UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
| x | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2005. |
| ¨ | TRANSITION REPORTING PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO . |
COMMISSION FILE NO. 0-21911
SYNTROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
| | |
| Delaware | | 73-1565725 |
(State or other jurisdiction of incorporation or organization) | | (I.R.S. Employer Identification No.) |
| | |
4322 South 49thWest Avenue Tulsa, Oklahoma | | 74107 |
| (Address of principal executive offices) | | (Zip Code) |
Registrant’s telephone number, including area code: (918) 592-7900
Securities registered pursuant to Section 12(b) of the Act: None
Securities Registered Pursuant to Section 12(g) of the Act:
Common Stock, par value $.01 per share
and
Preferred Share Purchase Rights
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes¨ Nox
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yesx No¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
| | | | |
| Large accelerated filer ¨ | | Accelerated filer x | | Non-accelerated filer ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes¨ Nox
At June 30, 2005, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was approximately $344,000,000 based on the closing price of such stock on such date of $10.26 per share (assuming solely for this purpose that all of the registrant’s directors, executive officers and 10 percent stockholders are its affiliates).
At March 1, 2006, the number of outstanding shares of the registrant’s common stock was 55,694,877.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the registrant’s definitive proxy statement to be filed with the Securities and Exchange Commission (“SEC”) within 120 days of December 31, 2005 for its 2006 annual meeting of stockholders are incorporated by reference into Part III of this Form 10-K.
TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K includes forward-looking statements as well as historical facts. These forward-looking statements include statements relating to the Syntroleum Process and related technologies including Synfining, gas-to-liquids (“GTL”) and coal-to-liquids (“CTL”) plants based on the Syntroleum Process, including our GTL Mobile Facilities, anticipated costs to design, construct and operate these plants, the timing of commencement and completion of the design and construction of these plants, expected production of ultra-clean diesel fuel, obtaining required financing for these plants and our other activities, the economic construction and operation of GTL or CTL plants, the value and markets for plant products, testing, certification, characteristics and use of plant products, the continued development of the Syntroleum Process (alone or with co-venturers) and the economic production of oil and gas reserves, anticipated capital expenditures, anticipated expense reductions, anticipated cash outflows, anticipated expenses, use of proceeds from our equity offerings, anticipated revenues, availability of catalyst materials, our support of and relationship with our licensees, and any other statements regarding future growth, cash needs, capital availability, operations, business plans and financial results. When used in this document, the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “plan,” “project,” “should” and similar expressions are intended to be among the statements that identify forward-looking statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, these kinds of statements involve risks and uncertainties. Actual results may not be consistent with these forward-looking statements. Important factors that could cause actual results to differ from these forward-looking statements are described under “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K.
As used in this Annual Report on Form 10-K, the terms “Syntroleum,” “we,” “our” or “us” mean Syntroleum Corporation, a Delaware corporation, and its predecessors and subsidiaries, unless the context indicates otherwise.
Our GTL technology can be used for converting natural gas or synthesis gas from coal, into synthetic liquid hydrocarbons. Generally, any reference to GTL is also applicable to CTL unless the context indicates otherwise.
PART I
Overview
We are seeking to develop and employ innovative technology to acquire and cause the production of stranded energy assets in various regions of the world. We are focusing our efforts on:
| | • | | projects that will allow us to use our proprietary processes for converting natural gas, or synthesis gas from coal or other materials, into synthetic liquid hydrocarbons, a process generally known as gas-to-liquids (“GTL”) or coal-to-liquids (“CTL”) technology, utilizing Fischer-Tropsch synthesis; and |
| | • | | projects in which we are directly involved in the field development, production and processing of hydrocarbons, including projects that involve traditional methods of production and processing, projects that may later include the use of our GTL technology and projects that utilize other available technology. |
We seek to form joint ventures for projects and acquire equity interests in these projects. We also license our GTL technologies, which we refer to as the “Syntroleum Process” and the “Synfining Process,” to others. We believe that our use of air in the conversion process provides our technology with a competitive advantage compared to other technologies that use pure oxygen, thereby allowing us to build smaller footprint plants, like our designed barge- or ship-mounted GTL plant (“GTL Mobile Facility”), and avoid the inherent operating risks associated with using pure oxygen.
We are currently investing a significant amount of our resources into our designed GTL Mobile Facility and other potential international or domestic GTL or CTL projects. We believe that these projects offer the greatest potential to meet our objective of generating cash flow and utilizing the advantages of our processes. We also have projects ongoing and at varying stages of development with co-venturers and licensees in various geographical areas, including, Australia, Bolivia, Egypt, Nigeria, Papua New Guinea, Trinidad and the United States. We may obtain funding through joint ventures, license arrangements and other strategic alliances, as well as various other financing arrangements to meet our capital and operating needs for various projects. We are currently exploring alternatives for raising capital to fund the growth of our CTL business, including the development, and demonstration of effectiveness, of our technology with coal-derived synthesis gas. In January 2006, we entered into a memorandum of understanding with Sustec AG (“Sustec”) to form a joint venture to develop projects that will integrate Sustec’s coal gasification technology with our Fischer-Tropsch technology. We expect to incur increases in our costs as we continue to develop and commercialize our projects. Our longer-term survival will depend on our ability to obtain additional revenues or financing.
We are incurring substantial operating and research and development costs with respect to developing and commercializing the Syntroleum Process, our proprietary process of converting natural gas or gasified coal into synthetic liquid hydrocarbons, and the Synfining Process, our proprietary process for refining synthetic liquid hydrocarbons produced by the Syntroleum Process, and do not anticipate recognizing any significant revenues from licensing our technology or from production from either a GTL or CTL plant in which we own an interest in the near future. As a result, we expect to continue to operate at a loss until sufficient revenues are recognized from licensing activities, commercial operation of GTL or CTL plants or non-GTL projects we are developing.
During the past five years, we have been focusing on commercializing the Syntroleum Process and Synfining Process to develop our own GTL and, more recently, CTL projects and we have also pursued more traditional oil and gas development and processing activities. We began business as GTG, Inc. on November 15, 1984. On April 25, 1994, GTG, Inc. changed its name to Syntroleum Corporation. On August 7, 1998, Syntroleum Corporation merged into SLH Corporation. SLH Corporation was the surviving entity in the merger and was renamed Syntroleum Corporation. Syntroleum Corporation was later re-incorporated in Delaware on June 17, 1999 through its merger into a Delaware corporation that was organized on April 23, 1999.
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GTL and CTL Projects
The Syntroleum Process produces synthetic liquid hydrocarbons that are substantially free of contaminants normally found in conventional products made from crude oil. These synthetic liquid hydrocarbons can be further processed into higher margin products through conventional refining processes and our Synfining Process. These products include:
| | • | | Ultra-clean liquid fuels for use in internal combustion engines, jet/turbine engines (subject to certification) and fuel cells; and |
| | • | | Specialty products, such as synthetic lubricants, process oils, high melting point waxes, liquid normal paraffins, drilling fluids, and chemical feedstocks. |
We believe the key advantages of our GTL technology over traditional GTL technologies are (1) the use of air in the conversion process, which is inherently safer than the requirement for pure oxygen in other GTL technologies, and (2) the use of our proprietary catalysts, which we believe will provide operating cost efficiencies through longer operating life than catalysts used in traditional or other GTL technologies. We believe these advantages will reduce capital and operating costs of GTL plants based on our GTL technologies and permit smaller plant sizes, including mobile plants that could be mounted on barges and ocean-going vessels. Based on demonstrated research, including the advancement of our technology from the laboratory to pilot plant and demonstration facility scales, and current market conditions, we believe that our single-train commercial design of 17,000 barrels per day (“b/d”) stand-alone facility can be economically developed. Increased economies of scale can be achieved with incremental trains resulting in throughput levels over 100,000 b/d depending upon the volume amount of oil, condensate, and liquefied petroleum gas or propane (“LPG”) that is produced along with the natural gas. Additionally, we believe that our single-train design could be increased to over 20,000 b/d. We also believe that, subject to our completion of additional engineering to implement improvements we have tested, a GTL or CTL plant smaller than our 17,000 b/d design can be effectively utilized at existing processing facilities. However, the economic application of our GTL technology at any particular plant will depend on the plant operating conditions, including among other things, the then-current market conditions and the volume amount of oil, condensate and liquefied petroleum gas or propane (“LPG”) that is produced along with the natural gas.
We believe the advantages afforded by the Syntroleum Process together with the large worldwide resource base of stranded natural gas provide market opportunities for the use of this technology by us and our licensees in the development of commercial GTL plants. These market opportunities include the application of our technology to natural gas reserves that have not yet been developed due to the limited markets available and those that are currently being flared, vented or re-injected or to coal reserves that are not currently being produced due to environmental concerns or their distance to market. These reserves are typically referred to as “stranded reserves”.
In addition to enabling monetization of stranded natural gas, we expect that our FT technology will be applied to coal. The largest coal reserves are located in the United States, Russia, India, China and Australia. Much of these reserves are difficult and expensive to utilize because of environmental concerns and distance to markets. By applying the Syntroleum Process, integrated with third party gasification and synthesis gas cleanup technology, these underused coal resources could be converted to ultra-clean transportation fuels, thus providing a new source of clean energy and reducing dependence on oil from politically unstable regions. In response to the growing demand for development and application of clean-coal technologies in the United States and availability of stranded coal at prices comparable to stranded natural gas internationally, we are undertaking a comprehensive evaluation of this opportunity.
While we have not yet built a commercial-scale GTL plant based on the Syntroleum Process, we have demonstrated numerous elements and variations of the major catalytic reactions that are part of the Syntroleum Process. These major catalytic reactions include the autothermal reforming of natural gas to Synthesis Gas, or Syngas, and the Fischer-Tropsch synthesis to convert the Syngas into paraffin-like synthetic crude. We have also demonstrated our Synfining Process, which involves the hydro-treating/hydro-cracking of the synthetic crude to produce finished products. We have completed numerous tests and observations on each of these reactions in demonstration plant operations, pilot plant operations and laboratory tests, including:
| | • | | operation of the demonstration plant located at the Tulsa Port of Catoosa (the “Catoosa Demonstration Facility” or “CDF”) since March 2004 as part of the Department of Energy (“DOE”) Ultra-Clean Fuels Production and Demonstration Project ( the “DOE Catoosa Project”) with Marathon Oil Company (“Marathon”) which was completed in 2005; |
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| | • | | operation of the CDF since the completion of the DOE Catoosa Project for the production of additional fuels, extension of our operating experience and for our own research and development purposes; |
| | • | | operation of the Cherry Point Refinery demonstration facility in Blaine, Washington with Atlantic Richfield Company (“ARCO”) for approximately one year; |
| | • | | several years of operations at our Tulsa-based pilot plant under various operating conditions; and |
| | • | | preparation and testing of various concepts and designs in our laboratories. |
These reactions have produced synthetic liquid hydrocarbons in anticipated amounts. For a discussion of our intellectual property rights, see “ – Intellectual Property”.
We currently have a number of licensing agreements with oil companies plus the Commonwealth of Australia and have active projects under development with current licensees Ivanhoe Energy Inc. (“Ivanhoe”) and Marathon. These agreements are described under “ – Licensing Agreements”. In addition, we are pursuing the development of the GTL Mobile Facility and various projects in Australia, Bolivia, Egypt, Nigeria, Papua New Guinea, Trinidad and the United States. We also have strategic relationships with various companies in support of the Syntroleum Process, including AMEC Process and Energy Ltd. and Mustang Engineering, L.P., with which we have entered into agreements allowing access to our confidential engineering systems, technology and information.
Development, Production and Processing Projects
We are pursuing projects in which we intend to participate in the development, production and processing of hydrocarbons. These include projects that involve traditional methods of production and processing, projects that may later include the use of our GTL or CTL technologies and projects that utilize other technologies.
One of the projects we are pursuing is our Oil Mining Lease (“OML”) 113 project offshore Nigeria. The license covers approximately 413,000 acres, and we believe that areas in this lease have the potential to contain a significant amount of oil, condensate, natural gas liquids and natural gas. An appraisal well (“Aje-3”) was drilled in the third quarter of 2005. Test results were evaluated after drilling for consideration of commercial completion. The participants found the economics for commercial completion to be unfavorable and are evaluating further development in accordance with the participation agreement in 2006. If we successfully develop this project, we expect to begin to produce potential oil reserves that we believe may be contained in OML 113 while determining if gas reserves are sufficient to support a GTL facility.
Another project we are pursuing is with Brittania-U Nigeria Limited (“Brittania-U”) to acquire a 40 percent participating interest in the Ajapa field in OML 90 offshore Nigeria. We have entered into a Heads of Agreement, Participation Agreement, Joint Operating Agreement, and Deed of Assignment with Brittania-U regarding this project. Depending on receipt of the appropriate approvals, rig availability and the results of initial drilling, production from the Ajapa Field could commence by the end of 2007 or early 2008. Previously, we have also sought opportunities through natural gas monetization projects with prospects for short-term revenues to provide us with cash flows as we pursue our long lead-time GTL or CTL technologies and projects. These gas monetization projects were located in the United States and included leaseholds, completed wells, related equipment, and a gas processing plant. These operations have been discontinued and the assets have been or are in the process of being sold due to economic factors surrounding the projects and a realignment of all resources with strategic goals of the company.
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Business Strategy
Our objective is to be the leading developer of small and medium sized stranded energy projects utilizing our GTL and CTL technologies and other technology resulting in the ownership of oil, gas and coal reserves and to be a recognized provider of GTL and CTL technology for the energy industry. Our business strategy to achieve this objective involves the following key elements:
Participate in Development Projects.We intend to establish equity participation in projects involving monetization of stranded natural gas and coal assets and associated activities. We are actively pursuing such projects involving natural gas development in Australia, Bolivia, Egypt, Nigeria, Papua New Guinea, Trinidad and the United States. Under this strategy, we will provide our GTL, CTL and related technologies to work with companies that have remote and/or stranded resources that can be economically monetized with our technology through individual site licenses for the specific GTL or CTL plant location. Such projects may involve conventional gas processing and/or GTL activities.
Develop and Own GTL and CTL Plants.We intend to develop projects and own equity interests in joint ventures with our licensees and other energy-industry and financial participants that will develop and own GTL and CTL plants for the production of fuels and specialty products. We are actively pursuing development of GTL and/or CTL plants in several locations, including potential projects in China, Egypt, Malaysia, Nigeria, Papua New Guinea, Trinidad and the United States. We are currently engaged in the study phase with respect to several joint ventures; however, at present no joint venture for the construction of a GTL or CTL plant is in place.
License the Syntroleum Process. Although we are not actively seeking to enter new master, regional or volume licensing agreements, we plan to support our existing licensees in their efforts to develop new GTL plants through both our research and development and our commercial and engineering support activities. Our license agreements obligate us to apprise licensees of upgrades and improvements in the Syntroleum Process and the Synfining Process and to assist in the plant construction process. We believe that our research and development capabilities combined with our demonstration and pilot plant testing facilities provide advantages over competing and alternative technologies. We also believe these advantages enable us to maintain strong relationships with existing licensees and gain project participation opportunities for us.
