum case, reserves, reservoir, trap, seal, source and migration of hydrocarbons. A commercial probability is established for each prospect to find the chance of commerciality. Prospects are then compared based on a risk/reward basis without inherited bias to optimize Spinnaker’s prospect inventory.
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 seven technical specialists with significant experience in database and systems management, seismic data processing, petrophysical analysis 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.
Sustain a balanced, diversified exploration effort while maintaining a low debt-to-capitalization ratio. 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 prospects and higher-risk, higher-potential prospects.
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.
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 oil and gas prices. Spinnaker’s emphasis on maintaining a lower debt-to-capitalization ratio than many of its peers has enhanced its ability and provided the flexibility 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 since acquired approximately 14,000 blocks of standard and enhanced 3-D seismic data from various seismic contractors, including approximately 4,000 blocks from PGS. The Company’s 3-D seismic database included a total of approximately 9,100 blocks of standard data and 8,600 blocks of enhanced data as of December 31, 2003.
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 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 oil and gas 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.
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 oil and gas 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 each month based on hedging commitments and projected strength of commodity prices. Revenues, profitability, cash flow and future growth depend substantially on prevailing oil and gas prices. The prices received by the Company for its natural gas and oil production fluctuate widely. For example, natural gas prices were volatile in 2003 with significant fluctuations between the high and low prices of $9.13 and $4.43, respectively. Oil prices have also increased as compared to prior years. Among the factors that can cause these fluctuations 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 oil and gas, the price of foreign imports and overall economic conditions.
Decreases in natural gas and oil prices could adversely affect the carrying value of proved reserves and revenues, profitability and cash flow. Although the Company did not experience any significant involuntary curtailment of natural gas or oil production in 2003, market, economic and regulatory factors may in the future materially affect its ability to sell natural gas or 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.
For the year ended December 31, 2003, sales to Cinergy Marketing & Trading, LP, Sequent Energy Management, L.P., Shell Trading (US) Company and Duke Energy Trade and Marketing LLC accounted for approximately 41%, 22%, 14% and 10%, respectively, of total natural gas and oil revenues, excluding the effects of hedging activities. 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 total 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 total natural gas and oil revenues, excluding the effects of hedging activities.
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. 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. For further information concerning Spinnaker’s hedging transactions, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”
Competition
The Company competes with major and independent oil and gas 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 oil and gas 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 oil and gas 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. 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 FERC continues to review and modify its regulations regarding the transportation of natural gas with the stated goal of fostering competition within all phases of the natural gas industry. 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.
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 oil and gas 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, 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 financial 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.
In 2000, the MMS issued a final rule that governs the calculation of royalties and the valuation of crude oil produced from federal leases. That rule amended 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. On August 20, 2003, the MMS issued a proposed rule that would change certain components of its valuation procedures for the calculation of royalties owed for crude oil sales. The proposed changes include changing the valuation basis for transactions not at arm’s-length from spot to NYMEX prices adjusted for locality and quality differentials, and clarifying the treatment of transactions under a joint operating agreement. Final comments on the proposed rule were due on November 10, 2003. The Company cannot predict whether the MMS will implement the proposed changes in a final rule. The Company believes that the proposed changes 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 may conduct operations in the state waters offshore Louisiana and Mississippi in the future. 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 oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states prorate production to the market demand for oil and gas.
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 changes to the Producer Price Index for Finished Goods, subject to certain conditions and limitations. 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.
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 oil and gas 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.
In addition, pursuant to the OCSLA, the MMS has issued regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Such regulations authorize the MMS to restrict the rate of drilling fluid discharge, prescribe alternative discharge methods and restrict the use of certain components if necessary to prevent unreasonable degradation to the marine environment. Additionally, specific design and operational standards 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 orders 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 oil and gas exploration and production activities.
In addition, legislation has been proposed in Congress from time to time that would reclassify some oil and gas 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 oil and gas 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 oil and gas 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 oil and gas 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 oil or gas, increasing the risks involved with these 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 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, 2003, the Company had 71 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.
GLOSSARY OF OIL AND GAS TERMS
The following is a description of the meanings of some of the oil and gas 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 oil or natural gas, 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 oil or natural gas 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 oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas 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 an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.
Lead. A specific geographic area which, based on supporting geological, geophysical or other data, is deemed to have potential for the discovery of commercial hydrocarbons.
MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.
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 oil and/or gas 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 oil or gas 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.
Item 2.
Item 2. Properties
Since inception, the Company has concentrated on the exploration for oil and natural gas exclusively in the Gulf of Mexico. As of December 31, 2003, proved reserves associated with Spinnaker’s discoveries were located on 36 different blocks, including one property in which the Company has only a royalty interest, with production established from 32 blocks. Spinnaker has operated 50 of its 90 discoveries since inception through December 31, 2003, and the Company’s working interests in these wells range from 12.5% to 100%. Seven blocks account for approximately 73% of the Company’s total proved reserves.
As of December 31, 2003, the Company had license rights to approximately 17,700 blocks of mostly contiguous 3-D seismic data in the Gulf of Mexico. This database covers an area of approximately 45 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, 2003, the Company had 294 leasehold interests located in federal and Texas state waters of the Gulf of Mexico covering approximately 1,419,000 gross and 819,000 net acres. Most of these leasehold interests were acquired through a competitive bid process at federal and state lease sales.
Oil and Gas Reserves
Spinnaker has a 25% non-operator working interest in its significant deepwater oil discovery at Front Runner. The Company participated in drilling eight successful wells on these blocks. Of the Company’s total proved reserves as of December 31, 2003, 68% were proved undeveloped reserves. Front Runner represented approximately 70% of total proved undeveloped reserves.
The following table presents estimated net proved oil and gas reserves and the related net present value of the reserves as of December 31, 2003 as prepared by Ryder Scott. 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 oil and gas 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, 2003 was determined by using prices of $6.29 per Mcf of natural gas and $30.34 per barrel of oil as of December 31, 2003.
(1) Excludes net pre-tax unrealized losses of $2.7 million for the effects of hedging activities using natural gas prices in effect as of December 31, 2003.
The process of estimating oil and gas reserves is complex. Ryder Scott prepares Spinnaker’s reserve estimates as of June 30 and December 31 each year. In order to assist in the preparation of these estimates, the Company must project production rates and timing of development expenditures. The Company also analyzes 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 oil and gas prices, drilling and operating
expenses, capital expenditures, taxes and the availability of funds. Therefore, estimates of oil and gas reserves are inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas 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 oil and gas prices and other factors, many of which are beyond the Company’s control. As of December 31, 2003, approximately 84% 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.
As of December 31, 2003, approximately 68% 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 from our proved reserves is the current market value of the Company’s estimated oil and gas reserves. In accordance with Commission requirements, 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 of future net cash flows estimate.
Volumes, Prices and Operating Expenses
The following table presents information regarding production volumes, average sales prices and average production costs associated with Spinnaker’s sales of natural gas and oil and condensate for the years indicated:
(1) The lease operating expense rate per Mcfe includes $0.06, $0.03 and $0.04 associated with workovers in 2003, 2002 and 2001, respectively.
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
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, completions, platforms, facilities, pipelines and the costs related to the retirement of these assets.
(1) Includes asset retirement costs of $30.0 million and gain on settlement of asset retirement obligations of $0.5 million for the year ended December 31, 2003.
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.
Since December 31, 2003 and through March 10, 2004, the Company has drilled one gross (0.6 net) nonproductive exploratory well. As of March 10, 2004, the Company was drilling three gross (1.4 net) exploratory wells and two gross (0.4 net) development wells.
Productive Wells
The following table sets forth the number of productive oil and gas wells in which Spinnaker owned an interest as of December 31, 2003:
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 oil and gas regardless of whether or not such acreage contains proved reserves. Spinnaker’s developed and undeveloped lease acreage as of December 31, 2003 was as follows (in thousands):
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 5.7 years, 4.1 years and 1.6 years for leases in federal waters offshore Louisiana, federal waters offshore Texas and Texas state waters, respectively.
Item 3.
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 litigation that it considers material based upon the facts and circumstances as they are known at this time.
Item 4.
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 2003.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
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.
On March 10, 2004, the closing sale price of Spinnaker’s Common Stock, as reported by the New York Stock Exchange, was $34.58 per share. On March 1, 2004, there were 37 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 revolving credit agreement dated as of December 19, 2003 (the “Revolver”) contains restrictions and limitations on paying cash dividends on its Common Stock. For a description of the covenants and restrictive provisions of the Revolver, 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 incorporated by reference under “Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters” and is incorporated by reference herein.
Item 6.
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.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
Our objective since inception has been to assemble a large 3-D seismic database and focus on exploration activities exclusively in the Gulf of Mexico because we believe this area represents one of the most attractive exploration regions in North America. We also believe a geographic focus provides an excellent opportunity to develop and maintain competitive advantages through our regional exploration and operating expertise. We try to maintain balance and diversity in our exploration approach by drilling both shallow water and deepwater prospects, ranging from lower-risk prospects to higher-risk, higher-potential prospects.
Spinnaker recognized 2003 net income of $36.6 million, or $1.08 per diluted share, compared to 2002 net income of $31.6 million, or $0.97 per diluted share. These financial results were impacted by a 51% higher average commodity price, 5% lower production and a $42.4 million increase in hedging losses in 2003. The lease operating expense rate per Mcfe increased 31%, primarily due to workover activities. The DD&A expense rate per Mcfe increased 21% in 2003, primarily due to our strategy of maintaining balance and diversity in our exploration activities, particularly in the deep shelf play where higher costs and risks accompany the potential for higher rewards. Spinnaker had $15.3 million in cash and cash equivalents and outstanding borrowings of $50.0 million as of December 31, 2003.
Spinnaker has experienced and expects to continue to experience substantial capital requirements. We have incurred capital costs of almost $1.0 billion in the past three years. Additionally, we have had negative working capital at the end of each of the last three years, including a deficit of $33.2 million as of December 31, 2003. Spinnaker has capital expenditure plans for 2004 totaling approximately $250.0 million. We believe that cash flows from operations, proceeds from available borrowings under the Revolver and Front Runner spar production facility financing opportunities will be sufficient to meet our capital requirements in the next twelve months.
Production of 49.0 Bcfe in 2003 was down 8% from 2001 production of 53.1 Bcfe. Proved oil and gas reserves of 332.6 Bcfe as of December 31, 2003 were up 8% from June 30, 2001 proved reserves of 307.2 Bcfe. Although we have been able to maintain a drilling success rate of approximately 60% since inception, our exploratory drilling successes on the shelf and deep shelf since the second half of 2001 have been smaller and had less impact on our operating results than those prior to that time, resulting in a negative impact on our subsequent production and reserve growth. Additionally, several of our discoveries since mid-2001 were in the deep water, and we do not expect to see the full impact on production from these projects until after 2004.
Production
Since inception, 90% of Spinnaker’s total production has been natural gas, including 83% in 2003. Considering oil and condensate production from deepwater projects in 2004 and 2005, we anticipate that this concentration in natural gas production will decrease to approximately three-fourths of total production in 2004 and approximately one-half of total production in 2005. As a result, Spinnaker’s revenues, profitability and cash flows will be less sensitive to natural gas prices and more sensitive to oil and condensate prices.
Generally, Spinnaker’s producing properties on the shelf have high initial production rates followed by steep declines. As a result, we must continually drill for and develop new oil and gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find and develop these reserves. Our challenge is to find and develop reserves at economic rates and commence production of these reserves as quickly and efficiently as possible.
Oil and Gas Property Costs
Spinnaker participated in 20 successful wells in 29 attempts in 2003. Capital costs incurred for leasehold and other acquisition, exploration and development activities in 2003, excluding asset retirement costs of $30.0 million, totaled $276.2 million compared to $342.5 million in 2002. Excluding asset retirement costs, capital costs incurred for development and leasehold and other acquisition activities totaled approximately 66% of total capital costs incurred in 2003. The majority of the development costs were incurred at Front Runner and Mississippi Canyon 496 (“Zia”). During 2003, we announced the Front Runner spar hull completion and delivery and progress on the related topsides. We expect to take possession of the spar production facility in the summer of 2004, followed by the commencement of well completion activities. Initial production on Front Runner is scheduled for the second half of 2004. Zia, our third successful deepwater completion, commenced production in June 2003. We also announced a deepwater discovery at Desoto Canyon 620/621 (Amazon/Spiderman) in late 2003.
We currently plan to drill approximately 20 wells on the shelf and 13 wells in the deep water in 2004. We expect more than 50% of our 2004 capital expenditure budget to be used for exploration activities, up from 34% in 2003.
Finding and Development Costs
We believe that the DD&A rate is the best measure for evaluating finding and development costs per Mcfe since the rate generally considers all acquisition, exploration and development costs. The rate also considers any additional development costs associated with proved reserves, such as costs for drilling new wells,
sidetracks and recompletions, which Spinnaker will incur in the future to produce the oil and gas reserves and an estimate of the costs to abandon wells, platforms, facilities and pipelines after reservoirs are depleted. However, other factors must also be considered when relying on the DD&A rate as a measure for evaluating a company’s finding and development costs per Mcfe. In most cases, the total estimated resource of a reservoir is not usually proved with only one well, and the initial proved reserves are generally burdened with 100% of the development costs as well as any future development costs.
The DD&A rate per Mcfe is calculated quarterly and increased 13% to $2.68 in the fourth quarter of 2003 from $2.37 in the fourth quarter of 2002. The increase in the DD&A rate was primarily due to costs of $34.3 million associated with nine unsuccessful wells in 2003 and higher finding costs associated with new discoveries in 2003, as well as the timing and reserve recognition associated with economical discoveries.
Oil and Gas Reserves
Spinnaker has achieved reserve growth through exploration activities. We have not acquired reserves through acquisition activities. As of December 31, 2003, Ryder Scott estimated net proved reserves at approximately 332.6 Bcfe, with a present value, discounted at 10% per annum, of pre-tax future net cash flows of approximately $1.1 billion. The discovery of the Front Runner field in 2001 significantly changed our reserve profile. Proved oil and condensate reserves were 53% of total proved reserves as of December 31, 2003 compared to 10% as of December 31, 2000. Proved undeveloped reserves were approximately 68% of total proved reserves as of December 31, 2003. Front Runner represented approximately 70% of total proved undeveloped reserves.
Natural Gas and Oil Prices and Hedging Activities
Prices for natural gas and oil fluctuate widely, primarily affecting the amount of cash flow available for capital expenditures, our ability to borrow and raise additional capital and the amount of natural gas and oil that we can economically produce. Natural gas prices have been extremely volatile recently as a result of various factors, including weather, industrial demand and uncertainty related to the ability of the energy industry to provide supply to meet future demand. There are questions whether fundamentals support current natural gas prices.
Spinnaker enters into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. However, these contracts also limit the benefits we would realize if prices increase. We recorded a net hedging loss of $42.6 million from 2001 through 2003, including a net hedging loss of $37.7 million in 2003. Major challenges related to our hedging activities include a determination of the proper production volumes to hedge and acceptable commodity price levels for each hedge transaction.
Revenues, profitability, cash flow and future growth depend substantially on prevailing oil and gas prices and our ability to find and develop oil and gas reserves that are economically recoverable. A substantial or extended decline in the prices for oil and gas could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and access to capital.
Critical Accounting Policies
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires us 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 DD&A of proved oil and gas properties. Oil and gas 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. Our critical accounting policies are as follows:
Full Cost Method of Accounting
The accounting for oil and gas exploration and production is subject to special accounting rules that are specific to the industry. Two allowable methods exist for these activities: the successful efforts method and the full cost method. Several significant differences exist between the two methods. The major difference is under the successful efforts method, costs such as geological and geophysical, exploratory dry holes and delay rentals are expensed as incurred where under the full cost method, these types of charges are capitalized into the full cost pool.
We use the full cost method of accounting for investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and gas properties 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, completions, platforms, facilities, pipelines and the costs related to the retirement of these assets. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas 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 oil and gas reserves.
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. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. As a result, we believe that the full cost method of accounting better reflects the true economics of exploring for and developing oil and gas reserves. Our financial position and results of operations would have been significantly different had we used the successful efforts method of accounting for our oil and gas investments.
Reserve Estimates
Ryder Scott prepares estimates of our proved oil and gas reserves as of June 30 and December 31 each year. These estimates of proved reserves are based on the quantities of oil and gas which geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate, among others, the amount and timing of future production, operating, workover and transportation expenses and development and abandonment costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our oil and gas reserves.
Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, we use the units-of-production method to amortize our oil and gas properties and the quantity of reserves could significantly impact our DD&A rate and related expense. Our oil and gas properties are also subject to a ceiling limitation based in part on the quantity of our proved reserves. Finally, these proved reserves are the basis for our supplemental oil and gas disclosures.