Expand and Develop Product Markets. We intend to continue developing markets for our synthetic fuels and specialty products in order to promote construction of GTL and CTL plants by us and our licensees, and to establish markets for GTL and CTL products from plants. Based on the results of our already-completed research and development activities, we believe that our technology can provide economic and environmentally superior transportation fuels, including diesel and JP-5/JP-8 jet fuels. These fuels when produced through the Syntroleum Process and Synfining Process are virtually free of sulfur and aromatics and can be transported to the end user through the existing distribution infrastructure. We also believe that availability of these fuels will foster the development and economic application of existing diesel engines, fuel cells and other clean combustion technologies.
The Syntroleum Process
The Syntroleum Process involves two catalytic reactions: (1) conversion of natural gas into synthesis gas in our proprietary flameless autothermal reformer; and (2) conversion of the synthesis gas into hydrocarbons over our proprietary Fischer-Tropsch catalyst. These reactions are expressed in the following equations:
Step 1
Conversion of Natural Gas to Synthesis Gas
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Step 2
Fischer - Tropsch Synthesis
The flameless autothermal reformer in the Syntroleum Process is similar to units used for over 30 years in the ammonia industry. Different generations of our ATR design have operated since November 2003 in our Catoosa Demonstration Facility and have been operating since 1995 as the sole source of synthesis gas for our two b/d pilot plant facility in Tulsa, Oklahoma. An earlier generation of this reformer design was also operated for over 6,500 hours at a 70 b/d demonstration facility with one of our licensees, ARCO, at its Cherry Point refinery in Washington State. The nitrogen in the gas entering the autothermal reformer passes through the reactor essentially unchanged, although very low levels of other nitrogen compounds are produced. These trace contaminants may be removed from the process stream and are not incorporated into the finished products in significant quantities.
Although our proprietary cobalt-based Fischer-Tropsch catalyst was originally developed for use with synthesis gas produced from natural gas, we believe it is capable of functioning with synthesis gas produced from other sources, such as coal or petroleum coke. These feedstocks are converted into synthesis gas using either an air-based or oxygen-based gasifier that is currently available from several third-party technology providers. The ratio of hydrogen to carbon monoxide in the synthesis gas from the gasifier is adjusted using a water gas shift reactor and sulfur and other contaminants are removed. We believe that once this process synthesis gas preparation has been completed, the synthesis gas produced from coal and other sources will react the same as synthesis gas produced in the Syntroleum Process from natural gas.
The Synfining Process
We have also developed refining technology – the Synfining Process – for conversion of the Fischer-Tropsch products into a variety of products including diesel fuels, jet fuels subject to certification, lubricants, and other materials. The high purity and highly paraffinic, or waxy, nature of the Fischer-Tropsch products generally require lower temperature processing conditions than conventional petroleum-derived feedstocks to obtain high yields of the desired products. This refining technology has been used to produce fuels for testing by the DOE in its Ultra-Clean Fuels Program, automobile manufacturers in the United States and Japan as well as by the U.S. Department of Defense (“DOD”) and U.S. Department of Transportation (“DOT”). This refining technology will be utilized in plants we construct and is available for license to our Syntroleum Process licensees and others.
Syntroleum Technology Implementation
The Catoosa Demonstration Facility has produced ultra-clean diesel fuel and jet fuel from natural gas using the Syntroleum Process and the Synfining Process. This is the first plant we have built that incorporates all of our proprietary GTL process technologies on a single site. We completed the DOE Catoosa Project fuel production commitment during 2004. We completed delivery of ultra-clean diesel fuel to other project participants during 2004 and 2005, including the Washington Metropolitan Area Transit Authority and the U.S. National Park Service at Denali National Park in Alaska for testing in bus fleets. We also operated the Catoosa Demonstration Facility during 2005 to support additional fuel testing programs including those of the DOD and the DOT, to demonstrate GTL process technology and catalyst enhancements, and to provide training for our operators.
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Our goal in developing the Syntroleum Process and Synfining Process has been to substantially reduce both the capital and operating costs and the minimum economic size of a GTL or CTL plant. We have developed and continue to develop variations of our basic process design and make enhancements to our proprietary Fischer-Tropsch catalyst in an effort to further lower costs and increase the adaptability of the Syntroleum Process to a wide variety of potential applications. We are working with a number of engineering firms and manufacturers of catalysts with which we have entered into agreements allowing access to our confidential engineering systems, technologies and information.
Although we believe that the Syntroleum Process can be utilized in commercial-scale GTL and CTL plants, there can be no assurance that commercial-scale GTL or CTL plants based on the Syntroleum Process will be successfully constructed and operated or that these plants will yield the same economics and results as those demonstrated in a laboratory, pilot plant or demonstration plant. In addition, improvements to the Syntroleum Process currently under development may not prove to be commercially applicable. See “Item 1A. Risk Factors–Risks Relating to Our Technology.”
Syntroleum Advantage
We believe that the Syntroleum Process and the Synfining Process will be an attractive solution for companies that are unable to economically produce their natural gas or coal reserves using traditional methods. We believe that the Syntroleum Process will enable owners of stranded natural gas or coal reserves to monetize a significant portion of these resources by converting them into synthetic liquid hydrocarbons in the form of ultra-clean fuels, based on our belief that these products can be:
| | • | | produced substantially free of undesirable products normally found in fuels and specialty products made from crude oil; |
| | • | | used as blending stock to upgrade conventional fuels and specialty products made from crude oil; |
| | • | | used unblended in traditional internal combustion engines to reduce emissions; |
| | • | | used in advanced internal combustion engines and fuel-cells that require sulfur-free fuels; and |
| | • | | transported through existing distribution infrastructures for crude oil and refined products. |
Resource Base
Set forth below and elsewhere in this Annual Report on Form 10-K are estimates of identified reserves of oil, natural gas and coal. These estimates do not constitute proved reserves in accordance with the regulations of the SEC. Under SEC regulations, proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Under SEC regulations, proven coal reserves are the reserves for which (a) the quantity is computed from dimensions revealed in outcrops, trenches, workings or drill holes, and the grade and/or quality are computed from the results of detailed sampling, and (b) the sites for inspection, sampling and measurement are spaced so closely and the geologic character is so well defined that size, shape, depth and mineral content of reserves are well-established. We compiled these estimates of identified reserves from the referenced industry publications and other publicly available reports to identify the magnitude of the natural gas and coal resource base. We have not independently verified this information. Accordingly, we cannot provide assurance as to the existence or recoverability of the estimates of identified reserves of oil, natural gas and coal set forth in this Annual Report on Form 10-K. References below and elsewhere in this Annual Report on Form 10-K to the conversion of identified amounts of natural gas and coal into amounts of synthetic crude oil assume that all of the referenced natural gas and coal could be converted at anticipated conversion rates. Actual amounts of synthetic crude oil produced will vary based on the ability of the producer to extract the natural gas and coal, the composition of the natural gas and coal and process conditions selected for the plant, and this variance may be material.
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Natural Gas
The following table presents the 2004 worldwide identified natural gas reserves, consumption and ratio of reserves to consumption (i.e., reserve life) by region:
2004 Worldwide Natural Gas Reserves, Consumption and Reserve Life
| | | | | | |
Region | | Reserves | | Annual
Consumption | | Reserve
Life |
| | | (TCF) | | (TCF) | | (years) |
Central and South America | | 250.6 | | 4.2 | | 54.9 |
Africa and the Middle East | | 3,067.3 | | 10.9 | | 204.9 |
Asia Pacific | | 501.5 | | 12.9 | | 44.0 |
Europe and the Commonwealth of Independent States | | 2,259.7 | | 39.1 | | 61.0 |
North America | | 258.3 | | 27.6 | | 9.7 |
| | | | | | |
Total | | 6,337.4 | | 94.7 | | 67.1 |
Source: Information derived from BP Statistical Review of World Energy 2005.
World natural gas reserves have increased in recent years. Identified gas reserves in 1993 were estimated to be approximately 4,981 trillion cubic feet (“TCF”), according to the BP Statistical Review of World Energy 2005. However, by 2004, natural gas reserves were estimated to be approximately 6,337 TCF. This increase occurred while the demand for natural gas increased 25 percent over the same time period.
A significant amount of stranded gas also exists that is not included in the natural gas reserves indicated above. The term “stranded gas” generally refers to gas existing in reservoirs that have been discovered but no economic market can be found for the natural gas production, or production with associated oil would be too prolific for the limited markets available. Typically this low value gas is managed by either not producing the reservoir, flaring, venting, or re-injecting the natural gas into the geologic formation from which it is produced while producing the oil reserves.
We believe that energy companies with stranded natural gas reserves will be able to cost-effectively use our GTL technology to produce fuels that can be sold in well-developed global markets. As a result, we believe these companies would be able to generate a return on these already discovered reserves, which are currently undeveloped.
Coal
In addition to enabling monetization of stranded natural gas, we expect that our Fischer-Tropsch technology can be applied to coal as well. According to BP Statistical Review of World Energy 2005, identified world coal reserves in 2004 were approximately 909,064 million tons. The largest coal reserves are located in the United States, Russia, China, India and Australia. Much of these reserves are difficult and expensive to utilize because of environmental concerns and distance to traditional power markets. By applying the Syntroleum Process, these underused coal resources could be converted to ultra-clean transportation fuels, thus providing a new source of clean energy and reducing dependence on oil from politically unstable regions.
Market Demand
We believe significant market potential exists for Syntroleum GTL and CTL technologies and products because of steadily increasing demand for transportation fuels, the anticipated increased demand for ultra-clean fuels for both internal combustion engines and fuel cells, and the existing demand for high-quality specialty products—underpinned by the vast amounts of stranded natural gas and coal worldwide.
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We expect demand for products created via Syntroleum technologies to result from the following factors:
The Large Market for Transportation Fuels. According to the Energy Information Administration, diesel fuel demand is estimated to be growing at a faster rate than the total demand for refined products due to superior fuel efficiency of the diesel engine. Based on a study completed by the National Energy Policy Development Group, oil consumption in the United States is expected to increase 32 percent b/d by 2020 primarily due to the growth in consumption of transportation fuels. Based on our belief that the Syntroleum Process can produce ultra-clean transportation fuels, we believe that a portion of the demand growth can be satisfied through our process, although the amount of this demand actually satisfied through our process will depend on the number of products from any commercial plants that are constructed.
Increasing Demand for Ultra-Clean Fuels. Market demand for ultra-clean fuels is increasing due to more stringent environmental standards in most of the world’s industrialized countries and the need for vehicle manufacturers to respond to the challenge of producing fuel-efficient engines that meet these standards. The burden of producing cleaner fuels from conventional crude oil is expected to substantially increase refining costs. We believe these factors will promote the creation of markets for premium, ultra-clean fuels produced by the Syntroleum Process. In addition, we believe that fuels produced by the Syntroleum Process, either alone or blended with conventional fuels, can be used in existing and new generation diesel engines on a cost-effective basis to meet or exceed current and scheduled fuel specifications and emissions standards.
Increasingly Restrictive Environmental Legislation. Key domestic and international environmental regulations and initiatives that affect the demand for ultra-clean fuels include the Clean Air Act of 1970, which establishes specific responsibilities for government and private industry to reduce emissions from vehicles, factories and other pollution sources. In December 1999, the U.S. Environmental Protection Agency (“EPA”) issued rules mandating that sulfur levels in highway diesel fuel be lowered from the then current level of 500 parts per million (“ppm”) to 15 ppm beginning in 2006.
The U.S. government passed the 2005 Energy Policy Act with incentives for innovative technologies, which allowed for the appropriation of funds to carry out research, development, demonstration and commercial application programs in fossil energy. In addition to the appropriations for fossil energy, specific funds will be dedicated to coal and related technologies programs, which will include programs to facilitate production and generation of coal-based power.
The U.S. government also passed the Safe, Accountable, Flexible, and Efficient Transportation Equity Act of 2005, which includes extensive tax incentives for alternative fuels. Alternative fuels include any liquid fuel derived from coal. The alternative fuel credit results in a credit of $0.50 per gallon for use as a motor fuel in a highway vehicle.
The European Union is also making sharp reductions in engine emissions. Sulfur content from the current 350 ppm to below 50 ppm is currently mandated for diesel fuel in 2005. In addition, the Commission of the European Communities requires diesel fuel with a maximum sulfur content of 10 ppm to be made available on a broad geographic basis within each member state of the European Union by January 1, 2005. Member states must also introduce a fuel quality monitoring system and present a fuel quality report. The Commission must publish an annual report on fuel quality and the geographical coverage of fuels with a maximum sulfur content of 10 ppm.
We believe that fuels produced by the Syntroleum Process are positioned to take advantage of the demand for ultra-clean fuels that we expect will develop as a result of these stringent emission standards. This belief is based on the characteristics of fuels produced by the Syntroleum Process, which are substantially free of contaminants – sulfur and aromatics – and demonstrate high operating efficiency. As a result, we believe that fuels produced by the Syntroleum Process, either alone or blended with conventional fuels, can be cost-effectively used to meet scheduled fuel specifications.
Increasing Demand for Fuel Cells. Fuel cells combine hydrogen – which can be derived from natural gas, propane, methanol, gasoline or diesel – with oxygen from the air to produce electric power without combustion. Fuel cell systems have advantages over conventional power systems, which include low or no pollution, higher fuel efficiency, greater flexibility in installation and operation, quiet operation, low vibration and potentially lower maintenance and capital costs. Fuel cells are being developed to support a variety of markets, including transportation and continuous stationary (residential and commercial) power.
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Because fuels produced by the Syntroleum Process are substantially free of contaminants and have greater hydrogen content than other liquid fuels, we believe that fuels produced by the Syntroleum Process have the potential to become preferable fuel cell fuels and to significantly enhance commercial opportunities for many fuel-cell applications. The absence of contaminants from fuels produced by the Syntroleum Process allows for simplified fuel cell processor design, construction and operation. As the storage and processing of the fuel for a fuel cell are simplified, the physical size of fuel-cell components can be reduced. Because fuels produced by the Syntroleum Process have almost twice the hydrogen content per volume of other commonly proposed fuel cell fuels, primarily methane, methanol and liquid hydrogen, they enable greater utility and wider application of fuel-cell power for vehicles. We also believe that fuels produced by the Syntroleum Process have lower toxicity and similar solubility compared to conventional fuels, and can be distributed via existing conventional fuel distribution infrastructure.
The Existing Market for High-Quality Specialty Products. Synthetic crude oil produced by the Syntroleum Process can be further refined into specialty products using conventional refining processes that can be simplified to take advantage of the ultra-clean nature of the synthetic feedstock. We intend to develop and own significant equity interests in GTL and CTL plants designed to produce these specialty products. We believe that specialty products produced by the Syntroleum Process have environmental and performance characteristics that are superior to comparable conventional crude oil products.