Depreciation, Depletion & Amortization
Spinnaker’s full cost DD&A expense is comprised of many factors, including costs incurred in the acquisition, exploration and development of proved oil and gas reserves, production levels, estimates of proved reserve quantities and future development and abandonment costs. Spinnaker computes the provision for DD&A of oil and gas 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 estimated salvage values associated with future asset retirement obligations.
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, 2003, we excluded from the amortization base estimated future expenditures of $29.5 million associated with common development costs for the 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 $29.5 million had been included in the amortization base as of December 31, 2003, and no additional reserves were assigned to the Front Runner project, the DD&A rate as of December 31, 2003 would have been $2.77 per Mcfe, or an increase of $0.09 over the actual DD&A rate of $2.68 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 oil and gas reserves used in the full cost ceiling calculation, as discussed below.
Full Cost Ceiling
Capitalized costs of oil and gas properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effects of hedging activities in place as of December 31, 2003, 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, 2003, Spinnaker’s full cost ceiling, including estimated future net cash flows calculated using commodity prices of $6.29 per Mcf of natural gas and $30.34 per barrel of oil and condensate, exceeded capitalized costs of oil and gas properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, by approximately $213.9 million. Considering the volatility of natural gas and oil prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If natural gas or oil prices decline, even if for only a short period of time, if we incur significant costs associated with unsuccessful drilling operations or if we have downward revisions to our estimated proved reserves, it is possible that write-downs of oil and gas properties could occur in the future.
Unproved Properties
The costs associated with unproved properties and properties under development are not initially included in the amortization base and primarily 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.
Leasehold Costs
In June 2001, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 141, “Business Combinations,” which requires the use of the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review of impairment. The new standard also requires that, at a minimum, all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS No. 141 and 142 had no impact on Spinnaker’s financial position or results of operations.
A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 141 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, we have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 141 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $72.2 million and $59.0 million as of December 31, 2003 and 2002, respectively, from oil and gas properties to a separate intangible assets line item. These costs include those to acquire contract-based drilling and mineral use rights such as delay rentals, lease bonuses, commission and brokerage fees and other leasehold costs. Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules, as allowed by SFAS No. 142. Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on compliance with covenants under the Revolver.
Spinnaker will continue to classify its oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided. We anticipate there will be no effect on our results of operations or cash flows.
Asset Retirement Obligations
We recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying amount of the asset. The fair value of a liability for an asset retirement obligation is the amount which that liability could be settled in a current transaction between willing parties. Spinnaker uses the expected cash flow approach for calculating asset retirement obligations. The liability is discounted using the credit-adjusted risk-free interest rate in effect when the liability is initially recognized. The changes in the liability for an asset retirement obligation due to the passage of time are measured by applying an interest method of allocation to the amount of the liability at the beginning of the period. This amount is recognized as an increase in the carrying amount of the liability and as accretion expense classified as an operating item in the statement of operations.
Financial Instruments and Price Risk Management Activities
At December 31, 2003, our 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. Spinnaker enters into hedging arrangements from time to time to reduce our 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. We recorded a net hedging loss of $37.7 million, a net hedging gain of $4.7 million and a net hedging loss of $9.6 million in 2003, 2002 and 2001, respectively.
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. We have 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, $0.2 million and $0.1 million in 2003, 2002 and 2001, respectively. For further information concerning SFAS 123, see Note 2 of the Notes to Consolidated Financial Statements.
Related Parties
We purchase oilfield goods, equipment and services from Baker Hughes Incorporated (“Baker Hughes”), Cooper Cameron Corporation (“Cooper Cameron”), National-Oilwell, Inc. (“National-Oilwell”) and other oilfield services companies in the ordinary course of business. Spinnaker incurred charges of approximately $7.5 million, $16.1 million and $16.3 million in 2003, 2002 and 2001, respectively, from affiliates of Baker Hughes. Mr. Michael E. Wiley, a director of Spinnaker, serves as Chairman of the Board, Chief Executive Officer and President of Baker Hughes. Spinnaker incurred charges of approximately $0.1 million, $0.1 million and $0.1 million in 2003, 2002 and 2001, respectively, from Cooper Cameron. Mr. Sheldon R. Erikson, a director of Spinnaker, serves as Chairman of the Board, Chief Executive Officer and President of Cooper Cameron. Spinnaker incurred charges of approximately $0.1 million and $0.2 million in 2003 and 2002, respectively, from National-Oilwell. Mr. Roger L. Jarvis, Chairman of the Board, Chief Executive Officer and President of Spinnaker, has served as a director of National-Oilwell since February 2002. These amounts represent less than 1% of Baker Hughes’, Cooper Cameron’s and National-Oilwell’s total revenues.
We believe that these transactions are at arm’s-length and the charges we pay 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. Each of these companies is a leader in their respective segments of the oilfield services sector. Spinnaker could be at a disadvantage if it were to discontinue using these companies as vendors.
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 Spinnaker uses cannot eliminate exploration risk and require experienced technical personnel whom we may be unable to attract or retain.
Our future success will depend on the success of our exploratory drilling program. Exploration activities involve numerous risks, including the risk that no commercially productive oil or gas reservoirs will be
discovered. In addition, we are often 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. We could incur losses as a result of expenditures on unsuccessful wells. Poor results from our exploration activities could materially and adversely affect future cash flows and results of operations.
Our exploratory drilling success will depend, in part, on our ability to attract and retain experienced explorationists and other professional personnel. Competition for explorationists and engineers with experience in the Gulf of Mexico is extremely intense. If we cannot retain current personnel or attract additional experienced personnel, our ability to compete in the Gulf of Mexico could be adversely affected.
A substantial portion of our proved reserves are associated with the deepwater oil discovery at Front Runner. The development of Front Runner has required and will continue to require 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 we have 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 second half of 2004. Spinnaker has incurred $129.4 million in capital expenditures for Front Runner through December 31, 2003 and expects to incur an aggregate of approximately $22.5 million in future development costs during 2004 and $34.6 million after 2004. Because another oil and gas exploration and production company operates Front Runner, we have a limited ability to influence the operations and costs associated with this property.
Front Runner is located in approximately 3,500 feet of water. The eight wells have been drilled in the Front Runner area to total depths in excess of 20,000 feet. We have limited experience with large deepwater and deep drilling depth discoveries similar to Front Runner as most of our prior discoveries have occurred in shallower waters and drilling depths. As a result of these uncertainties and risks, we may encounter difficulties and delays that could cause actual expenditures to exceed anticipated amounts.
Construction of the topsides of the spar production facility is expected to be completed in the second quarter of 2004. Construction of the hull is complete. 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 approximately 70% of Spinnaker’s proved undeveloped reserves as of December 31, 2003. If the actual reserves associated with Front Runner are substantially less than the estimated reserves, our results of operations and financial condition could be adversely affected.
When production ultimately commences for this discovery, it may produce substantially less oil and gas than currently projected. Additionally, we cannot predict commodity prices when production commences. If production is substantially less than currently projected or commodity prices are low, our 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, our future business, financial condition and operating results will be materially and adversely affected.
The oil and gas business involves many operating risks that can cause substantial losses.
The oil and gas business involves a variety of operating risks, including fires, explosions, blow-outs and surface cratering, uncontrollable flows of underground oil, natural gas and formation water, natural disasters, pipe or cement failures, casing collapses, embedded oilfield drilling and service tools, abnormally pressured formations and environmental hazards such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases. If any of these events occur, we could incur substantial losses as a result of injury or loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of our operations and repairs to resume operations. If we experience any of these problems, it could affect well bores, platforms, gathering systems and processing facilities, which could adversely affect our ability to conduct operations.
Offshore operations are also subject to a variety of operating risks 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, we could incur substantial liabilities that could reduce or eliminate the funds available for exploration, development or leasehold acquisitions, or result in loss of equipment and properties.
For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. If a significant accident or other event occurs and is not fully covered by insurance, it could adversely affect our operations.
Exploration for oil and gas 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.
We explore for oil and gas 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 involve a higher risk of mechanical failure. We have experienced and will continue to experience significantly higher drilling costs for deep depth and deepwater prospects.
As of December 31, 2003, approximately 86% of our 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 we can market the oil or gas, increasing both the financial and operational risk involved with these operations.
Spinnaker is vulnerable to operational, regulatory and other risks associated with the Gulf of Mexico because we currently explore and produce exclusively in that area.
Our operations and revenues are impacted acutely by conditions in the Gulf of Mexico because we currently explore and produce exclusively in that area. This concentration of activity makes us more vulnerable than many of our competitors to the risks associated with the Gulf of Mexico, including delays and increased costs relating to adverse weather conditions, drilling rig and other oilfield services and compliance with environmental and other laws and regulations.
A significant part of the value of our production and reserves is concentrated in a small number of offshore properties. Because of this concentration, any production problems or inaccuracies in reserve estimates related to those properties are more likely to adversely impact our business.
During 2003, approximately 70% of our production came from seven properties in the Gulf of Mexico. If mechanical problems, storms or other events curtailed a substantial portion of this production, our cash flow
would be adversely affected. In addition, as of December 31, 2003, our proved reserves were located on 36 different blocks in the Gulf of Mexico, with 73% of the proved reserves attributable to seven of these properties. One property, Front Runner, accounted for approximately 70% of total proved undeveloped reserves and 50% of total proved reserves. If the actual reserves associated with any one of these seven properties are substantially less than the estimated reserves, Spinnaker’s results of operations and financial condition could be adversely affected.
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. 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. We expect initial production from the majority of our proved undeveloped reserves in the deep water in the second half of 2004.
If any seismic contractor terminates its data agreement with Spinnaker, our ability to find additional reserves could be impaired.
Our success depends heavily on access to 3-D seismic data. If any seismic contractor terminates its data agreement with us, we would lose access to a portion of the 3-D seismic data, which loss could have an adverse effect on our ability to find additional reserves. A seismic contractor may terminate its data agreement with us on several grounds, including if a competitor of the seismic contractor acquires control of Spinnaker or if we breach 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 we 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, we may be placed at a competitive disadvantage, and competitive pressures may force us 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 we can. We cannot be certain that we will be able to implement technologies on a timely basis or at a cost that is acceptable to us. One or more of the technologies that Spinnaker currently uses or that we may implement in the future may become obsolete, which may adversely affect our 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 our 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 Spinnaker’s reserves.
The process of estimating oil and gas 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-Oil and Gas Reserves.”
Ryder Scott prepares Spinnaker’s reserve estimates as of June 30 and December 31 each year. In order to assist in the preparation of these estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data, and the extent, quality and reliability of this data can vary. The process also requires economic assumptions such as oil
and gas prices, drilling and operating expenses, capital expenditures, taxes and the availability of funds. Even though our reserve estimates are prepared by an independent third party, these estimates of oil and gas reserves are still inherently imprecise.
Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves most likely will vary from our estimates. Any significant variance could materially affect the estimated quantities and net present value of reserves. In addition, estimates of proved reserves may be adjusted to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our 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, 2003. 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 our proved reserves is the current market value of our estimated oil and gas reserves. In accordance with Commission requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value of future net cash flows estimate.
The failure to replace reserves would adversely affect our production and cash flows.
Spinnaker’s future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves, our level of production and cash flows would be adversely impacted. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics and mechanical issues. Total proved reserves will decline as reserves are produced unless we conduct other successful exploration and development activities or acquire properties containing proved reserves, or both. Our ability to make the necessary capital investment to maintain or expand its asset base of oil and gas reserves would be impaired to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable. We may not be successful in exploring for, developing or acquiring additional reserves. If we are not successful, our future production and revenues will be adversely affected.
Relatively short rates of production for Gulf of Mexico properties compared to other producing regions of the world subject us to more active reserve replacement efforts, require us to incur capital expenditures more frequently to replace production and generate growth in reserves and may impair our ability to slow or shut-in production during periods of low prices for oil and gas.
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, our reserve replacement needs from new prospects in the Gulf of Mexico are greater and require us to incur capital expenditures more frequently to replace production than would typically be required in many other producing regions of the world. We expect a decline in production in the first quarter of 2004 due to the rapid production decline of certain producing wells, timing related to first production from recent shelf discoveries and shut-ins for facility work not related to our properties.
Also, revenues and return on capital will depend significantly on oil and gas prices during these relatively short production periods. The potential need to generate revenues to fund ongoing capital commitments or reduce future indebtedness may limit our ability to slow or shut-in production from producing wells in the future during periods of low prices for oil and gas.
Natural gas and oil prices fluctuate widely, and low prices could have a material adverse impact on our business and financial results.
Our revenues, profitability and future growth depend substantially on prevailing oil and gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise
additional capital. The amount we can borrow under the Revolver is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and gas that we 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 oil and gas producing regions, the domestic and foreign supply of oil and gas, 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 oil and gas 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.
Spinnaker enters into hedging arrangements from time to time to reduce our 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 we believe represent minimum credit risks. We cannot provide assurance that these trading counterparties will not become credit risks in the future. Hedging arrangements expose us 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 we could receive from increases in the prices for natural gas and oil. We cannot provide assurance that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in natural gas and oil prices. We may choose not to engage in hedging transactions in the future. As a result, Spinnaker may be adversely affected during periods of declining natural gas and oil prices.
Spinnaker’s success depends on our Chief Executive Officer and other key personnel, the loss of who could disrupt business operations.
We depend to a large extent on the efforts and continued employment of our President and Chief Executive Officer, Roger L. Jarvis, and other key personnel. If Mr. Jarvis or other key personnel resign or become unable to continue in their present role and if they are not adequately replaced, Spinnaker’s business operations could be adversely affected.
Spinnaker is subject to complex laws and regulations, including environmental regulations, which can adversely affect the cost, manner or feasibility of doing business.
Exploration for and development, production and sale of oil and gas in the U.S. and especially in the Gulf of Mexico are subject to extensive federal, state and local laws and regulations, including environmental laws and regulations. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include discharge permits for drilling operations, drilling bonds, reports concerning operations and taxation.
Under these laws and regulations, Spinnaker could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs and other environmental damages. We do not believe that full insurance coverage for all potential environmental damages is available at a reasonable cost. Failure to comply with these laws and regulations also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws and regulations could change in ways that substantially increase 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 Spinnaker’s financial condition and results of operations.
Competition in the industry is intense, and Spinnaker is smaller and has a more limited operating history than most of our competitors in the Gulf of Mexico.
We compete with major and independent oil and gas companies for property acquisitions. We also compete for the equipment and labor required to operate and develop our properties. Most of our competitors have substantially greater financial and other resources than we do. 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 we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and productive oil and gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for oil and gas prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of the competitors have been operating in the Gulf of Mexico for a much longer time than Spinnaker has and have demonstrated the ability to operate through industry cycles.
We cannot control the activities on properties we do not operate.
Other companies operate some of the properties in which we have an interest, including Front Runner. As a result, we have a limited ability to exercise influence over operations for these properties or their associated costs. Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially and adversely affect the realization of 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 our control, including timing and amount of capital expenditures, the operator’s expertise and financial resources, approval of other participants in drilling wells and selection of technology.
We may have difficulty financing our planned growth.
We have experienced and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of our drilling program. In the future, we expect that we will require additional financing, in addition to cash generated from operations, to fund planned growth. We cannot be certain that additional financing will be available on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our 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, 2003, 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. Warburg’s influence over Spinnaker may delay or prevent a change of control of Spinnaker and may adversely affect the voting and other rights of other stockholders.
Furthermore, conflicts of interest could arise in the future between Spinnaker and Warburg concerning, among other things, potential competitive business activities or business opportunities. Warburg is not restricted from competitive oil and gas exploration and production activities or investments. Warburg currently has significant equity interests in other public and private oil and gas companies. The interests of Warburg could differ from those of other stockholders.
A portion of our 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 our 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 Spinnaker.
The certificate of incorporation authorizes the Board of Directors to issue Preferred Stock without stockholder approval. If the Board of Directors elects to issue Preferred Stock, it could be more difficult for a third party to acquire control of Spinnaker, 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 Spinnaker.
Terrorist attacks on oil and gas production facilities, transportation systems and storage facilities could have a material adverse impact on our business.
Oil and gas production facilities, transportation systems and storage facilities could be targets of terrorist attacks. These attacks could have a material adverse impact on our results of operations and cash flows if certain oil and gas infrastructure integral to our operations were destroyed or damaged.
Results of Operations
Year Ended December 31, 2003 as Compared to the Year Ended December 31, 2002
Revenues and Production
Revenues increased $38.5 million, or 20%, in 2003 compared to 2002. The increase was primarily due to a 51% higher average commodity price in 2003, partially offset by the impact of an increase in net hedging losses and other of $42.2 million and 5% lower production in 2003.