Sales and Marketing
We intend to maintain an active marketing and sales effort to promote the Syntroleum Process, working to further develop current projects as well as to look for additional project opportunities. We also intend to continue efforts to establish brand recognition for “Syntroleum” through participation in conferences, press releases, providing fuels for testing with automobile and engine manufacturers, and our work with the DOE, the DOD, DOT and other governmental agencies. “Syntroleum” is a registered trademark and service mark in Argentina, Australia, Bolivia, Chile, the European Union, Japan, Peru and the United States, with an application pending in Brazil.
Licensing Agreements
GTL Licenses.We currently have four types of GTL license agreements. Our master GTL license agreement generally grants to the licensee the non-exclusive right to enter into an unlimited number of site license agreements to construct GTL plants based on the Syntroleum Process to produce fuels worldwide. Our volume GTL license agreement generally grants to the licensee the non-exclusive right to enter into an unlimited number of site license agreements to construct GTL plants based on the Syntroleum Process, subject to specified aggregate production capacity limits. Our regional GTL license agreement generally grants to the licensee the non-exclusive right to enter into an unlimited number of site license agreements to construct GTL plants based on the Syntroleum Process within a designated region. Finally, our site GTL license agreement generally grants to the licensee the non-exclusive right to use the Syntroleum Process in a GTL plant at a single, specified location for the life of the plant. This type of license may be granted under our master, regional or volume license agreements or may be granted to licensees for a specific site who have not otherwise entered into a master, regional or volume license agreement. The licenses may exclude the right to use the Syntroleum Process in areas of the world with which we have intellectual property protection concerns; these areas may vary over time as countries change their laws and enforcement practices.
Under three different licensing programs that include prepaid deposits, a licensee receives pricing terms for future project site licenses and secures (1) the right to use the Syntroleum Process, (2) the right to acquire catalysts from us for which we charge a fixed mark-up over our cost and (3) the right to future improvements in our GTL technology. Current GTL licensees include BP, the Commonwealth of Australia, Ivanhoe, Kerr-McGee Corporation, Marathon, and Repsol-YPF, S.A. We have received an aggregate of $39.5 million in connection with our licensing agreements, which generally begin to expire in 2011.
The following description summarizes the principal terms and conditions of the forms of our GTL license agreements. This summary is not complete and is qualified in its entirety by reference to the form of our master license agreement, a copy of which has been filed as an exhibit to this Annual Report on Form 10-K. Agreements entered into with specific licensees may differ in material respects from the current forms of our various license agreements.
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CTL Licenses. While we have had discussions with potential CTL licensees, we have not executed any CTL license agreements that grant rights to any licensee to construct CTL plants based on the Syntroleum Process. We are focusing our efforts on CTL site licenses where we have the option to participate in the project as well as collect license fees. We will also consider exchanging license fees for equity in CTL projects. The license fees structure for CTL licenses will more than likely be different than GTL licenses and reflect market demand for the technology, as well as consideration for technology development support and options for equity participation by us.
Initial Deposits and GTL License Fees. At the inception of a master, volume or regional GTL license agreement, the licensee is generally required to make an initial deposit to us, which is credited against future site-specific license fees. The amount of the initial deposit depends on market conditions and, in the case of volume and regional GTL license agreements, the volume limitation and the size and location of the region covered. In some cases, we have acquired technologies or commitments to provide funding for future development activities in lieu of initial cash deposits in cases where we viewed these technologies or commitments as being more valuable than the initial cash deposit.
Generally, the amount of the license fee for site licenses under our master, volume and regional GTL license agreements is determined pursuant to a formula based on the discounted present value of the product of (1) the annual maximum design capacity of the plant, (2) an assumed life of the plant and (3) an agreed royalty rate. Our license fees for new plants may change from time to time based on the size of the plant, improvements that reduce plant capital cost and competitive market conditions. Our existing master and volume license agreements allow for the adjustment of fees for new site licenses under certain circumstances. We expect that license fees under existing GTL licensing agreements will be paid in increments when certain milestones during the plant design and construction process are achieved.
Catalyst Sales and Process Design Packages. Our license agreements grant the licensee the right to acquire from us or from vendors designated by us any proprietary catalyst used in either the synthesis gas reaction or the Fischer-Tropsch reaction, in each case at prices based on our costs plus a specified margin. We currently estimate that these catalysts will be required to be replaced every three to five years. Licensees also have the right to acquire proprietary reactors used in the Syntroleum Process from vendors approved by us. In addition, under our license agreements, licensees are required to purchase from us a process design package for plants covered by the license at a fee based on our costs plus a specified margin. We may, however, develop the process design package with the assistance of a third party. We are also required to provide certain technical support to licensees at specified fees.
Other License Terms.As part of our network model for improving our GTL and CTL technologies, we generally acquire a royalty-free, non-exclusive license to any invention or improvement to the Syntroleum Process that is developed by the licensee, together with the right to grant corresponding sublicenses to our other licensees who have granted us similar rights. Licensees also generally acquire the right to use subsequent inventions or improvements to the Syntroleum Process that we acquire from other licensees. Licensees may, but are not required to, develop improvements to the Syntroleum Process and may seek to obtain a patent on the improvements, either independently or jointly with us, and to license those improvements. Our license agreements may be terminated by the licensee, with or without cause, and without penalty, upon 90 days notice to us. For a further discussion of our license agreements and license fees, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Operating Revenues-License Revenues” in Item 7 of this Annual Report on Form 10-K.
Agreement with ExxonMobil.In December 2004, we signed an agreement with ExxonMobil Research and Engineering Company (“ExxonMobil”) whereby we were granted a worldwide license to use ExxonMobil’s patented processes to produce and sell fuels from natural gas or other substances such as coal. In addition, we have the right to extend the terms of this agreement to our licensees. The scope of this agreement includes the fields of syngas production, Fischer-Tropsch synthesis and product upgrading to make fuels and various processes that relate to these areas. It includes all existing ExxonMobil patents (which number over 3,000 worldwide) and future improvement patents in these areas over the next several years. This agreement does not include patents covering certain specific catalyst formulations and manufacturing steps. We have agreed that we will not enforce against ExxonMobil and its affiliates any patents that we obtain after the date of the license agreement, to the extent that those patents overlap with any of ExxonMobil’s patents.
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Projects
We continue to develop several projects that would utilize the Syntroleum Process; however, we can provide no assurance that GTL or CTL plants will be constructed using this technology, that financing will be attained for projects being developed by us and others, that the design and construction of any of these plants will be successfully completed, that any of these plants will be commercially successful, or that these plants will be constructed or utilized on a cost-effective basis. See “Item 1A. Risk Factors.”
Commercial and Licensee Projects
During 2005 and early 2006, we made progress on various projects including the acquisition of interests in OML 113 offshore Nigeria, the acquisition of interests, subject to various government and other approvals, in OML 90 offshore Nigeria, the GTL Mobile Facility, and projects in Papua New Guinea, and the Commonwealth of Independent States. During 2005 and early 2006, we and our licensees had projects in Egypt and Qatar. For a discussion of these projects, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Significant Developments During 2005 and Early 2006” in Item 7 of this Annual Report on Form 10-K.
Demonstration and Scale-Up Projects
Our Demonstration and Scale-Up Projects during 2005 consisted primarily of our Catoosa Demonstration Facility for the DOE Ultra-Clean Fuels Project, including increasing the capacity of a single-train GTL facility, the testing of our new Fischer-Tropsch catalyst and the design, construction and operation of our Modified Reformer Unit. For a discussion of these projects, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Significant Developments During 2005 and Early 2006” in Item 7 of this Annual Report on Form 10-K.
Oil and Gas Properties
In connection with our development, production and processing projects, we have acquired interests in oil and gas properties in the Central Kansas Uplift area, and in OML 113 offshore Nigeria. During the year ended 2005, we drilled on these leases in both properties, with limited production from the Central Kansas Uplift leases and have subsequently discontinued operations and sold leases and assets associated with the Central Kansas Uplift area. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Significant Developments during 2005 and Early 2006” in Item 7 of this Annual Report on Form 10-K for future development plans for these leases. The following information provides drilling activity and acreage data for our oil and gas properties. We had no productive wells as of December 31, 2005. No reserve estimates were provided to any federal authority or agency since the beginning of 2005.
Drilling Activity
During 2005, we drilled nine exploratory gross (nine net) wells and reentered three wells in the Central Kansas Uplift. Nominal production from one of these wells began in the first quarter of 2005. Evaluation of commercial completion and economics was performed and completed on all wells and management made the determination that these properties would be liquidated. We also drilled one exploratory well, Aje-3, on OML 113 offshore Nigeria during 2005. This well was plugged and abandoned. For discussion of this wells and wells that may be drilled in the future, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Significant Developments during 2005 and Early 2006” in Item 7 of this Annual Report on Form 10-K.
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Acreage Data
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of December 31, 2005. Developed acres refer to acreage within producing units and undeveloped acres refer to acreage that has not been placed in producing units. All remaining oil and gas leases in Kansas were sold subsequent to December 31, 2005. These leases were acquired during 2004 and generally had three year terms and options to extend for an additional three years. The lease for OML 113 offshore Nigeria expires in 13 years. In general, our leases will continue past their primary terms if oil or natural gas in commercial quantities is being produced from a well on such leases.
| | | | | | | | | | | | |
| | | Developed Acreage | | Undeveloped Acreage | | Total |
| | | Gross | | Net | | Gross | | Net | | Gross | | Net |
Kansas | | 1,800 | | 1,800 | | 58,700 | | 58,700 | | 60,500 | | 60,500 |
Offshore Nigeria | | — | | — | | 412,650 | | 100,580 | | 412,650 | | 100,580 |
| | | | | | | | | | | | |
Total | | 1,800 | | 1,800 | | 471,350 | | 159,280 | | 473,150 | | 161,080 |
| | | | | | | | | | | | |
Research and Development
Our ongoing research and development strategy includes continuing to lower GTL and CTL capital and operating costs and improving the efficiency of the Syntroleum Process. Our expenditures for research and development activities, including pilot plant, engineering and construction and operation of the Catoosa Demonstration Facility, totaled approximately $22.4 million, $22.3 million, and $30.1 million in 2005, 2004, and 2003, respectively. The current 2006 budget for these activities is approximately $24 million, a significant amount of which relates to operations of the Catoosa Demonstration Facility and the Tulsa pilot plant, engineering and design of our GTL Mobile Facility, and ongoing research and development efforts focusing primarily on commercialization of the technology we previously have developed.
Our research and development facilities include the following locations:
| | • | | Catoosa Demonstration Facility - This facility houses a 70 b/d plant that initially produced products for the DOE and other governmental agencies. This facility has operated since March 2004 to complete our commitment for delivery of fuels to the DOE as well as for research and development and demonstrations for licensees or other customers. |
| | • | | Syntroleum Corporate Office and Technology Center - This facility houses our corporate offices and much of our research and development equipment, including our Synfining Product Upgrading Unit. This unit manufactures finished fuels and specialty products to specifications for testing by our customers and us, which have included the DOD, DOE, and DOT, and a consortium of Japanese automobile manufacturers. This facility is also home to our catalyst development and characterization, products, and gas chromatography laboratories. |
| | • | | Syntroleum Fischer-Tropsch Performance Laboratory - This laboratory houses six fixed bed, four fluid bed and eleven continuously stirred-tank reactors, as well as a particle size analysis instrument and supporting accessories. |
| | • | | Syntroleum Pilot Plant - The plant includes our Advanced Fischer-Tropsch Slurry Reactor Unit, which is utilized in demonstrating process performance and conducting parametric studies requested by clients and engineering contractors involved in developing commercial GTL plants. In support of the Advanced Reactor Unit, we have a syngas generation process (ATR), steam generation facilities, and a Fischer-Tropsch laboratory located at this facility that includes three continuous stirred tank reactors. |
Intellectual Property
Our success depends on our ability to obtain, protect, and enforce our intellectual property rights, to successfully avoid infringing the valid and enforceable intellectual property rights of others and, if necessary, to defend against any alleged infringements. We regard the protection of our proprietary technologies as critical to our future success and we rely on a combination of patent, copyright, trademark and trade secret law and contractual restrictions to protect our proprietary rights. We pursue protection of the Syntroleum Process and the Synfining Process primarily through patents and trade secrets. It is our policy to seek, when appropriate, protection for our proprietary products and processes by filing patent applications in the United States and selected foreign countries and to encourage or further the efforts of others who have licensed technology to us to file patent applications. Our
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ability to protect and enforce these rights involves complex legal, scientific and factual questions and uncertainties. Our policy is to honor the valid, enforceable intellectual property rights of others. While we have made efforts to avoid any such infringement, commercialization of our GTL and CTL technologies may give rise to claims that the technologies infringe upon the patents or other proprietary rights of others. We have not been notified of any claim that our GTL or CTL technologies infringes on the proprietary rights of any third party. However, we can provide no assurance that third parties will not claim infringement by us with respect to past, present or future GTL or CTL technologies.
We currently own, or have licensed rights to, more than 140 patents or patent applications pending in the United States and various foreign countries that relate to one or more embodiments of Syntroleum technology. Our patents generally begin to expire in 2009 for the initial patents, which were issued in the late 1980s, and in 2017 for most of our patents that have been issued since the late 1990s. These patents are not renewable in the United States, and the cost of renewing our foreign patents is not material. In addition to patent protection, we also rely significantly on trade secrets, know-how and technological advances, which we seek to protect, in part, through confidentiality agreements with our collaborators, licensees, employees and consultants. If these agreements are breached, we might not have adequate remedies for the breach. In addition, our trade secrets and proprietary know-how might otherwise become known or be independently discovered by others.
In December 2004, we signed an agreement with ExxonMobil whereby we were granted a worldwide license to use ExxonMobil’s patented processes to produce and sell fuels from natural gas or other substances such as coal. In addition we have the right to extend the terms of this agreement to our licensees. The scope of this agreement includes the fields of syngas production, Fischer-Tropsch synthesis, product upgrading to make fuels and various processes that relate to these areas. It includes all existing ExxonMobil patents (which number over 3,000 worldwide) and future improvement patents in these areas over the next several years. This agreement does not include patents covering certain specific catalyst formulations and manufacturing steps. We have agreed that we will not enforce against ExxonMobil and its affiliates any patents that we obtain after the date of the license agreement, to the extent that those patents overlap with any of ExxonMobil’s patents.
As part of our intellectual property program, we have reviewed a large amount of Fischer-Tropsch patents and prior art literature. In conjunction with outside patent counsel, our technical staff and management have reviewed thousands of existing patents with respect to our own proprietary position and for patent clearance related to specific projects. Together with licensees, we have spent more than $2.0 million to establish a strong patent position, and we do not believe our technology infringes on the valid enforceable patents of others. As a result of these efforts, we are able to provide easy access to this literature for the entire industry through our website, http://www.fischer-tropsch.org. This growing site now includes over 6,000 patents, 12,650 literature document references, 2,180 government reports, and approximately 225 of the U.S. Technical Oil Mission microfilm reels. Recently, this website has had over 10,000 users and 100,000 hits per month from all parts of the world.
In any potential intellectual property dispute involving us, our licensees could also become the target of litigation. Our license agreements require us to indemnify the licensees against specified losses, including the losses resulting from patent and trade secret infringement claims, subject to a cap of 50 percent of the license fees received. Our indemnification and support obligations could result in substantial expenses and liabilities to us. These expenses or liabilities could have a material adverse effect on our business, operating results and financial condition. See “Item 1A. Risk Factors-Risks Relating to Our Technology.”
Employees
As of March 1, 2006, we had 125 employees, none of which is represented by a labor union. We have experienced no work stoppages and believe that our relations with our employees are excellent.
Government Regulation
We are subject to extensive federal, state and local laws and regulations relating to the protection of the environment, including laws and regulations relating to the release, emission, use, storage, handling, cleanup, transportation and disposal of hazardous materials, as well as to employee health and safety. Additionally, our GTL and CTL plants will be subject to environmental, health and safety laws and regulations of any foreign countries in
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which these plants are located. Any GTL Mobile Facility may also be subject to the international treaties and laws relating to activities on the high seas. Violators of these laws and regulations may be subject to substantial fines, criminal sanctions or third-party lawsuits. We may be required to install costly pollution control equipment or, in some extreme cases, curtail operations to comply with these laws. These laws and regulations may also limit or prohibit activities on lands lying within wilderness areas, wetlands or other protected areas.
Our operations in the United States are also subject to the federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also know as the “Superfund” law, and similar state laws, which can impose joint and several liability for site cleanup, regardless of fault, upon statutory classes of persons, including our company, with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”), include the current and certain past owners and operators of a facility where there has been a release or threat of release of a Hazardous Substance and persons who disposed of or arranged for the disposal of Hazardous Substances found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the PRPs the costs of such action. In the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of Hazardous Substance. We may also be the owner or operator of sites on which Hazardous Substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA. We also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties.
Environmental laws and regulations often require acquisition of a permit or other authorization before activities may be conducted, and compliance with laws, regulations and any requisite permits can increase the costs of designing, installing and operating our GTL and CTL plants. GTL and CTL plants generally will be required to obtain permits under applicable environmental laws of the country in which it is situated, as well as various permits for industrial siting and construction. Emissions from a GTL or CTL plant, primarily from the gas turbine, will contain nitrous oxides and may require the installation of abatement equipment in order to meet applicable permit requirements. Additionally, GTL or CTL plants will be required to adhere to laws applicable to the disposal of byproducts produced, including waste water and spent catalyst.
Operation of our Tulsa-based pilot plant requires two annual permits regarding air emissions and industrial wastewater discharge to a sanitation sewer. We do not expect the costs to renew these permits to be material.
Operation of our Catoosa Demonstration Facility requires the following permits: air emissions; air quality construction; air quality minor operating; industrial wastewater discharge; and storm water general. Each of these permits is renewed annually, with the exception of the storm water general permit, which expires on September 12, 2007. We do not expect the costs to renew these permits to be material.
The following environmental regulations are applicable to the Catoosa Demonstration Facility: Clean Air Act; Clean Water Act; Superfund Amendments and Reauthorization Act; Toxic Substance Control Agency; and Chemical Accident Prevention. We believe we are in substantial compliance with all of these regulations. We currently maintain a risk management plan addressing these regulations. We do not expect the costs associated with this plan to be material.
Although we do not believe that compliance with environmental and health and safety laws in connection with our current operations will have a material adverse effect on us, we cannot predict with certainty the future costs of complying with environmental laws and regulations and containing or remediating contamination. In the future we could incur material liabilities or costs related to environmental matters, and these environmental liabilities or costs (including fines or other sanctions) could have a material adverse effect on our business, operating results and financial condition. We currently carry environmental impairment liability insurance to protect us against these contingencies and may, in the future, seek to obtain additional insurance in connection with our participation in the construction and operation of GTL and CTL plants, if coverage is available at reasonable cost and without unreasonably broad exclusions.
Our subsidiary, Scout Development Corporation (“Scout”), which owned our real estate assets sold in 2003, is subject to several U.S. environmental laws, including the Clean Air Act, CERCLA, the Emergency Planning and Community Right-to-Know Act, the Federal Water Pollution Control Act, the Oil Pollution Act of
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1990, the Resource Conservation and Recovery Act, the Safe Drinking Water Act and the Toxic Substances Control Act. Scout is also subject to U.S. environmental regulations promulgated under these acts, as well as state and local environmental regulations that have their foundation in the foregoing U.S. environmental laws. As is the case with many companies, Scout may face exposure to actual or potential claims and lawsuits involving environmental matters with respect to real estate that it has sold. However, no such claims are presently pending. Scout has not suffered and does not anticipate that it will suffer a material adverse effect as a result of any past action by any governmental agency or other party, or as a result of noncompliance with such environmental laws and regulations.
Operating Hazards
Operations at our GTL and CTL plants will involve a risk of incidents involving personal injury and property damage due to the operation of machinery in close proximity to individuals and the highly flammable nature of natural gas and the materials produced at these plants. Depending on the frequency and severity of personal injury and property damage incidents, such incidents could affect our operating costs, insurability and relationships with customers, employees and regulators. Any significant frequency or severity of these incidents, or the general level of compensation awards, could affect our ability to obtain insurance and could have a material adverse effect on our business, operating results and financial condition.
Available Information
Our website address iswww.syntroleum.com. We make our website content available for information purposes only. It should not be relied upon for investment purposes, nor is it incorporated by reference in this Annual Report on Form 10-K. We make available on this website under “Investor Relations-Financial Information –Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. The SEC also maintains a website atwww.sec.gov that contains reports, proxy statements and other information regarding SEC registrants, including us.
You should carefully consider the risks described below. The risks and uncertainties described below encompass all risks that could affect our company. If any of the following risks actually occur, our business, financial condition or results of operations could be materially and adversely affected. In that case, the trading price of our common stock could decline and you may lose all or part of your investment in us.
Risks Relating to Our Technology
We might not successfully commercialize our technology, and commercial-scale GTL or CTL plants based on the Syntroleum Process may never be successfully constructed or operated.
We do not have significant experience managing the financing, design, construction or operation of commercial-scale GTL or CTL plants, and we may not be successful in doing so. No commercial-scale GTL or CTL plant based on the Syntroleum Process has been constructed to date. A commercial-scale GTL or CTL plant based on the Syntroleum Process may never be successfully built either by us or by our licensees. Success depends on our ability and the ability of our licensees to economically design, construct and operate commercial-scale GTL or CTL plants based on the Syntroleum Process. Successful commercial construction and operation of a GTL or CTL plant based on the Syntroleum Process depends on a variety of factors, many of which are outside our control.
Commercial-scale GTL or CTL plants based on the Syntroleum Process might not produce results necessary for success, including results demonstrated on a laboratory, demonstration and pilot plant basis.
A variety of results necessary for successful operation of the Syntroleum Process could fail to occur at a commercial plant, including reactions successfully tested on a laboratory, demonstration plant and pilot plant basis. Results that could cause commercial-scale GTL or CTL plants to be unsuccessful include:
| | • | | lower reaction activity than that demonstrated in laboratory, pilot plant and demonstration plant operations, which would increase the amount of catalyst or number of reactors required to convert synthesis gas into liquid hydrocarbons and increase capital and operating costs; |
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| | • | | shorter than anticipated catalyst life, which would require more frequent catalyst regeneration, catalyst purchases, or both, thereby increasing operating costs; |
| | • | | excessive production of gaseous light hydrocarbons from the Fischer-Tropsch reaction compared to design conditions, which would lower the anticipated amount of liquid hydrocarbons produced and would lower revenues and margins from plant operations; |
| | • | | inability of the gas turbines or heaters integrated into the Syntroleum Process to burn the low-heating-value tail gas produced by the process, which would result in the need to incorporate other methods to generate horsepower for the compression process that may increase capital and operating costs; |
| | • | | inability of third-party gasification and synthesis gas clean-up technology integrated into the Syntroleum Process to produce quantities of quality synthesis gas adequate for economic operation of a CTL plant; and |
| | • | | higher than anticipated capital and operating costs to design, construct and operate a GTL or CTL plant. |
In addition, these plants could experience mechanical difficulties related or unrelated to elements of the Syntroleum Process.
Many of our competitors have significantly more resources than we do, and GTL and CTL technologies developed by competitors could become more commercially successful than ours or render our technology obsolete.
Development of GTL and CTL technology is highly competitive, and other GTL and CTL technologies could become more commercially successful than ours. The Syntroleum Process is based on chemistry that has been used by several companies in synthetic fuel projects over the past 60 years. Our competitors include major integrated oil companies that have developed or are developing competing GTL and CTL technologies, including BP, ConocoPhillips, ExxonMobil, Sasol (including its participation in a joint venture with Chevron) and Shell. Each of these companies has significantly more financial and other resources than we do to spend for research and development of their technologies and for funding construction and operation of commercial-scale GTL or CTL plants. In addition to using their own GTL technologies in competition with us, these competitors could also offer to license their technology to others. Additionally, several small companies have developed and are continuing to develop competing GTL and CTL technologies. The DOE has also sponsored a number of research programs relating to GTL and CTL technology that could potentially lower the cost of competitive processes.
As our competitors continue to develop GTL and CTL technologies, one or more of our current technologies could become obsolete. Our ability to create and maintain technological advantages is critical to our future success. As new technologies develop, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement new technologies at a substantial cost. We may not be able to successfully develop or expend the financial resources necessary to acquire new technology.
Our ability to protect our intellectual property rights involves complexities and uncertainties and commercialization of the Syntroleum Process could give rise to claims that our technology infringes upon the rights of others.
Our success depends on our ability to protect our intellectual property rights, which involves complex legal, scientific and factual questions and uncertainties. We rely on a combination of patents, copyrights, trademarks, trade secrets and contractual restrictions to protect our proprietary rights. Additional patents may not be granted, and our existing patents might not provide us with commercial benefit or might be infringed upon, invalidated or circumvented by others. In addition, the availability of patents in foreign markets, and the nature of any protection against competition that may be afforded by those patents, are often difficult to predict and vary significantly from country to country. We, our licensors, or our licensees may choose not to seek, or may be unable to obtain, patent protection in a country that could potentially be an important market for our GTL or CTL technology. The
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confidentiality agreements that are designed to protect our trade secrets could be breached, and we might not have adequate remedies for the breach. Additionally, our trade secrets and proprietary know-how might otherwise become known or be independently discovered by others.
Commercialization of the Syntroleum Process may give rise to claims that our technologies infringe upon the patents or proprietary rights of others. We may not become aware of patents or rights that may have applicability in the GTL or CTL industry until after we have made a substantial investment in the development and commercialization of those technologies. Third parties may claim that we have infringed upon past, present or future GTL or CTL technologies. Legal actions could be brought against us, our co-venturers or our licensees claiming damages and seeking an injunction that would prevent us, our co-venturers or our licensees from testing, marketing or commercializing the affected technologies. If an infringement action were successful, in addition to potential liability for damages, our co-venturers, our licensees or we could be required to obtain a license in order to continue to test, market or commercialize the affected technologies. Any required license might not be made available or, if available, might not be available on acceptable terms, and we could be prevented entirely from testing, marketing or commercializing the affected technology. We may have to expend substantial resources in litigation, either in enforcing our patents, defending against the infringement claims of others, or both. Many possible claimants, such as the major energy companies that have or may be developing proprietary GTL or CTL technologies competitive with the Syntroleum Process, have significantly more resources to spend on litigation.
We could have potential indemnification liabilities to licensees relating to the operation of GTL and CTL plants based on the Syntroleum Process or intellectual property disputes.
Our indemnification obligations could result in substantial expenses and liabilities to us if intellectual property rights claims were to be made against us or our licensees, or if GTL or CTL plants based on the Syntroleum Process were to fail to operate as designed. Our license agreements require us to indemnify the licensee, subject to a cap of 50 percent of the license fees we receive, against specified losses relating to, among other things:
| | • | | use of patent rights and technical information relating to the Syntroleum Process; |
| | • | | acts or omissions by us in connection with our preparation of process design packages for plants; and |
| | • | | performance guarantees that we may provide. |
Industry rejection of our technology would make the construction of GTL and CTL plants based on the Syntroleum Process more difficult or impossible and would adversely affect our ability to receive future license fees.
Demand and industry acceptance for our GTL or CTL technology are subject to uncertainty. Failure by the industry to accept our technology would make construction of our GTL or CTL plants more difficult or impossible, adversely affecting our ability to receive future license fees and generate other revenue. If a high profile industry participant were to adopt the Syntroleum Process and fail to achieve success, or if any commercial GTL or CTL plant based on the Syntroleum Process were to fail to achieve success, other industry participants’ perception of the Syntroleum Process could be adversely affected.
If ongoing work to enhance project economics and improvements to the Syntroleum Process is not commercially viable, the design and construction of lower-cost GTL and CTL plants based on the Syntroleum Process could be delayed or prevented.
If improvements to the Syntroleum Process currently under development do not become commercially viable on a timely basis, the total potential market for GTL or CTL plants that could be built by us and our co-venturers and by our licensees could be significantly limited. A number of improvements to the Syntroleum Process are in various stages of development. These improvements will require substantial additional investment, development and testing prior to their commercialization. We might not be successful in developing these improvements and, if developed, they may not be capable of being utilized on a commercial basis.
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Risks Relating to Our Business
We will need to obtain funds from additional financings or other sources for our business activities. If we do not receive these funds, we would need to reduce, delay or eliminate some of our expenditures.
Financing for our projects may not be available when needed or on terms acceptable or favorable to us. In addition, we expect that definitive agreements with equity and debt participants in our capital projects will include conditions to funding, many of which could be outside of our control. If adequate funds are not available, we would be required to delay or eliminate expenditures for these projects and may be required to reduce, delay or eliminate expenditures for research and development and other activities or seek to enter into a business combination transaction with or sell assets to another company. We could also be forced to license to third parties the rights to commercialize additional products or technologies that we would otherwise seek to develop ourselves.
We have expended and will continue to expend substantial funds to continue research and development of our technologies, to market the Syntroleum Process and to design and construct GTL or CTL plants. We intend to finance these plants primarily through non-recourse debt financing at the project level, as well as through equity financing. Additionally, we intend to obtain additional funds through collaborative or other arrangements with co-venturers and debt and equity financing in the capital markets. If we obtain additional funds by issuing equity securities, dilution to stockholders may occur. In addition, preferred stock could be issued in the future without stockholder approval, and the terms of our preferred stock could include dividend, liquidation, conversion, voting and other rights that are more favorable than the rights of the holders of our common stock.
We may not receive revenues from license fees, catalyst sales or sales of specialty products from GTL or CTL plants in which we own an interest. Even if we do receive these revenues, they may not be sufficient for capital expenditures or operations, or may not be received within expected time frames. If we are unable to generate funds from operations, our need to obtain funds through financing activities or asset monetization will be increased.
Construction of GTL or CTL plants based on the Syntroleum Process will be subject to risks of delay and cost overruns.