Production decreased approximately 2.4 Bcfe, or 5%, in 2003 compared to 2002 primarily due to normal production declines. Average daily production in 2003 was 134 MMcfe compared to 141 MMcfe in 2002. Natural gas revenues increased $65.0 million, or 42%, due primarily to a 58% higher average price in 2003, partially offset by the impact of a decrease in production of approximately 4.7 Bcf, or 10%. Excluding the effects of hedging activities, the 2003 average natural gas price increased 58% to $5.46 per Mcf compared to $3.46 per Mcf in 2002. Oil and condensate revenues increased $15.8 million, or 57%, due primarily to a 16% higher average realized price in 2003 and an increase in production of approximately 374 MBbls, or 36%. The 2003 average oil and condensate price was to $30.56 per barrel compared to $26.39 per barrel in 2002. We expect a decline in production in the first quarter of 2004 due to the rapid production decline of certain producing wells, timing related to first production from recent shelf discoveries and shut-ins for facility work not related to our properties.
Lease Operating Expenses
Lease operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, labor, materials, supplies, property taxes, insurance, severance taxes and transportation, gathering and processing expenses. Lease operating expenses increased $4.3 million, or 23%, in 2003 compared to 2002. Of the total increase in lease operating expenses, approximately $1.4 million related to increased workover activities, $2.0 million related to activity on blocks that commenced production subsequent to December 31, 2002 and $0.9 million related to increased operating expenses on existing properties. The 31% increase in the lease operating expense rate per Mcfe in 2003 was primarily due to a pipeline workover on Green Canyon 177 (Sangria) of $2.4 million, or $0.05 per Mcfe, and lower production volumes.
Depreciation, Depletion and Amortization
DD&A increased $16.3 million, or 15%, in 2003 compared to 2002. Of the total increase in DD&A, $22.5 million related to a higher DD&A rate, offset in part by $6.2 million related to lower production volumes of 2.4 Bcfe. The 21% increase in the DD&A rate was primarily due to costs of $34.3 million associated with nine unsuccessful wells in 2003 and higher finding costs associated with new discoveries in 2003, as well as the timing and reserve recognition associated with economical discoveries.
General and Administrative
General and administrative expenses are overhead-related expenses, including among others, wages and benefits for non-capitalized employees, auditing fees, legal fees, insurance, office rent, travel and entertainment, computer supplies and maintenance and investor relations expenses. General and administrative expenses increased $1.8 million, or 16%, in 2003 compared to 2002. The increase was primarily due to higher employment-related costs associated with an increase in the number of employees in 2002 and 2003.
Year Ended December 31, 2002 as Compared to the Year Ended December 31, 2001
Revenues and Production
Revenues decreased $22.1 million, or 10%, in 2002 compared to 2001. The decrease was primarily due 3% lower production and a 14% lower average commodity price in 2002, partially offset by the impact of an increase in net hedging income of $14.2 million in 2002.
Production decreased approximately 1.7 Bcfe, or 3%, 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, or 26%, due primarily to 12% lower production and a 16% lower average price in 2002. The production declines of certain producing wells, particularly in the High Island 202 area, resulted in lower natural gas production in 2002. Excluding the effects of hedging activities, the 2002 average natural gas price decreased 16% to $3.46 per Mcf compared to $4.14 per Mcf in 2001. Oil and condensate revenues increased $19.7 million, or 256%, due to an increase in production of approximately 730 MBbls, or 235%, and a 6% higher average realized price in 2002. The 2002 average oil and condensate price was $26.39 per barrel compared to $24.90 per barrel in 2001. We expected 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
Lease operating expenses increased $6.1 million, or 50%, 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 decreases of $0.9 million in operating expenses associated with existing wells and $0.3 million in workovers in 2002. The 52% 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 Spinnaker. Additionally, we experienced higher lease operating rates associated with new wells compared to our historical average lease operating rates due to well locations, transportation and gathering agreements and processing requirements.
Depreciation, Depletion and Amortization
DD&A increased $23.9 million, or 28%, 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. The 33% increase in the DD&A rate per Mcfe 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
General and administrative expenses increased $1.5 million, or 16%, in 2002 compared to 2001. The increase was primarily due to higher employment-related costs associated with an increase in the number of employees in 2001 and 2002 and an increase in professional services fees.
Interest Income
Interest income decreased $2.6 million, or 72%, in 2002 compared to 2001 primarily due to lower average cash and short-term investment balances and significantly lower interest rates in 2002.
Liquidity and Capital Resources
Revenues, profitability, cash flow and future growth depend substantially on prevailing oil and gas prices and our ability to find and develop oil and gas reserves that are economically recoverable. A substantial or extended decline in the prices for natural gas or oil could have a material adverse effect on Spinnaker’s financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and access to capital.
We have experienced and expect to continue to experience substantial capital requirements, primarily due to our active exploration and development programs in the Gulf of Mexico. Spinnaker has capital expenditure plans
for 2004 totaling approximately $250.0 million. We use a risk-weighted model to calculate budgeted capital expenditures on a project-by-project basis. If we experience greater than anticipated success on budgeted projects, capital expenditures will increase.
Net additions to property and equipment in 2003 were $308.3 million, including asset retirement costs of $30.0 million. We incurred capital expenditures of approximately $81.3 million in 2003 related to deepwater development activities, including $48.3 million associated with the deepwater discovery at Front Runner. Inception-to-date capital expenditures through December 31, 2003 on the Front Runner project were $129.4 million. As of December 31, 2003, we expect to incur approximately $57.1 million in future development costs related to Front Runner, including approximately $22.5 million in 2004 and $34.6 million thereafter.
Natural gas and oil prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under the Revolver is subject to semi-annual re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of natural gas and oil that we can economically produce. Lower prices and/or lower production may decrease revenues, cash flows and the borrowing base under the Revolver, thus reducing the amount of financial resources available to meet our capital requirements. We believe that cash flows from operations, proceeds from available borrowings under the Revolver and Front Runner spar production facility financing opportunities will be sufficient to meet our 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 activities. In the event additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis. As of December 31, 2003, we had borrowings of $50.0 million and were in compliance with the covenants and restrictive provisions under the Revolver. Subsequent to December 31, 2003, we borrowed an additional $25.0 million and expect to incur additional borrowings under the Revolver in 2004.
Spinnaker has an effective shelf registration statement relating to the potential public offer and sale by us or certain of our 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 we will or could sell any such securities.
Contractual Obligations
We lease administrative offices, office equipment and oil and gas equipment under non-cancelable operating leases. Contractual obligations as of December 31, 2003 were as follows (in thousands):
(1) Contractual obligations for seismic data acquisitions.
We will incur obligations in the ordinary course of business under purchase and service agreements that are not included in the table above. These obligations, among others, include estimated future development costs of approximately $177.5 million for the costs of drilling additional wells, completions, recompletions, platforms, pipelines, facilities, tie-backs and abandonments related to our proved reserves. Our asset retirement obligations as of December 31, 2003 were $33.0 million.
Components of Cash Flow
Cash and cash equivalents decreased $17.2 million to $15.3 million as of December 31, 2003. The components of the decrease in cash and cash equivalents included $198.1 million provided by operating activities, $266.0 million used in investing activities and $50.7 million provided by financing activities.
Operating Activities
Net cash provided by operating activities in 2003 increased 29% to $198.1 million primarily due to higher commodity prices. Cash flow from operations is dependent upon our ability to increase production through exploration and development activities and the prices of natural gas and oil. We have made significant investments to expand our operations in the Gulf of Mexico.
We sell our natural gas and oil production under fixed or floating market price contracts. Spinnaker enters into hedging arrangements from time to time to reduce our exposure to fluctuations in natural gas and oil prices and to achieve more predictable cash flow. However, these contracts also limit the benefits we would realize if prices increase. See “Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Price Risk
Spinnaker’s revenues, profitability and future growth depend substantially on prevailing oil and gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. Lower prices may also reduce the amount of natural gas and oil that we can economically produce. We sell our natural gas and oil production under fixed or floating market price contracts. Spinnaker enters into hedging arrangements from time to time to reduce our 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 we would realize if prices increase. Our current financial derivative contracts include fixed price swap contracts and cashless collar arrangements that have been placed with major trading counterparties we believe represent minimum credit risks. We cannot provide assurance that these trading counterparties will not become credit risks in the future. Under our current hedging practice, we generally do not hedge more than 66 2/3% of our estimated twelve-month production quantities without the prior approval of the Risk Management Committee of the Board of Directors.