The construction of GTL or CTL plants based on the Syntroleum Process will be subject to the risks of delay or cost overruns resulting from numerous factors, including the following:
| | • | | shortages of equipment, materials or skilled labor; |
| | • | | unscheduled delays in the delivery of ordered materials and equipment; |
| | • | | engineering problems, including those relating to the commissioning of newly designed equipment; |
| | • | | unanticipated cost increases; and |
| | • | | difficulty in obtaining necessary permits or approvals. |
We have incurred losses and anticipate continued losses.
As of December 31, 2005, we had an accumulated deficit of $283 million. We have not yet achieved profitability and we expect to continue incurring net losses until we recognize sufficient revenues from licensing activities, GTL or CTL plants or other sources. Because we do not have an operating history upon which an evaluation of our prospects can be based, our prospects must be considered in light of the risks, expenses and difficulties frequently encountered by small companies seeking to develop new and rapidly evolving technologies. To address these risks we must, among other things, continue to attract investment capital, respond to competitive
19
factors, continue to attract, retain and motivate qualified personnel and commercialize and continue to upgrade our GTL and CTL technologies. We may not be successful in addressing these risks, and we may not achieve or sustain profitability.
Our anticipated expense levels are based in part on our expectations as to future operating activities and not on historical financial data. We plan to continue funding research and development and project development activities. Capital expenditures will depend on progress we make in developing various projects on which we are currently working. Increased revenues or cash flows may not result from these expenses.
If prices for crude oil, natural gas, coal and other commodities are unfavorable, GTL and CTL plants based on the Syntroleum Process may not be economical.
Because the synthetic crude oil, liquid fuels and specialty products that Syntroleum Process-based GTL and CTL plants are expected to produce will compete in markets with oil and refined petroleum products, and because natural gas, coal or other materials will be used as the feedstock for these plants, an increase in prices relative to prices for oil and refined products, or a decrease in prices for oil and refined products, could adversely affect the operating results of these plants. Higher than anticipated costs for the catalysts and other materials used in these plants could also adversely affect operating results. Prices for natural gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for natural gas, market uncertainty and a variety of additional factors that are beyond our control. Coal prices are also subject to variation due to supply and demand forces beyond our control. Factors that could cause changes in the prices and availability of oil, natural gas, coal and refined products include:
| | • | | level of consumer product demand; |
| | • | | domestic and foreign government regulation; |
| | • | | actions of the Organization of Petroleum Exporting Countries; |
| | • | | political conditions in oil and natural gas producing countries; |
| | • | | supply of foreign crude oil and natural gas; |
| | • | | location of GTL plants relative to natural gas reserves and pipelines; |
| | • | | location of CTL plants relative to coal reserves and transportation systems; |
| | • | | capacities of pipelines; |
| | • | | fluctuations in seasonal demand; |
| | • | | price and availability of alternative fuels; and |
| | • | | overall economic conditions. |
We cannot predict the future markets and prices for oil, natural gas, coal or other materials used in the Syntroleum Process or refined products.
Our belief that the Syntroleum Process can be cost effective for GTL plants with capacities from 17,000 to over 100,000 b/d depending upon the amount of oil, condensate, and LPG that is produced along with the natural gas assumes prevailing oil prices in the range of at least $25 per barrel. We believe that the Syntroleum Process for CTL can be cost effective assuming prevailing oil prices in the range of $35-40 per barrel, with gasification technology representing approximately 75-80 percent of the capital cost of a CTL plant. However, the markets for oil and natural gas have historically been volatile and are likely to continue to be volatile in the future. Although
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world crude oil prices were approximately $59 per barrel in December 2005, crude oil prices fell for a period of time during 1998 to historically low levels below $10 per barrel and could return to such low levels in the future.
Adverse operating conditions could prevent GTL and CTL plants based on the Syntroleum Process from operating economically.
The economic application of GTL and CTL technologies depends on favorable plant operating conditions. Among operating conditions that impact plant economics are the site location, infrastructure, weather conditions, size of equipment, quality of the natural gas feedstock, type of plant products and whether the natural gas converted by the plant is associated with oil reserves. For example, if a plant were located in an area that requires construction of substantial infrastructure, plant economics would be adversely affected. Additionally, plants that are not designed to produce specialty products or other high margin products, and plants that are not used to convert natural gas that is associated with oil reserves, will be more dependent on favorable natural gas and oil prices than plants designed for those uses.
GTL and CTL plants will depend on the availability of natural gas or coal at economic prices, and alternative uses of natural gas or coal could be preferred in many circumstances.
Construction and operation of GTL plants will depend on availability of natural gas at economic prices. The market for natural gas is highly competitive in many areas of the world and, in many circumstances, the sale of natural gas for use as a feedstock in a GTL plant will not be the highest value market for the owner of the natural gas. Cryogenic conversion of natural gas to liquefied natural gas may compete with our GTL plants for use of natural gas as feedstocks in many locations. Local commercial, residential and industrial consumer markets, power generation, ammonia, methanol and petrochemicals are also alternative markets for natural gas. Unlike us, many of our competitors also produce or have access to large volumes of natural gas, which may be used in connection with their GTL operations. The availability of natural gas at economic prices for use as a feedstock for GTL plants may also depend on the production costs for the gas and whether natural gas pipelines are located in the areas where these plants are located. New pipelines may be built or existing pipelines may be expanded into areas where GTL plants are built, and this may affect operating margins of these plants as other markets compete for available natural gas.
Construction and operation of CTL plants will depend on the availability of coal or other carbon-based materials such as pet-coke or vacuum resin at economic prices. The cost of coal varies depending upon the energy value per ton of different types of coal and the type of mining operations. The markets for these feedstocks are highly dependent upon the source, location and availability of transportation systems that are generally tied to the power generation sector. Higher coal prices are generally found closer to major population centers where power plants may have a competitive advantage in converting coal to power for transmission in the local region.
Our receipt of license fees depends on substantial efforts by our licensees, and our licensees could choose not to construct a GTL or CTL plant based on the Syntroleum Process or to pursue alternative GTL or CTL technologies.
Our licensees will determine whether we issue any plant site licenses to them and, as a result, whether we receive any additional license fees under our license agreements. To date, no licensee of the Syntroleum Process has exercised its right to obtain a site license. Under most circumstances, a licensee will need to undertake substantial activities and investments before we issue any plant site licenses and receive license fees. These activities may include performing feasibility studies, obtaining regulatory approvals and permits, obtaining preliminary cost estimates and final design and engineering for the plant, obtaining a sufficient dedicated supply of natural gas, obtaining adequate commitments for the purchase of the plant’s products and obtaining financing for construction of the plant. A licensee will control the amount and timing of resources devoted to these activities. Whether licensees are willing to expend the resources necessary to construct GTL or CTL plants will depend on a variety of factors outside our control, including the prevailing view of price outlook for crude oil, natural gas, coal and refined products. In addition, our license agreements may be terminated by the licensee, with or without cause and without penalty, upon 90 days’ notice to us. If we do not receive payments under our license agreements, we may not have sufficient resources to implement our business strategy. Our licensees are not restricted from pursuing alternative GTL or CTL technologies on their own or in collaboration with others, including our competitors.
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Our success depends on the performance of our executive officers, the loss of whom would disrupt our business operations.
We depend to a large extent on the performance of our executive officers, including Kenneth L. Agee, our founder, Chairman of the Board and inventor with respect to many of our patents and patent applications, and John B. Holmes, Jr., our President and Chief Executive Officer. Given the technological nature of our business, we also depend on our scientific and technical personnel. Our efforts to develop and commercialize our technology have placed a significant strain on our scientific and technical personnel, as well as our operational and administrative resources. Our ability to implement our business strategy may be constrained and the timing of implementation may be impacted if we are unable to attract and retain sufficient personnel. At March 1, 2006, we had 125 full-time employees. Except for a $500,000 life insurance policy that we hold on the life of Kenneth L. Agee, we do not maintain “key person” life insurance policies on any of our employees. We have entered into employment agreements with several key employees.
We depend on strategic relationships with manufacturing and engineering companies. If these companies fail to provide necessary components or services, this could negatively impact our business.
We intend to, and believe our licensees will, utilize third-party component manufacturers in the design and construction of GTL and CTL plants based on the Syntroleum Process. If any third-party manufacturer is unable to acquire raw materials or provide components of GTL or CTL plants based on the Syntroleum Process in commercial quantities in a timely manner and within specifications, we or our licensees could experience material delays or construction or development plans could be canceled while alternative suppliers or manufacturers are identified. We have no experience in manufacturing and do not have any manufacturing facilities. Consequently, we will depend on third parties to manufacture components for GTL and CTL plants based on the Syntroleum Process. We have conducted development activities with third parties for our proprietary catalysts and other equipment, including turbines that may be used in the Syntroleum Process, and other manufacturing companies may not have the same expertise as these companies.
We also intend to utilize third parties to provide engineering services in connection with our efforts to commercialize the Syntroleum Process. If these engineering firms are unable to provide requisite services or performance guarantees, we or our licensees could experience material delays or construction plans could be canceled while alternative engineering firms are identified and become familiar with the Syntroleum Process. We have limited experience in providing engineering services and have a limited engineering staff. Consequently, we will depend on third parties to provide necessary engineering services, and these firms may be asked by licensees or financial participants in plants to provide performance guarantees in connection with the design and construction of GTL or CTL plants based on the Syntroleum Process.
Our operating results may be volatile due to a variety of factors and are not a meaningful indicator of future performance.
We expect to experience significant fluctuations in future annual and quarterly operating results because of the unpredictability of many factors that impact our business. These factors include:
| | • | | timing of any construction by us or our licensees of GTL and CTL plants; |
| | • | | demand for licenses of the Syntroleum Process and receipt and revenue recognition of license fees; |
| | • | | timing and productivity of oil and gas wells; |
| | • | | timing and amount of research and development expenditures; |
| | • | | demand for synthetic fuels and specialty products; |
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| | • | | introduction or enhancement of GTL or CTL technologies by us and our competitors; |
| | • | | availability of insurance; |
| | • | | market acceptance of new technologies; and |
| | • | | general economic conditions. |
As a result, we believe that period-to-period comparisons of our results of operations are not meaningful and should not be relied upon as any indication of future performance. Due to all of the foregoing factors, it may be that in some future year or quarter our operating results will be below the expectations of public market analysts and investors. In that event, the price of our common stock would likely be materially adversely affected.
We are subject to extensive laws relating to the protection of the environment, and these laws may increase the cost of designing, constructing and operating our GTL and CTL plants.
If we violate any of the laws and regulations relating to the protection of the environment, we may be subject to substantial fines, criminal sanctions or third party lawsuits and may be required to install costly pollution control equipment or, in some extreme cases, curtail operations. Our GTL or CTL plants will generally be required to obtain permits under applicable environmental laws and various permits for industrial siting and construction. Compliance with environmental laws and regulations, as well as with any requisite environmental or construction permits, may increase the costs of designing, constructing and operating our GTL or CTL plants. We may also face exposure to actual or potential claims and lawsuits involving environmental matters with respect to our previously owned real estate.
Terrorist threats and U.S. military actions could result in a material adverse effect on our business.
Subsequent to the September 11, 2001 terrorist attacks on the World Trade Center and the Pentagon, the United States commenced military actions in response to these attacks. On March 19, 2003, the United States and a coalition of other countries initiated military action in Iraq for the stated purpose of removing that country’s government and destroying its ability to use or produce weapons of mass destruction. Further acts of terrorism in the United States or elsewhere could occur. In addition, recent world political events have resulted in increasing tension involving Iran, North Korea and Syria. These developments and similar future events may cause instability in the world’s financial and insurance markets and could significantly increase political and economic instability in the geographic areas in which we may wish to operate. These developments could also lead to increased volatility in prices for crude oil and natural gas. In addition, these developments could adversely affect our ability to access capital and to successfully implement projects currently under development.
Following the terrorist attacks on September 11, 2001, insurance underwriters increased insurance premiums charged for many coverages and issued general notices of cancellations to their customers for war risk, terrorism and political risk insurance with respect to a variety of insurance coverages. Insurance premiums could be increased further or coverages may be unavailable in the future.
United States government regulations effectively preclude us from actively engaging in business activities in certain countries. These regulations could be amended to cover countries where we may wish to operate in the future. These developments could subject the operations of our company to increased risks and, depending on their magnitude, could have a material adverse effect on our business.
Sufficient markets for the synthetic products of the Syntroleum Process or products that utilize these synthetic products, including fuel cells, may never develop or may take longer to develop than we anticipate.
Sufficient markets may never develop for the synthetic products of the Syntroleum Process, or may develop more slowly than we anticipate. The development of sufficient markets for the synthetic products of the Syntroleum Process may be affected by many factors, some of which are out of our control, including:
| | • | | cost competitiveness of the synthetic products of the Syntroleum Process; |
| | • | | consumer reluctance to try a new product; |
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| | • | | environmental, safety and regulatory requirements; and |
| | • | | emergence of more competitive products. |
In addition, a new market may fail to develop for products that utilize our synthetic products. For example, the establishment of a market for the use of these products as fuel for fuel cells is uncertain, in part because fuel cells represent an emerging market and we do not know if distributors will want to sell them or if end-users will want to use them.
If sufficient markets fail to develop or develop more slowly than we anticipate, we may be unable to recover the losses we will have incurred in the development of our technology and may never achieve profitability.
We may not be successful in acquiring interests in oil and natural gas properties.
The successful acquisition of oil and natural gas properties requires an assessment of recoverable reserves, future oil and natural gas prices, capital and operating costs, potential environmental and other liabilities and other factors. Such assessments, even when performed by experienced personnel, are necessarily inexact and uncertain. Our review of subject properties will not reveal all existing or potential problems, deficiencies and capabilities. We may not always perform inspections on every well, and may not be able to observe structural and environmental problems even when we undertake an inspection. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of these problems. Because we do not have a database of acquired properties and other resources used in acquiring interests in oil and gas properties, we may not be as well positioned as many of our competitors to successfully acquire interests in properties.
Natural gas and oil drilling is a speculative activity and involves numerous risks and substantial and uncertain costs that could adversely affect us.
Drilling for natural gas and oil involves numerous risks, including the risk that no commercially productive natural gas or oil reservoirs will be discovered. The cost of drilling, completing and operating wells is substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including:
| | • | | unexpected or adverse drilling conditions; |
| | • | | elevated pressure or irregularities in geologic formations; |
| | • | | equipment failures or accidents; |
| | • | | adverse weather conditions; |
| | • | | compliance with governmental requirements; and |
| | • | | shortages or delays in the availability of drilling rigs, crews and equipment. |
Even if drilled, our completed wells may not produce reserves of natural gas or oil that are economically viable or that meet our earlier estimates of economically recoverable reserves. Our overall drilling success rate or our drilling success rate for activity within a particular project area may decline. Unsuccessful drilling activities could result in a significant decline in our production and revenues and materially harm our operations and financial condition by reducing our available cash and resources. Because of the risks and uncertainties of our business, our future performance in exploration and drilling may not be comparable to our historical performance described in this Annual Report on Form 10-K.
We are subject to various operating and other casualty risks that could result in liability exposure or the loss of production and revenues.
The natural gas and oil business involves operating hazards such as:
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| | • | | uncontrollable flows of oil, natural gas or well fluids; |
| | • | | geologic formations with abnormal pressures; |
| | • | | pipeline ruptures or spills; |
| | • | | releases of toxic gases; and |
| | • | | other environmental hazards and risks. |
Any of these hazards and risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties and the property of others.
We may not have enough insurance to cover all of the risks we face.
In accordance with customary industry practices, we maintain insurance coverage against some, but not all, potential losses in order to protect against the risks we face. We do not carry a significant amount of business interruption insurance. We may elect not to carry insurance if our management believes that the cost of available insurance is excessive relative to the risks presented. In addition, we cannot insure fully against pollution and environmental risks. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.
| Item 1B. | Unresolved Staff Comments |
None.
We own and operate a nominal two b/d pilot plant located on approximately three acres leased in Tulsa, Oklahoma. This lease expires in May 2022, and annual lease payments total approximately $9,000. We also lease 4,500 square feet of laboratory space, which expires in June 2006 and has lease payments of approximately $42,000 per year. We expect to be able renew this under similar terms. We own a 24,000 square-foot corporate office and technology center located on approximately 25 acres in Tulsa. We also lease office space in Houston, Texas, under a lease that expires in November 2007 and provides for payments of approximately $74,000 per year.
We lease approximately 10 acres of land at the Port of Catoosa near Tulsa, on which we have constructed a nominal 70 b/d GTL demonstration plant as part of our clean fuels project with the DOE known as the “DOE Catoosa Project.” We and Marathon have also added additional equipment to the project for work outside of the scope of the DOE project. We refer to the entire project, including the additional equipment, as the “Catoosa Demonstration Facility.” This lease runs through 2011, and the rent expense is $39,000 annually.
Our predecessor, SLH Corporation, owned real estate assets that we have liquidated. These assets were legacy assets of a real estate development business that Lab Holdings had conducted in association with a previously owned life insurance company that was sold in 1990. These real estate assets, which consisted of a 75 percent interest in land in Houston, Texas comprising 221 acres of undeveloped land and 117 residential lots available for sale, known as the “Houston Project” and held by our subsidiary, Scout, were sold in July 2003 to Anthony L. Levinson, our 25 percent partner in the Houston Project, for approximately $3.9 million in proceeds.
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Scout is subject to contingent obligations under leases and other instruments incurred in connection with real estate activities and other operations. See Note 10 to our consolidated financial statements included in Item 8 of this Annual Report on Form 10-K.
In February 2000, we sold our parking garage in Reno, Nevada to Fitzgerald’s Reno, Inc. (“FRI”), a Nevada corporation doing business as Fitzgerald’s Hotel & Casino Reno, for $3.0 million. FRI paid $750,000 in cash and executed a promissory note in the original principal amount of $2.3 million and interest rate of 10 percent per year (based on a twenty-year amortization). The note was payable in monthly installments of principal and interest, with the entire unpaid balance due on February 1, 2010. The note was secured by a deed of trust, assignment of rents and security interest in favor of us on the parking garage. FRI also executed an Assumption and Assignment of Ground Lease dated February 1, 2000, under which FRI agreed to make the lease payments due under the ground lease. FRI’s obligations under the Assumption and Assignment of Ground Lease are secured by the deed of trust, assignment of rents and security interest in the parking garage and the ground lease.
In December 2000, FRI, along with several affiliates, filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court, District of Nevada. Since the date of its bankruptcy petition, FRI has continued to make the monthly payments due on the note and the payment obligations due under the ground lease.
On August 28, 2003, the bankruptcy plan filed by FRI went into effect and FRI agreed to pay us $50,000 to be applied towards the outstanding principal balance of the promissory note. FRI then issued a new note in the amount of $2.1 million, which was the balance outstanding on the original note at that time, under the same terms and conditions as the original promissory note, except that the maturity date was accelerated to August 28, 2006 and the interest rate was reduced to 5 percent with a 16-year amortization. As a result of the restructuring of this note, we recorded an impairment of $267,000. FRI executed an amended and restated deed of trust under the same terms and conditions as the previous deed of trust. FRI is required to continue to make the lease payments due under the ground lease under the same terms as originally agreed in the Assumption and Assignment of Ground Lease dated February 1, 2000.
We will continue to closely monitor the payments made by FRI under the note and the ground lease to ensure that, should a default occur, notice of default will be properly provided. We believe that we will ultimately collect the balance of the note receivable.
In September 2003, we, along with FRI and the ground lessor, were named in a condemnation action by the City of Reno to obtain rights to lower certain railroad tracks presently running alongside the parking garage. We have engaged outside counsel to represent us. In November 2004, we entered into a Declaration of Nonmonetary Status and Agreement Not to Participate with the City of Reno, whereby we are no longer required to participate in the litigation so long as the City does not seek any monetary liability from us. If we are damaged by the condemnation, including any damage to the parking garage against which we are holding the promissory note, we may reenter the litigation to allege and prove damages.
We are not a party to, nor are any of our properties the subject of, any pending legal proceedings that, in the opinion of management, are expected to have a material adverse effect on our consolidated results of operations or financial position.
| Item 4. | Submission of Matters to a Vote of Security Holders |
None.
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Executive Officers of the Registrant
The following table sets forth certain information concerning our executive officers as of March 1, 2006.
| | | | |
Name | | Age | | Position |
Kenneth L. Agee | | 49 | | Chairman of the Board and Chief Technology Officer |
John B. Holmes, Jr. | | 58 | | Chief Executive Officer, President and Director |
Greg G. Jenkins | | 48 | | Executive Vice President of Finance and Business Development and Chief Financial Officer |
Jeffrey M. Bigger | | 52 | | Senior Vice President of Business Development |
Carla S. Covey | | 33 | | Senior Vice President of Finance and Chief Accounting Officer |
Richard L. Edmonson | | 54 | | Senior Vice President, General Counsel and Corporate Secretary |
Kenneth R. Roberts | | 54 | | Senior Vice President of Business Development |
Edward G. Roth | | 48 | �� | Senior Vice President and Chief Engineer |
Ronald E. Stinebaugh | | 41 | | Senior Vice President of Finance & Acquisitions |
Larry J. Weick | | 57 | | Senior Vice President of Business Development |
Kenneth L. Agee is Chairman of the Board and Chief Technology Officer. Mr. Agee founded our company in 1984 and initially served as President and a director. He served as Chief Executive Officer from February 1996 until January 2005. He became Chairman of the Board in November 1995. He also served as President from June 2002 to September 2002. He became the Chief Technology Officer in April 2005. He is a graduate of Oklahoma State University with a degree in Chemical Engineering. He has over 23 years of experience in the energy industry and is listed as Inventor on several U.S. and foreign patents, with several more patent applications pending, all of which he has assigned to us.
John B. (Jack) Holmes, Jr. is President, Chief Executive Officer and a Director. Mr. Holmes has been President and Chief Executive Officer since January 3, 2005. From October 2002 until January 2005, Mr. Holmes was President and Chief Operating Officer. Mr. Holmes became a director upon joining Syntroleum in October 2002. Prior to joining Syntroleum, Mr. Holmes was Chief Operating Officer of El Paso Merchant Energy Company beginning in January 2001, where he had operating responsibility for all assets, including power generation, refining and chemical terminals and marine assets throughout the U.S. and overseas. Before becoming the Chief Operating Officer of El Paso, Mr. Holmes was the President of Oil and Gas Operations from 1999 to 2001. Prior to joining El Paso in 1999, he was President and Chief Operating Officer of Zilkha Energy Company from 1986 to 1998 and, upon its merger with Sonat, Inc. in 1998, he served as President and Chief Executive Officer of Sonat Exploration until 1999. He holds a B.S. in Chemical Engineering from the University of Mississippi.
Greg G. Jenkinsis Executive Vice President of Finance and Business Development and Chief Financial Officer. Prior to joining Syntroleum in January 2005, Mr. Jenkins served in several executive roles at the El Paso Corporation from December 1996 to June 2003, including: President, El Paso Merchant Energy from December 1996 to August 2000; President, El Paso Global Networks from August 2000 to December 2001; and President, Global Petroleum and LNG from January 2002 to June 2003. From June 2003 to January 2005, Mr. Jenkins was a private investor. Previously, he was President of Entergy Power from May 1996 to December 1996, President and CEO of Hadson Corporation from 1993 to 1996, and served in various senior management positions at Santa Fe Energy Company between 1982 and 1993. He holds a B.A. in Business Management and Economics from Western State College.
Jeffrey M. Bigger is Senior Vice President of Business Development. Previously Mr. Bigger served as Senior Vice President and Chief Technology Officer from April 2003 until April 2005. Mr. Bigger joined Syntroleum in October 2000 as Business Development Manager and became Vice President of Engineering in September 2002. He has 23 years of experience in management of research, engineering, design and optimization of oil, gas and chemical production facilities. Prior to joining our company, he was ARCO’s gas-to-liquids technology manager from 1994 to 2000, responsible for that company’s GTL program, including research, engineering, pilot plant and commercialization efforts. Mr. Bigger holds a B.S. in Chemical Engineering from Illinois Institute of Technology.
Carla S. Covey is Senior Vice President of Finance and Chief Accounting Officer. Ms. Covey became Director of Accounting in June 1997. She had been Controller since January 1999 and Vice President of Finance since September 2002 and was promoted to Senior Vice President of Finance and Chief Accounting Officer in March 2005. Prior to joining Syntroleum, she served as Accounting Manager/Human Resource Manager and Manager, Facility Operations for AGC Manufacturing Services, Inc., a global energy company in Tulsa, Oklahoma, from 1995 to 1997. Ms. Covey
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received her B.A. degree in Business Administration from Drury University and her M.S. degree in Management from Southern Nazarene University. She has also completed the Harvard Business School’s Executive Management Program in Finance and is a certified public accountant.
Richard L. Edmonsonis Senior Vice President, General Counsel and Corporate Secretary. Mr. Edmonson became our Vice President, General Counsel and Corporate Secretary in August 2003 and was promoted to Senior Vice President in July 2004. Prior to assuming that position, he served as a contract attorney for us since April 2003. Prior to joining Syntroleum, Mr. Edmonson spent 26 years in the energy industry in various legal and management positions, including seven years as a Senior Vice President of various subsidiaries of Pennzoil Company until January 1999. From January 1999 to August 1999, he was a senior vice president of PennzEnergy Company. From August 1999 to July 2000, Mr. Edmonson was in private practice. In July 2000, Mr. Edmonson joined EEX Corporation as Senior Vice President, General Counsel and Corporate Secretary where he remained until the sale of that company in November 2002. From December 2002 to April 2003, Mr. Edmonson was in private practice. Mr. Edmonson received his B.A. degree from Oklahoma State University and his juris doctor degree from the University of Texas School of Law.
Kenneth R. Roberts is Senior Vice President of Business Development. Mr. Roberts joined Syntroleum in July 1997 as Business Development Manager and was promoted to Vice President of Finance, Planning and Administration and Chief Financial Officer in September 2002. Mr. Roberts served as Senior Vice President of Licensing and Business Development from April 2003 until January 2005, and Senior Vice President of Planning and Strategic Ventures until June 2005 when he assumed his current position. He has over 25 years of petroleum industry experience. Prior to joining Syntroleum, he served as Chief Financial Officer for the Caspian Pipeline Consortium in Moscow and Senior Project Finance Consultant for Oman Oil Company’s India refinery project development team in Houston. Earlier he served 12 years with ARCO Oil and Gas Company, where he held various management positions in financial/strategic planning and investment analysis activities. He holds B.S. and M.B.A. degrees from the University of Texas at Austin.
Edward G. (Gary) Roth is Senior Vice President and Chief Engineer. Previously Mr. Roth served as Senior Vice President of Projects from July 2004 to April 2005. Prior to joining Syntroleum in July 2004, Mr. Roth served from December 1997 to July 2004 with Petrofac Resources International in varying positions, and in July 2003 was appointed President and Chief Operating Officer of Petrofac LLC, a company involved in all facets of turnkey engineering, procurement and construction in refining and gas processing. From February 1994 to December 1997, Mr. Roth was Vice President of Engineering & Operations at Zilkha Energy. From December 1979 to February 1994, he worked at ARCO in various capacities, including drilling production operations and business development both domestically and internationally. Mr. Roth has a B.S. in Petroleum Engineering from Texas A&M University and a M.B.A. in Finance from the University of Chicago.
Ronald E. Stinebaughis Senior Vice President of Finance & Acquisitions. He joined our company in February 2003 and served as Director of Corporate Finance & Acquisitions. In April 2003, he was promoted to Vice President of Corporate Finance and Acquisitions and served in that position until January 2005, when he assumed his current position. He has 12 years of investment banking-related experience, primarily focused on the energy industry. Prior to joining Syntroleum, Mr. Stinebaugh held the position of Director, Investment Banking for The Integrated Energy Group at ABN AMRO Incorporated from August 2000 to March 2002 and Vice President, Investment Banking, Energy Group at Prudential Securities in Houston from February 1997 to August 2000. Mr. Stinebaugh was an independent consultant between March 2002 and joining Syntroleum in February 2003. He also held investment banking-related positions with Trivest, Inc., a private equity firm, NationsBanc Capital Markets, Inc. and Kidder, Peabody & Co., Incorporated. Mr. Stinebaugh holds a B.A. from Rice University and an M.B.A. from Harvard Business School.
Larry J. Weick is Senior Vice President of Business Development. Mr. Weick joined Syntroleum as Vice President of Licensing and Business Development in 1996 and was Senior Vice President and Chief Financial Officer from April 2003 until January 2005, when he assumed his current position. Prior to joining Syntroleum, from 1971 to 1982, he held positions in engineering, planning and project development in the natural gas and electric utility industry. From 1982 to 1994, he held finance, planning and business development positions with ARCO. From 1994 to 1996, he served as a consultant to Syntroleum. Mr. Weick holds a B.S. in Electrical Engineering from the University of Nebraska at Lincoln and an M.S. in Engineering-Economics from Stanford University.
There are no family relations, of first cousin or closer, among our executive officers, by blood, marriage or adoption.
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Part II
| Item 5. | Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |
Stock Prices. Our common stock is traded on the National Market System of the Nasdaq Stock Market under the symbol “SYNM.” The table below reflects the high and low sales prices for our common stock for each quarter during 2005 and 2004.
| | | | | | |
| | | Sales Price |
| | | High | | Low |
Year Ended December 31, 2005: | | | | | | |
First Quarter | | $ | 12.47 | | $ | 7.71 |
Second Quarter | | $ | 14.45 | | $ | 7.41 |
Third Quarter | | $ | 16.50 | | $ | 9.81 |
Fourth Quarter | | $ | 12.32 | | $ | 6.54 |
Year Ended December 31, 2004: | | | | | | |
First Quarter | | $ | 8.23 | | $ | 4.25 |
Second Quarter | | $ | 7.35 | | $ | 5.51 |
Third Quarter | | $ | 7.28 | | $ | 4.80 |
Fourth Quarter | | $ | 8.17 | | $ | 6.52 |
Record Holders. As of March 1, 2006, we had approximately 1,267 record holders of our common stock (including brokerage firms and other nominees).