We enter into NYMEX related swap contracts and collar arrangements from time to time. These 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 us for the difference between the fixed price and the settlement price if the settlement price is below the fixed price. We are 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, 2003, our commodity price risk management positions in fixed price natural gas swap contracts and related fair values were as follows:
In a collar arrangement, the counterparty is required to make a payment to us for the difference between the fixed floor price and the settlement price if the settlement price is below the fixed floor price. We are 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 and ceiling prices. As of December 31, 2003, our commodity price risk management positions in natural gas collar arrangements and related fair values were as follows:
We reported net liabilities of $2.7 million and $19.9 million related to financial derivative contracts as of December 31, 2003 and 2002, respectively. Amounts related to hedging activities were as follows (in thousands):
We recognized no ineffective component of the derivatives and net hedging gains (losses) in revenues in 2003, 2002 and 2001 as follows (in thousands):
Based on future natural gas prices as of December 31, 2003, we would reclassify a net loss of $2.7 million from accumulated other comprehensive loss to earnings in 2004. The amounts ultimately reclassified into earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement.
To calculate the potential effect of the derivative contracts on future revenues, we applied NYMEX natural gas forward prices as of December 31, 2003 to the quantity of our 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):
Subsequent to December 31, 2003, the fair value of our commodity price risk management positions in fixed price natural gas swap contracts and natural gas collar arrangements using an average natural gas forward price of $5.59 as of March 10, 2004 was a net liability of approximately $1.4 million, including first quarter 2004 settlements resulting in income of $1.7 million. Following are Spinnaker’s commodity price risk management positions in fixed price natural gas swap contracts and natural gas collar arrangements as of March 10, 2004:
Natural Gas Swap Contracts
Natural Gas Collar Arrangements
Interest Rate Risk
Spinnaker 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 Revolver. We do not currently use interest rate derivative financial instruments to manage exposure to interest rate changes, but may do so in the future.
Item 8.
Item 8. Financial Statements and Supplementary Data
The consolidated financial statements and supplementary data of the Company appear on pages 45 through 73 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.
Item 9. Change 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.
Item 9A.
Item 9A. Controls and Procedures
Our Chief Executive Officer and Chief Financial Officer performed an evaluation of our disclosure controls and procedures, which have been designed to permit us to effectively identify and timely disclose important information. They concluded that the controls and procedures were effective as of December 31, 2003. During the three months ended December 31, 2003, we made no change in our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
The Company’s Definitive Proxy Statement for its 2004 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.
Spinnaker’s Board of Directors has adopted a code of ethics for the chief executive officer, chief financial officer, principal accounting officer and other senior financial officers. The Financial Code of Ethics is available on the Company’s internet website at www.spinnakerexploration.com and available in print, free of charge, upon stockholder request to Spinnaker Exploration Company, 1200 Smith Street, Suite 800, Houston, Texas 77002, Attention: Corporate Secretary.
Item 11.
Item 11. Executive Compensation
The Company’s Definitive Proxy Statement for its 2004 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.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The Company’s Definitive Proxy Statement for its 2004 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.
Item 13.
Item 13. Certain Relationships and Related Transactions
The Company’s Definitive Proxy Statement for its 2004 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.
Item 14. Principal Accountant Fees and Services
The Company’s Definitive Proxy Statement for its 2004 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 14.
PART IV
Item 15.
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 45.
(3) Exhibits
See “Exhibit Index” on page 74.
The management contracts and compensatory plans or arrangements required to be filed as exhibits to this report are as follows:
(b) Reports on Form 8-K
A Current Report on Form 8-K dated and furnished on October 30, 2003 provided third quarter 2003 earnings and operations information through October 30, 2003 pursuant to Item 12, “Results of Operations and Financial Condition.”
A Current Report on Form 8-K dated November 4, 2003 and furnished on November 6, 2003 announced the appointment of Gonzalo Enciso as Vice President, Chief Geoscientist, pursuant to Item 9, “Regulation FD Disclosure.”
A Current Report on Form 8-K dated and filed on December 16, 2003 provided updated derivatives and hedging activities pursuant to Item 5, “Other Events and Regulation FD Disclosure.”
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.
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.
SPINNAKER EXPLORATION COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page
Independent Auditors’ Report
Consolidated Balance Sheets as of December 31, 2003 and 2002
Consolidated Statements of Operations for each of the years in the three-year period ended
December 31, 2003
Consolidated Statements of Equity for each of the years in the three-year period ended
December 31, 2003
Consolidated Statements of Cash Flows for each of the years in the three-year period ended
December 31, 2003
Notes to Consolidated Financial Statements
Independent Auditor’s Report on Consolidated Financial Statement Schedule
Schedule II-Valuation and Qualifying Accounts and Reserves
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, 2003 and 2002, and the related consolidated statements of operations, equity and cash flows for each of the years in the three-year period ended December 31, 2003. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, 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, 2003, the Company changed its method of accounting for asset retirement obligations, and effective January 1, 2001, the Company changed its method of accounting for derivative instruments.
KPMG LLP
Houston, Texas
February 17, 2004
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
The accompanying notes are an integral part of these consolidated financial statements.
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF EQUITY
(In thousands, except share data)
The accompanying notes are an integral part of these consolidated financial statements.
SPINNAKER EXPLORATION COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
The accompanying notes are an integral part of these consolidated financial statements.
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 oil and gas 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 oil and gas properties. Oil and gas 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 $0.6 million and $0.3 million as of December 31, 2003 and 2002, respectively. Other non-current assets include unamortized debt financing costs of
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
$1.1 million and $0.3 million as of December 31, 2003 and 2002. respectively. These costs are amortized to interest expense over the three-year term of the related credit facility. Amortization of these and other debt financing costs included in interest expense was $0.4 million, $0.3 million and $0.2 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Full Cost Method of Accounting
The Company uses the full cost method of accounting for its investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and gas 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, completions, platforms, facilities, pipelines and the costs related to the retirement of these assets. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of oil and gas 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 oil and gas reserves. Substantially all the Company’s exploration activities are conducted jointly with others and, accordingly, the oil and gas property balances reflect only its proportionate interest in such activities.
Depreciation, Depletion and Amortization
The Company computes the provision for DD&A of oil and gas 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 estimated salvage values associated with future asset retirement obligations.
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, 2003, the Company excluded from the amortization base estimated future expenditures of $29.5 million associated with common development costs for its deepwater discovery at Green Canyon 338/339/382 (“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 oil and gas properties, net of accumulated DD&A, asset retirement obligations and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, including the effects of hedging activities in place as of December 31, 2003, 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.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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 $151.2 million of net unproved property costs as of December 31, 2003 excluded from the amortizable base, net costs of $9.9 million, $38.4 million and $19.7 million were incurred in 2003, 2002 and 2001, respectively, and $83.2 million was incurred prior to 2001. The majority of the costs will be evaluated over the next five years.
Leasehold Costs
In June 2001, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 141, “Business Combinations,” which requires the use of the purchase method of accounting for business combinations initiated after June 30, 2001 and eliminates the pooling-of-interests method. In July 2001, the FASB also issued SFAS No. 142, “Goodwill and Other Intangible Assets,” which discontinues the practice of amortizing goodwill and indefinite lived intangible assets and initiates an annual review of impairment. The new standard also requires that, at a minimum, all intangible assets be aggregated and presented as a separate line item in the balance sheet. The adoption of SFAS No. 141 and 142 had no impact on the Company’s financial position or results of operations.
A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141 and 142 to companies in the extractive industries, including oil and gas companies. The issue is whether SFAS No. 141 requires registrants to classify the costs of mineral rights associated with extracting oil and gas as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs, and provide specific footnote disclosures. Historically, the Company has included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties. If it is ultimately determined that SFAS No. 141 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, the Company would be required to reclassify approximately $72.2 million and $59.0 million as of December 31, 2003 and 2002, respectively, from oil and gas properties to a separate intangible assets line item. These costs include those to acquire contract-based drilling and mineral use rights such as delay rentals, lease bonuses, commission and brokerage fees and other leasehold costs. The Company’s cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with full cost accounting rules. Further, the Company does not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on the Company’s compliance with covenants under its revolving credit agreement.
Spinnaker will continue to classify its oil and gas leasehold costs as tangible oil and gas properties until further guidance is provided. The Company anticipates there will be no effect on its results of operations or cash flows.