Dividends. Cash dividends have not been paid since our inception. We currently intend to retain any earnings for the future operation and development of our business and do not currently anticipate paying any dividends in the foreseeable future. Any future determination as to dividend policy will be made, subject to Delaware law, at the discretion of our board of directors and will depend on a number of factors, including our future earnings, capital requirements, financial condition, business prospects and other factors that our board of directors may deem relevant. Although we are not currently a party to any agreement that restricts dividend payments, future dividends may be restricted by our then-existing financing arrangements. See “ Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” in Item 7 of this Annual Report on Form 10-K.
Our stock price may continue to be volatile and could decline in the future.Historically, the market price of our common stock has been very volatile. The trading price of our common stock is expected to continue to be subject to substantial volatility in response to numerous factors, including publicity regarding actual or potential results with respect to development of the Syntroleum Process and design, construction and commercial operation of plants using our process, announcements of technological innovations by others with competing GTL processes, developments concerning intellectual property rights, including claims of infringement, annual and quarterly variances in operating results, changes in energy prices, competition, changes in financial estimates by securities analysts, any differences in actual results and results expected by investors and analysts, investor perception of our favorable or unfavorable prospects and other events or factors. In addition, the stock market has experienced and continues to experience significant price and volume volatility that has affected the market price of equity securities of many companies. This volatility has often been unrelated to the operating performance of those companies. These broad market fluctuations may adversely affect the market price of our common stock. We are required to maintain standards for listing of our common stock on the National Market System of the Nasdaq Stock Market, and we cannot assure you that we will be able to do so. There is no guarantee that an active public market for our common stock will be sustained.
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Future sales of our common stock could adversely affect our stock price.Substantial sales of our common stock in the public market, or the perception by the market that those sales could occur, could lower our stock price or make it difficult for us to raise additional equity capital in the future. These sales could include sales of shares of our common stock by our directors and officers, who beneficially owned approximately 30 percent of the outstanding shares of our common stock as of March 1, 2006. We cannot predict if future sales of our common stock, or the availability of our common stock for sale, will harm the market price for our common stock or our ability to raise capital by offering equity securities.
Equity Compensation Plans
The following table provides information concerning securities authorized for issuance under our equity compensation plans as of December 31, 2005.
Equity Compensation Plan Information
| | | | | | | |
Plan Category | | Number of Securities to
be Issued Upon
Exercise of
Outstanding Options,
Warrants and Rights (a) | | Weighted-average
Exercise Price of
Outstanding Options,
Warrants and Rights (b) | | Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation
Plans (excluding
securities reflected in
column (a)) (c) |
Equity Compensation Plans Approved by Security Holders (1)(2)(3)(4) | | 8,245,120 | | $ | 7.45 | | 4,709,234 |
Equity Compensation Plans Not Approved by Security Holders (4)(5)(6) | | 1,025,198 | | $ | 1.72 | | 1,500,000 |
Total | | 9,270,318 | | $ | 6.82 | | 6,209,234 |
| (1) | Includes the 1993 Stock Option and Incentive Plan, the 1997 Stock Incentive Plan, the 2005 Stock Incentive Plan and the Stock Option Plan for Outside Directors. |
| (2) | Includes 346,253 shares to be issued upon exercise of options with a weighted average exercise price of $12.45 that were granted under our 1993 Stock Option and Incentive Plan and our Stock Option Plan for Outside Directors assumed by us in connection with the merger of Syntroleum Corporation and SLH Corporation on August 7, 1998, which were approved by our stockholders. |
| (3) | Includes up to 1,170,000 shares to be issued upon exercise of warrants granted to Mr. Ziad Ghandour, one of our directors, at exercise prices ranging from $4.50 per share to $5.25 per share, which were approved by our stockholders. An additional 1,000,000 warrants to purchase shares of common stock at an exercise price of $11.21 per share may be issued to Mr. Ghandour upon the achievement of certain performance objectives. These warrants were approved by our stockholders in April 2005. |
| (4) | Includes up to 116,250 shares to be issued upon exercise of warrants issued to Sovereign Oil & Gas Company II, LLC (“Sovereign”), a consulting firm that we have retained to assist us in acquiring stranded natural gas fields worldwide using the Syntroleum Process as a feedstock for our GTL Mobile Facility, which were approved by our stockholders. The warrants are issuable in varying amounts upon the acquisition of properties of the achievement of third-party participation in a project, and have an exercise price of between $6.40 and $11.16 per share for warrants issued since March 1, 2004. The exercise price per share for any additional warrants issued is to be determined based on the price for our common stock on March 1 of the contract year stated in the joint development agreement between us and Sovereign during which the project commences. Under the joint development agreement, we have agreed to issue to Sovereign warrants to purchase up to an aggregate of 2,000,000 shares of our common stock in varying amounts upon |
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| | the acquisition of properties or the achievement of third-party participation in a project. The issuance of warrants to purchase up to 500,000 shares of our common stock has been approved by our stockholders. |
| (5) | On August 31, 2002, we granted options to purchase 1,000,000 shares of our common stock at an exercise price of $1.55 to our President and Chief Executive Officer, John B. Holmes, Jr., as an inducement to his employment with Syntroleum. The rights to exercise the options and purchase 333,334 shares vested on October 1, 2002, the rights to exercise the options and purchase an additional 333,333 shares vested on October 1, 2003, and the rights to exercise the options and purchase an additional 333,333 shares vested on October 1, 2004. The ability to exercise the options will terminate upon the earliest of: (a) the tenth anniversary of the date of the grant; (b) 12 months after the date of the termination of Mr. Holmes’ employment by reason of death or disability; (c) the third annual anniversary of Mr. Holmes’ retirement; or (d) the date 12 months following the date upon which Mr. Holmes’ employment terminates for any reason other than those described in (b) or (c) above. |
| (6) | On June 30, 1997, and on February 3, 1999, we granted options to purchase 17,198 and 8,000 shares of common stock at exercise prices of $9.30 and $6.88, respectively, to a Business Development Consultant. The rights to exercise the options and purchase shares vest in three equal installments each year on the anniversary of each grant. |
We intend to submit a proposal to our shareholders to approve an amendment to the joint development agreement with Sovereign to change the exercise price of warrants issued to the closing per share sale price of our common stock as of December 1 prior to a contract year in which the warrants are issued. This amendment was made because this is the day that we must give notice to Sovereign of continuation or termination of the joint development agreement for the next contract year. This amendment is subject to shareholder approval at our annual meeting in April 2006. For the 2005 and 2006 contract years, the exercise price for all warrants issued, after shareholder approval, is $6.94 and $7.98 per share, respectively. If shareholder approval is not received, all warrants related to projects in the 2005 contract year will have an exercise price of $11.16 per share.
Issuer Repurchases of Equity Securities
Neither we nor anyone acting on our behalf or on behalf of an affiliated purchaser purchased shares of our common stock during the three months ended December 31, 2005.
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| Item 6. | Selected Financial Data |
The following selected financial information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Annual Report on Form 10-K and our consolidated financial statements and the related notes thereto included in Item 8 of this Annual Report on Form 10-K.
| | | | | | | | | | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | | | 2002 | | | 2001 | |
| | | (in thousands, except per share data) | |
Statement of Operations Data: | | | | |
Revenues: | | | | | | | | | | | | | | | | | | | | |
Joint development revenue | | $ | 7,444 | | | $ | 923 | | | $ | 14,183 | | | $ | 9,621 | | | $ | 2,239 | |
Catalyst materials revenue | | | — | | | | 5,674 | | | | 4,966 | | | | — | | | | — | |
Other revenue | | | 464 | | | | 9 | | | | 91 | | | | 25 | | | | — | |
| | | | | | | | | | | | | | | | | | | | |
Total revenue | | | 7,908 | | | | 6,606 | | | | 19,240 | | | | 9,646 | | | | 2,239 | |
| | | | | | | | | | | | | | | | | | | | |
Costs and expenses: | | | | | | | | | | | | | | | | | | | | |
Cost of catalyst materials sales and impairment | | | — | | | | 3,033 | | | | 7,886 | | | | — | | | | — | |
Catoosa Demonstration Facility | | | 10,710 | | | | 12,994 | | | | 21,843 | | | | 12,606 | | | | — | |
Write down of Sweetwater Project | | | — | | | | — | | | | — | | | | 30,855 | | | | — | |
Pilot plant, engineering and research and development | | | 11,734 | | | | 9,260 | | | | 8,135 | | | | 15,558 | | | | 21,908 | |
Depreciation, depletion, amortization and impairment | | | 5,064 | | | | 602 | | | | 639 | | | | 835 | | | | 928 | |
General and administrative and other | | | 23,071 | | | | 21,184 | | | | 15,390 | | | | 16,040 | | | | 16,373 | |
| | | | | | | | | | | | | | | | | | | | |
Total operating expenses | | | 50,579 | | | | 47,073 | | | | 53,893 | | | | 75,894 | | | | 39,209 | |
| | | | | | | | | | | | | | | | | | | | |
Operating income (loss) | | | (42,671 | ) | | | (40,467 | ) | | | (34,653 | ) | | | (66,248 | ) | | | (36,970 | ) |
Investment, interest, other income (expense), foreign currency, taxes and minority interest | | | 5,159 | | | | (1,603 | ) | | | (1,188 | ) | | | 711 | | | | 4,031 | |
Income from discontinued domestic oil and gas business | | | (3,882 | ) | | | (480 | ) | | | — | | | | — | | | | — | |
Income from discontinued real estate business | | | — | | | | — | | | | 1,203 | | | | 357 | | | | 2,639 | |
| | | | | | | | | | | | | | | | | | | | |
Net income (loss) | | $ | (41,394 | ) | | $ | (42,550 | ) | | $ | (34,638 | ) | | $ | (65,180 | ) | | $ | (30,300 | ) |
| | | | | | | | | | | | | | | | | | | | |
Basic and diluted per share amounts - | | | | | | | | | | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | (0.70 | ) | | $ | (0.97 | ) | | $ | (1.04 | ) | | $ | (1.99 | ) | | $ | (0.99 | ) |
Income from discontinued real estate business | | $ | (0.07 | ) | | $ | (0.01 | ) | | $ | 0.04 | | | $ | 0.01 | | | $ | 0.08 | |
Net income (loss) | | $ | (0.77 | ) | | $ | (0.98 | ) | | $ | (1.00 | ) | | $ | (1.98 | ) | | $ | (0.91 | ) |
| |
| | | As of December 31, | |
| | | 2005 | | | 2004 | | | 2003 | | | 2002 | | | 2001 | |
| | | (in thousands) | |
Balance Sheet Data: | | | | | | | | | | | | | | | | | | | | |
Working capital | | $ | 46,095 | | | $ | 22,625 | | | $ | 10,795 | | | $ | 13,626 | | | $ | 42,765 | |
Oil and gas properties and equipment held for sale | | | 1,927 | | | | 4,488 | | | | — | | | | — | | | | — | |
Property and equipment, net | | | 7,473 | | | | 3,245 | | | | 1,985 | | | | 12,673 | | | | 34,049 | |
Total assets | | | 89,795 | | | | 44,751 | | | | 67,235 | | | | 57,140 | | | | 105,512 | |
Long-term debt and deferred credit | | | — | | | | — | | | | 13,546 | | | | 11,261 | | | | 1,190 | |
Convertible debt | | | 25,925 | | | | 24,221 | | | | 21,842 | | | | 4,466 | | | | — | |
Deferred revenue | | | 20,952 | | | | 27,575 | | | | 38,273 | | | | 35,875 | | | | 34,351 | |
Stockholders’ equity (deficit) | | | 32,413 | | | | (13,324 | ) | | | (12,830 | ) | | | (3,990 | ) | | | 62,731 | |
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| Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Overview
We began business as GTG, Inc. on November 15, 1984. On April 25, 1994, GTG, Inc. changed its name to Syntroleum Corporation. On August 7, 1998, Syntroleum Corporation merged into SLH Corporation. SLH Corporation was the surviving entity in the merger and was renamed Syntroleum Corporation. Syntroleum Corporation was later re-incorporated in Delaware on June 17, 1999 through its merger into a Delaware corporation that was organized on April 23, 1999.
We are incurring substantial operating and research and development costs with respect to developing and commercializing the Syntroleum Process and the Synfining Process and do not anticipate recognizing any significant revenues from production from either a GTL or CTL fuel or specialty plant or from licensing our technology in the near future. As a result, we expect to continue to operate at a loss until sufficient revenues are recognized from licensing activities, or commercial operations of GTL and CTL plants or other oil and gas projects we are developing. Generally, any reference to GTL is also applicable to CTL unless the context indicates otherwise.
Operating Revenues
During the periods discussed below, our revenues were primarily generated from reimbursement for research and development activities associated with the Syntroleum Process and catalyst sales. In the future, we expect to receive revenue from sales of products or fees for the use of GTL and CTL plants in which we will own an equity interest, demonstration plant product sales, licensing, catalyst sales, research and development activities carried out with industry participants, and oil and gas projects we are developing.
Until the commencement of commercial operation of GTL or CTL plants in which we own an interest or an oil and gas project we are developing, we expect that cash flow relating to the Syntroleum Process will consist primarily of and revenues associated with joint development activities. We will not receive any cash flow from GTL or CTL plants in which we own an equity interest until the first of these plants is constructed and will not receive additional license fees until we enter into additional license agreements or existing licensees develop commercial plants. Our future operating revenues will depend on the successful commercial construction and operation of GTL or CTL plants based on the Syntroleum Process, the success of competing GTL technologies, the success of our non-GTL projects, and other competing uses for natural gas or coal. We expect our results of operations and cash flows to be affected by changing crude oil, natural gas, fuel and specialty product prices and trends in environmental regulations. If the price of these products increases (decreases), there could be a corresponding increase (decrease) in operating revenues.
GTL Plant Revenues.We intend to develop GTL plants and to retain equity interests in these plants. These plants will enable us to gain experience with the commercial operation of the Syntroleum Process and, if successful, are expected to provide ongoing revenues. Some of the anticipated products of these plants (i.e., synthetic crude oil, Fischer-Tropsch waxes, synthetic diesel and other fuels, naphtha, lube base oils, process oils, drilling fluid and/or liquid normal paraffins) have historically been sold at premium prices and may result in relatively high sales margins. We anticipate forming joint ventures with energy industry and financial participants in order to finance and operate these plants. We anticipate that our GTL plants will include co-venturers who have low-cost gas reserves in strategic locations and/or have distribution networks in place for the synthetic products to be made in each plant as well as engineering, procurement and construction contractors and FPSO operators.