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 $6.7 million, $5.9 million and $5.1 million in 2003, 2002 and 2001, respectively.
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 $2.1 million, $1.5 million and $0.5 million in 2003, 2002 and 2001, 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 settlements in volumes or cash, as required by applicable contracts. Imbalances included in accounts receivable were $0.9 million and $0.6 million as of December 31, 2003 and 2002, respectively. Imbalances included in accrued liabilities were $4.1 million and $2.5 million as of December 31, 2003 and 2002, respectively.
Income Taxes
Under 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 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
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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, $0.2 million and $0.1 million in 2003, 2002 and 2001, 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):
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 2003, 2002 and 2001 as follows:
Financial Instruments and Price Risk Management Activities
At December 31, 2003, 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
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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 recorded a net reserve of $3.2 million related to these receivables.
New Accounting Pronouncements
Effective January 1, 2003, Spinnaker adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 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. As of January 1, 2003, the Company recorded asset retirement costs of $21.4 million and asset retirement obligations of $26.0 million. The cumulative effect of change in accounting principle was $3.5 million, after taxes of $2.0 million.
The reconciliation of the beginning and ending asset retirement obligations as of December 31, 2003 is as follows (in thousands):
(1) The actual cost of the abandonments was approximately $3.4 million, resulting in a gain on settlement of asset retirement obligations of approximately $0.5 million.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
The following table summarizes the pro forma net income and earnings per share for the years ended December 31, 2002 and 2001 as if SFAS No. 143 had been adopted on January 1, 2000 (in thousands, except per share amounts):
The following table summarizes pro forma asset retirement obligations as of December 31, 2002 and 2001 as if SFAS No. 143 had been adopted on January 1, 2000 (in thousands):
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):
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(1) 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 recorded a net reserve of $3.2 million related to these receivables.
4. Debt:
On December 28, 2001, the Company entered into an unsecured $200.0 million credit facility (“Credit Facility”) with a group of seven banks. The borrowing base of the three-year Credit Facility was re-determined on a semi-annual basis. The banks and the Company also had the option to request one additional re-determination each year. The banks could also require a borrowing base re-determination if they permitted the sale, transfer or disposition of assets included in the borrowing base valued in excess of $20.0 million. The banks determined the borrowing base in their sole discretion and in their usual and customary manner. The amount of the borrowing base was a function of the banks’ view of the Company’s reserve profile, future commodity prices and projected cash flows. The borrowing base was $100.0 million as of December 18, 2003. The Company had the option to elect to use a base interest rate as described below or the London Interbank Offered Rate (“LIBOR”) 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 was a fluctuating rate of interest equal to the higher of either (i) The Toronto-Dominion Bank’s base rate for dollar advances made in the United States or (ii) the Federal Funds Rate plus 0.5% per annum. The commitment fee rate ranged from 0.3% to 0.5%, depending on borrowing base usage. The Credit Facility contained various covenants and restrictive provisions.
On December 19, 2003, Spinnaker revised and renewed the $200.0 million revolving credit agreement (the “Revolver”) with a group of eight banks. The Revolver consists of two tranches, Tranche A and Tranche B, and matures on December 19, 2006. Borrowings under each tranche constitute senior indebtedness.
Tranche A is available on a revolving basis through the maturity of the Revolver, and availability is subject to the borrowing base, currently $125.0 million, as determined by the banks. Tranche B is $50.0 million, is available in multiple advances through April 1, 2005 and is not subject to the borrowing base. Borrowings under Tranche B cannot be reborrowed once repaid. Total availability under Tranche A and Tranche B cannot exceed $200.0 million. Should the borrowing base exceed $150.0 million, Tranche B would be reduced by a like amount for the period the borrowing base exceeds $150.0 million until the maturity of Tranche B. At such time Tranche B is utilized, the banks are to be provided with security interests in virtually all of Spinnaker’s reserve base. Upon repayment of Tranche B, the security interests are to be released.
The borrowing base is re-determined semi-annually by the banks in their sole discretion and in their usual and customary manner. The banks and the Company also have the right to request one additional re-determination annually. The amount of the borrowing base is a function of the banks’ view of Spinnaker’s reserve profile, future commodity prices and projected cash flows. In addition to the semi-annual re-determinations, the banks have the right to re-determine the borrowing base in the event of the sale, transfer or disposition of assets included in the borrowing base exceeding $25.0 million, or $10.0 million when Tranche B is utilized.
The Company has the option to elect to use a base interest rate as described below or LIBOR plus, for each such rate, a spread based on the percentage of the borrowing base used at that time. The base rate spread ranges from 0.0% to 0.5% for Tranche A borrowings and from 2.0% to 2.75% for Tranche B borrowings. The LIBOR spread ranges from 1.25% to 2.0% for Tranche A borrowings and from 3.0% to 3.75% for Tranche B borrowings. The base interest rate under the Revolver is a fluctuating rate of interest equal to the higher of either
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(i) The Toronto-Dominion Bank’s base rate for dollar advances made in the United States or (ii) the Federal Funds Rate plus 0.5% per annum. The commitment fee rate ranges from 0.375% to 0.5%, depending on the borrowing base usage for Tranche A and is 0.625% for Tranche B.
The Revolver also includes the following restrictions and covenants:
• Other debt is prohibited except that senior debt may not exceed $10.0 million ($5.0 million when Tranche B is used), vendor indebtedness for the purchase of seismic data may not exceed $25.0 million, subordinated debt is permitted subject to certain conditions and a lease transaction involving the Front Runner spar is specifically permitted.
• Liens are generally prohibited; however, Spinnaker may grant a lien in the purchase of seismic data and pledges and deposits to secure hedging arrangements not to exceed $15.0 million.
• Dividends and stock buy-backs exceeding $10.0 million are prohibited in any fiscal year.
• The ratio of debt to EBITDA may not exceed 2.50 to 1.00.
• The ratio of current assets to current liabilities may not be less than 1.00 to 1.00. For purposes of the calculation, availability under the Revolver is added to current assets and maturities of the Revolver are excluded from current liabilities. Hedging assets and liabilities are also excluded from this calculation.
• Spinnaker’s tangible net worth is required to exceed 80% of the level at September 30, 2003, plus 50% of net income with certain non-cash gains and losses excluded from net income, plus 75% of future equity issuances.
• Spinnaker’s hedging transactions must not exceed 66 2/3% of estimated future production for the next 18 months and 33 1/3% for the period 19 to 36 months from the date of the transaction. There are also credit rating restrictions on counterparties as well as concentration limits.
On December 31, 2003, the Company had outstanding borrowings of $50.0 million and was in compliance with the covenants and restrictive provisions under the Revolver. Subsequent to December 31, 2003, the Company borrowed an additional $25.0 million and expects to incur additional borrowings under the Revolver in 2004.
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
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
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:
Officers, directors and employees have been granted options to purchase Common Stock under stock plans adopted in 1998, 1999, 2000, 2001 and 2003. Stock option grants generally vest ratably over four years, with 20% vesting on the date of grant and 20% vesting on the anniversary date of the grant in each of the succeeding four years. In the event of certain significant changes in control of the Company, all options then outstanding generally will become immediately exercisable in full. Following is a description of the major provisions of each stock plan.
2003 Stock Option Plan (“2003 Plan”)
Stockholders approved the 2003 Plan in May 2003. The number of shares of Common Stock that may be issued under the 2003 Plan may not exceed 1,650,000 shares. The exercise price of each option equals 105% of the fair market value of Spinnaker’s Common Stock on the date of grant. The maximum number of shares of Common Stock that may be subject to awards granted under the 2003 Plan to any one individual during any calendar year may not exceed 300,000 shares. The options expire after five years.
2001 Stock Incentive Plan (“2001 Plan”)
Stockholders approved the 2001 Plan in May 2001. The number of shares of Common Stock that may be issued under the 2001 Plan may not exceed 1,500,000 shares. The exercise price of each option equals the fair market value of Spinnaker’s Common Stock on the date of grant. 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. The options expire after ten years.
2000 Stock Option Plan (“2000 Plan”)
The Board of Directors of Spinnaker adopted the 2000 Plan in November 2000. 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. The exercise price of each option equals the fair market value of Spinnaker’s Common Stock on the date of grant. The options expire after ten years.
1999 Stock Incentive Plan (“1999 Plan”)
Stockholders approved the 1999 Plan in September 1999. The number of shares of Common Stock that may be issued under the 1999 Plan may not exceed 1,300,000 shares. The exercise price of each option equals the fair market value of Spinnaker’s Common Stock on the date of grant. 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. The options expire after ten years.
Adjunct Stock Option Plan (“Adjunct Plan”)
Stockholders approved the Adjunct Plan in connection with the 1999 Plan. The number of shares of Common Stock that may be issued under the Adjunct Plan may not exceed 21,920. The exercise price of each option equals the fair market value of Spinnaker’s Common Stock on the date of grant. The options expire after ten years.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
1998 Stock Option Plan (“1998 Plan”)
Stockholders approved the 1998 Plan in January 1998. The 1998 Plan was amended and restated in September 1999 and authorized the issuance of 2,673,242 shares of Common Stock. The exercise price of each option equals the fair market value of Spinnaker’s Common Stock on the date of grant. The options expire after ten years.
Presented below is a summary of stock option activity.
The Company transferred treasury shares to certain employees in connection with their exercises of 2,300, 2,944 and 2,128 options in 2003, 2002 and 2001, 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, 2003, the following options were outstanding and exercisable and had the indicated weighted average remaining contractual lives:
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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):
For the years ended December 31, 2003, 2002 and 2001, 2,361,630, 1,680,640 and 113,200 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 Cinergy Marketing & Trading, LP, Sequent Energy Management, L.P., Shell Trading (US) Company and Duke Energy Trade and Marketing LLC accounting for approximately 41%, 22%, 14% and 10%, respectively, of total natural gas and oil revenues, excluding the effects of hedging activities, for the year ended December 31, 2003. The Company had natural gas and oil sales to Duke Energy Trade and Marketing LLC, Cinergy Marketing & Trading, LP, Equiva Trading Company and Kinder Morgan Ship Channel Pipeline LP 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 Enron North America Corp., Tejas Gas Marketing, LLC, Reliant Energy Services, Inc. and Bridgeline Gas Marketing LLC 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.
9. Related-Party Transactions:
The Company incurred charges of approximately $7.5 million, $16.1 million and $16.3 million in 2003, 2002 and 2001, respectively, from affiliates of Baker Hughes Incorporated, an oilfield services company of which Mr. Michael E. Wiley, a director of Spinnaker, serves as Chairman of the Board, Chief Executive Officer and President. The Company incurred charges of approximately $0.1 million, $0.1 million and $0.1 million in 2003, 2002 and 2001, 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. The Company incurred charges of approximately $0.1 million and $0.2 million in 2003 and 2002, respectively, from National-Oilwell, Inc., an oilfield services company. Mr. Roger L. Jarvis, Chairman of the Board, Chief Executive Officer and President of Spinnaker, has served as a director of National-Oilwell, Inc. since February 2002. These amounts represent less than 1% of each company’s total revenues.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
10. Income Taxes:
The significant items giving rise to deferred income tax assets and liabilities are as follows (in thousands):
Tax benefits of $1.0 million and $1.4 million associated with the exercise of non-qualified stock options during the years ended December 31, 2003 and 2002 are reflected as a component of equity. The net deferred income tax liabilities include deferred tax assets of $1.0 million and $7.2 million related to the tax effect of the fair market value of derivatives as of December 31, 2003 and 2002, respectively, as required by SFAS No. 133, as amended. Upon adoption of SFAS No. 143 on January 1, 2003, the Company recorded a cumulative effect of change in accounting principle of $3.5 million, after taxes of $2.0 million.
As of December 31, 2003, the Company had approximately $268.0 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):
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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):
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 16,124 shares of Common Stock valued at $0.4 million in 2003, 9,062 shares of Common Stock valued at $0.3 million in 2002 and 5,456 shares of Common Stock valued at $0.2 million in 2001.
Leases
The Company leases administrative offices under a non-cancelable operating lease expiring in 2007. The lease agreement requires the Company to 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 $2.2 million, $1.6 million and $0.7 million in 2003, 2002 and 2001, respectively. Minimum future obligations under non-cancelable operating leases as of December 31, 2003 for the next five years are approximately $1.5 million, $1.3 million, $1.3 million, $0.5 million and less than $0.1 million, respectively.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Summary of Contractual Obligations
The Company leases administrative offices, office equipment and oil and gas equipment under non-cancelable operating leases. Contractual obligations as of December 31, 2003 were as follows (in thousands):
(1) Contractual obligations for seismic data acquisitions.
The Company will incur obligations in the ordinary course of business under purchase and service agreements that are not included in the table above. These obligations, among others, include estimated future development costs of approximately $177.5 million for the costs of drilling additional wells, completions, recompletions, platforms, pipelines, facilities, tie-backs and abandonments related to the proved reserves. Spinnaker’s asset retirement obligations as of December 31, 2003 were $33.0 million.
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. These 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, 2003, Spinnaker’s commodity price risk management positions in fixed price natural gas swap contracts and related fair values were as follows:
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
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
payment if the settlement price falls between the fixed floor and ceiling prices. As of December 31, 2003, Spinnaker’s commodity price risk management positions in natural gas collar arrangements and related fair values were as follows:
The Company reported net liabilities of $2.7 million and $19.9 million related to its financial derivative contracts as of December 31, 2003 and 2002, respectively. Amounts related to hedging activities were as follows (in thousands):
The Company recognized no ineffective component of the derivatives and net hedging gains (losses) in revenues in 2003, 2002 and 2001 as follows (in thousands):
Based on future natural gas prices as of December 31, 2003, the Company would reclassify a net loss of $2.7 million from accumulated other comprehensive loss to earnings in 2004. The amounts ultimately reclassified into earnings will vary due to changes in the fair value of the open derivative contracts prior to settlement.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
13. Quarterly Financial Data (Unaudited):
Quarterly operating results for the years ended December 31, 2003 and 2002 are summarized as follows (in thousands, except per share amounts):
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)
(1) DD&A per Mcfe was $2.56, $2.12 and $1.60 in 2003, 2002 and 2001, respectively. The cumulative effect of change in accounting principle included an impact to accumulated DD&A of approximately $0.9 million.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
(In thousands)
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, completions, platforms, facilities, pipelines and the costs related to the retirement of these assets. Development costs as of December 31, 2003 include asset retirement costs of $30.0 million and gain on settlement of asset retirement obligations of $0.5 million.
Costs being excluded from amortization consist of the following (in thousands):
Results of Operations for Oil and Gas Producing Activities
(In thousands)
(1) Operating expenses include costs incurred to operate and maintain wells and related equipment and facilities. These costs include, among others, workover expenses, labor, materials, supplies, property taxes, insurance, severance taxes and transportation, gathering and processing 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.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Proved oil and gas 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 oil and gas 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.
Reserve Quantity Information
(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 53%, 56% and 46% of total proved reserves as of December 31, 2003, 2002 and 2001, respectively, compared to 10% as of December 31, 2000. Of the Company’s total proved reserves as of December 31, 2003, 68% were proved undeveloped reserves. Front Runner represented approximately 70% 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(3) The 2003 revisions of previous estimates include a 6.1 Bcfe downward revision on Mississippi Canyon 496 (Zia) related to reserves originally booked below lowest known hydrocarbon. No downward revision on any individual property exceed 2% of proved reserves as of December 31, 2002.
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 produce the proved reserves, as well as certain abandonment costs based on year-end cost estimates and the estimated effect of future income taxes.
• 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 oil and gas 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 oil and gas 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 oil and gas 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 oil and gas properties could occur in the future.
Standardized Measure of Discounted Future Net Cash Flows
(In thousands)
(1) Prices for natural gas and oil used to calculate future cash inflows were $6.29, $4.91 and $2.71 per Mcf of natural gas and $30.34, $30.50 and $19.23 per barrel of oil as of December 31, 2003, 2002 and 2001, respectively.
SPINNAKER EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
Principal Sources of Change in the Standardized Measure of Discounted Future Net Cash Flows
(In thousands)
INDEPENDENT AUDITORS’ REPORT
To the Board of Directors and Stockholders of
Spinnaker Exploration Company:
Under date of February 17, 2004, we reported on the consolidated balance sheets of Spinnaker Exploration Company and subsidiaries as of December 31, 2003 and 2002, and the related consolidated statements of operations, equity and cash flows for each of the years in the three-year period ended December 31, 2003. 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 this consolidated financial statement schedule based on our audits.
In our opinion, this 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 17, 2004
Schedule II
SPINNAKER EXPLORATION COMPANY
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Years Ended December 31, 2003, 2002 and 2001
(In thousands)
EXHIBIT INDEX
* Filed herewith.