Oil and Gas Sales Revenues. We are pursuing projects in which we are directly involved in oil and gas field development and the processing of natural gas using available gas processing technologies. These include projects in which we only produce oil or natural gas and projects that may later evolve into integrated projects that would involve development, production and processing of hydrocarbons. Revenue from these projects will be recognized based on actual volumes produced and sold to purchasers. Projects we are currently pursuing include the upstream development of OML 113 and OML 90 offshore Nigeria and others. We expect these projects will be pursued by us and with co-venturers through various arrangements. We anticipate receiving revenues from these projects, including sales of oil and gas from properties owned by us or jointly with another party, as well as processing and gathering fees from facilities in which we own an interest.
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License Revenues. We expect to generate revenue earned from licensing the Syntroleum Process through four types of contracts: master license agreements, volume license agreements, regional license agreements and site license agreements. Master, volume and regional license agreements provide the licensee with the right to enter into site license agreements for individual GTL plants. A master license agreement grants broad geographic and volume rights, while volume license agreements limit the total production capacity of all GTL plants constructed under the agreement to specified amounts, and regional license agreements limit the geographical rights of the licensee. Master, volume and regional license agreements signed in the past have required an up-front cash deposit that may offset or partially offset license fees for future plants payable under site licenses. In the past, we have acquired technologies or commitments of funds for joint development activities, services or other consideration in lieu of the initial cash deposit in cases where we believed the technologies or commitments had a greater value.
Our site license agreements currently require fees to be paid in increments when milestones during the plant design and construction process are achieved. The amount of the license fee under our existing master and volume license agreements is currently determined pursuant to a formula based on the present value of the product of: (1) the yearly maximum design capacity of the plant, (2) an assumed life of the plant and (3) an agreed royalty rate. Our licensee fees may change from time to time based on the size of the plant, improvements that reduce plant capital cost and competitive market conditions. Our existing master and volume license agreements allow for the adjustment of fees for new site licenses under certain circumstances.
Our accounting policy is to defer all up-front deposits under master, volume and regional license agreements and license fees under site license agreements and recognize 50 percent of the deposits and fees as revenue in the period in which the engineering process design package (“PDP”) for a plant licensed under the agreement is delivered and recognize the other 50 percent of the deposits and fees when the plant has passed applicable performance tests. The amount of license revenue we earn will be dependent on the construction of plants by licensees, as well as the number of licenses we sell in the future. To date we have received $39.5 million in cash as initial deposits and option fees under our existing license agreements. Except for $2.0 million recorded as revenue in connection with option expirations, $8.8 million of license credits returned by the Commonwealth of Australia as part of the settlement for the Sweetwater project and $10.0 million recorded as revenue as a result of the release of license credits and indemnifications, these amounts have been recorded in deferred revenue. Our obligations under these license agreements are to allow the use of the technology, provide access to engineering services to generate a PDP at an additional cost, and to refund 50 percent of the advances should the licensee build a plant that does not pass all mechanical completion testing. These licenses generally begin to expire in 2011 and the initial deposits will be recognized as licensing revenue as the licenses expire should a licensee not purchase a site license and begin construction of a plant prior to expiration of the license.
Catalyst Revenues. We expect to earn revenue from the sale of our proprietary catalysts to our licensees. Our license agreements currently require our catalyst to be used in the initial loading of the catalyst into the Fischer-Tropsch reactor for the licensee to receive a process guarantee. After the initial fill, the licensee may use other catalyst vendors if appropriate catalysts are available. The price for catalysts purchased from us pursuant to license agreements is equal to our cost plus a specified margin. We will receive revenue from catalyst sales if and when our licensees purchase catalysts. We expect that catalysts will need to be replaced every three to five years. During 2004 and 2003, we marketed a certain amount of the catalyst materials we had on-hand, and we have classified these materials as current assets at their current market price. Revenues and costs of sales related to the sale of these materials are recorded on our statement of operations in the period in which the materials are sold. All of the materials that we were marketing were liquidated as of March 31, 2004.
Joint Development Revenues. We continually conduct research and development activities in order to improve the conversion efficiency and reduce the capital and operating costs of GTL plants based on the Syntroleum Process. We receive joint development revenues primarily through two initiatives: (1) prospect assessment and feasibility studies and (2) formal joint development arrangements with our licensees and others. Through these joint development arrangements, we may receive revenue as reimbursement for specified portions of our research and development or engineering expenses. Under some of these agreements, the joint development participant may receive credits against future license fees for monies expended on joint research and development. During the periods presented, joint development revenues consisted primarily of amounts received from Marathon Oil Company (“Marathon”), the U.S. Department of Energy (“DOE”), the U.S. Department of Defense (“DOD”), VNIIGAZ, Sasol, Ivanhoe and Oil Search Ltd. Currently, Marathon is the only party to receive credits
34
against future license fees as the result of joint development activities. To date, our revenues and costs have been related to certain projects and are wholly dependent upon the nature of our projects. The various sizes and timing of these projects, including the demonstration plant (the “Catoosa Demonstration Facility”) used as part of the DOE Ultra-Clean Fuels Production and Demonstration Project with Marathon affect the comparability of the periods presented.
Demonstration Plant Product Sales Revenues.We expect to provide synthetic ultra-clean diesel fuel, such as our S-2 diesel fuel, and FC-1 naphtha fuels to various customers for their use in further research and testing upon their request. Our ultra-clean S-2 diesel fuel is a paraffinic, high-cetane distillate fuel that is essentially free of sulfur, olefins, metals, aromatics and alcohols. The fuels are produced at our Catoosa Demonstration Facility. Revenues will be recognized upon delivery of the requested fuels.
Operating Expenses
Our operating expenses historically have consisted primarily of the construction and operation of the Catoosa Demonstration Facility, pilot plant, engineering, including third party engineering, research and development expenses and general and administrative expenses, which include costs associated with general corporate overhead, compensation expense, legal and accounting expenses and expenses associated with other related administrative functions.
Our policy is to expense costs associated with the Catoosa Demonstration Facility and pilot plant, engineering and research and development costs as incurred in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 2,Accounting for Research and Development Costs. All of these research and development expenses are associated with our development of the Syntroleum Process. The Catoosa Demonstration Facility expenses include costs to construct, maintain, and operate the facility for further research and development as well as for demonstrations for licensees and other customers. Research and development expenses include costs to operate both our laboratory and technology center, salaries and wages associated with these operations, research and development services performed by universities, consultants and third parties and additional supplies and equipment for these facilities. Our policy is to expense costs associated with the development of GTL plants or other projects until we begin our front-end engineering and design program on the respective projects. We also capitalize any costs associated with a project that would have economic value for future projects. We have incurred costs related specifically to the development of our GTL Mobile Facility project. These costs, which relate primarily to outside contract services for initial engineering, design, and development are included in pilot plant, engineering and research and development costs in our consolidated statements of operations.
We commenced operations at the Catoosa Demonstration Facility in the first quarter of 2004, with production of the initial finished fuels occurring on March 4, 2004. We have produced all of our contractual commitment to the DOE and have delivered all of the required fuels to a fuels testing facility in Detroit, Michigan, Denali National Park in Alaska, the University of Alaska in Fairbanks and the Washington D.C. Area Metropolitan Transit Authority. The plant will continue to operate during 2006, producing fuels, seeking to create new efficiency improvements, increasing our data and extending our operating experience, after which we intend to mothball the plant until such time as additional joint development programs or government fuels production contracts are forthcoming.
We have also recognized depreciation, depletion, amortization, and impairment expense primarily related to oil and gas assets, office and computer equipment, buildings and leasehold improvements and patents. We have incurred significant costs and expenses over the last several years as we have expanded our research and development, engineering and commercial activities, including staffing levels. We expect to incur increases in our operating expenses as we continue to develop and commercialize our GTL Mobile Facility or plant and other projects. Our operating expenses could increase further if we accelerate our development of these or other commercial projects.
If we are successful in developing a GTL or CTL plant in which we own an interest, we expect to incur significant expenses in connection with our share of the engineering design, construction and start-up of the plant. Upon the commencement of commercial operations of a plant, we will incur our share of cost of sales expenses relating primarily to the cost of natural gas or coal feedstocks for the plant and operating expenses relating to the
35
plant, including labor, supplies and maintenance, and product marketing costs. Due to the substantial capital expenditures associated with the construction of GTL or CTL plants, we expect to incur significant depreciation and amortization expense in the future. We also expect to incur expenses related to other gas monetization projects, which could include lease operating costs, gathering and processing fees and other typical costs associated with traditional oil and gas exploration, production and processing.
Discontinued Operations
We were pursuing gas monetization projects in which we were directly involved in gas field development using available gas processing technologies from third parties. We secured the exclusive rights to use two different gas processing technologies from third parties in certain areas in Central Kansas and three counties in the Permian Basin of Texas. The project consisted of acquiring leases of approximately 85,000 acres in the Central Kansas Uplift area, drilling of eight and the re-entry of three wells throughout 2004 and 2005. Limited production from the first well began in January 2005.
We have completed an evaluation of potential reserves related to drilled properties in the United States and decided to discontinue further expenditures in the Central Kansas Uplift area based on management’s decision to focus efforts with company specific goals in line with strategic activities. We recorded depreciation, depletion, amortization and impairment expense of $3,783,000 related to these properties and the associated gas processing plant and equipment during the year ended December 31, 2005. We successfully sold certain leasehold acres during 2005 for $1,000,000. The remaining leasehold acreage, including the wells and equipment, sold for $522,000 in January, 2006. We are actively seeking prospects for sale of our gas processing plant and related equipment and expect to complete the sale in 2006. Net oil and gas properties and equipment classified as held for sale is $1,927,000 for the year ended December 31, 2005.
Significant Developments During 2005 and Early 2006
Commercial and Licensee Projects
OML 113.On August 27, 2004, we entered into a Heads of Agreement with Yinka Folawiyo Petroleum Company Ltd. (“YFP”), pursuant to which we are required to delineate and potentially develop an oil and gas discovery on OML 113 offshore Nigeria. On October 7, 2004 we and YFP entered into a Joint Venture Agreement pursuant to the Heads of Agreement. The license covers approximately 413,000 acres, and our current project development plans include using our GTL Mobile Facility for development of the gas reserves in the field. We and other project participants will bear all capital costs in the project. YFP will bear a share of operating costs after project payout, which is the date on which we achieve the full recovery of all capital, operating and production costs incurred to that date. Based on our review of data tapes from a previously shot 3D seismic survey, we believe that areas in this lease have the potential to contain a significant amount of oil, condensate, natural gas liquids and natural gas. We believe that the oil and condensate in the field further enhances the economics of the project by providing the potential for near term cash flows.
On January 13, 2005, we finalized agreements to begin the delineation of the Aje Field. The agreements are with YFP and the following companies, to which we refer collectively as the “Participants”: Lundin Petroleum, a publicly traded Swedish exploration and production company who will serve as the technical advisor to the project; Challenger Minerals Inc., a subsidiary of GlobalSantaFe Corporation, one of the largest international drilling contractors; Providence Resources PLC, a publicly traded Irish exploration and production company; and Howard Energy Co., Inc. and Palace Exploration Company, both privately owned U.S. exploration and production companies.
The agreements required the Participants to pay 90 percent of the cost to drill and log one delineation well in the Aje Field discovery and one option well in order to earn 67.5 percent of our participating interest in OML 113. Additionally, upon commencement of commercial production, the Participants are required to pay a development bonus to us. Our net revenue interest in the project before payout is 31 percent; after project payout, our net revenue interest is reduced to approximately 25 percent. In addition, we received an overriding royalty interest from all of the interest owners in OML 113 other than YFP.
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On April 14, 2005, we and other participants received approval from the Nigerian government for the assignment of interest in OML 113 offshore Nigeria to us and the Participants. As a result of the approval and the receipt of the drilling permit for the first well, we received a signature bonus of approximately $9,438,000 from the Participants as part of the consideration for joining the Aje Field project. As a result of these agreements, payment to Sovereign in the amount of $3,719,000 was made and warrants to purchase 25,000 shares of our common stock were issued to Sovereign at an exercise price of $6.40 per share under the joint development agreement between us and Sovereign. We recorded a gain in conveyance of interest resulting from this transaction in the amount of $3,556,000 during the year ended December 31, 2005, after elimination of the costs of our Nigerian full cost pool at the time of conveyance.
We secured and drilled the first delineation well, which we refer to as the “Aje-3 well” during the third quarter of 2005. Our total net cost of drilling the delineation well totaled $3,331,000. In October 2005, we reached the reservoir objectives as anticipated and a detailed logging program was acquired and interpreted. The Participants found the economics for commercial completion to be unfavorable. In October 2005, the well was plugged and abandoned. Three wells, including the Aje-3 well, have been drilled on the Aje structure and have proven the existence of an active petroleum system and the presence of a well developed reservoir and seal in the block. As noted above, the Participants agreed to pay promoted costs to drill and log one delineation well in the Aje Field discovery and one option well in order to earn a participating interest in OML 113. The Participants must decide on the drilling of a second well by September 30, 2006. Howard Energy Co., Inc. is no longer a Participant in this project as of December 2005. Their respective interest has been assumed by the remaining Participants. We expect to incur additional expenditures relating to this project in the future, and the amount of such expenditures could be substantial.
OML 90.In November 2005, we entered into a Heads of Agreement with Brittania-U Nigeria Limited (“Brittania-U”) to acquire a 40 percent participating interest in the Ajapa Marginal Field (the “Ajapa Field”) in OML 90 offshore Nigeria, which has a size of approximately 11,367 acres. On February 26, 2006, we entered into a Participation Agreement and Joint Operating Agreement with Britannia-U regarding the Ajapa Field. The Nigerian government and certain third parties must approve this transaction before the 40 percent participating interest can be transferred to us. If these approvals are not received by May 3, 2006, these agreements will terminate unless both of us agree to extend them. After the required approvals have been obtained, we must pay $4 million to Brittania-U and we must commence Phase 1 of the drilling program within six months. Under Phase 1, we must spend at least $6 million to drill, evaluate, test and either complete or plug and abandon one well in the Ajapa Field. If the costs of the Phase 1 drilling program exceed $6 million, we have the option to either withdraw from this phase or continue this phase using additional funds. After Phase 1, we may either withdraw from the entire project or enter Phase 2 of the drilling program. If we enter Phase 2, we must pay $3 million to Brittania-U and we must commence Phase 2 within 6 months. Under Phase 2, we must spend at least $6 million to either re-enter the existing Ajapa-1 well or drill a new replacement well, and evaluate, test and either complete or plug and abandon the well. If the costs of the Phase 2 drilling program exceed $6 million, we have the option to either withdraw from this phase or continue this phase using additional funds. After Phase 2, we may either withdraw from the entire project or enter Phase 3 of the drilling program. If we elect to enter Phase 3, we must pay a cash bonus to Brittania-U based on the estimated reserves and we must commence Phase 3 within 6 months. Under Phase 3, we must spend at least $38 million to further develop the Ajapa Field. If the costs of the Phase 3 drilling program exceed $38 million, we have the option to either withdraw from this phase or continue this phase using additional funds.
During all three phases of the drilling program up to a maximum of $50 million and before payout, we must pay 100 percent of all costs in return for an 80 percent net revenue interest. After payout but before 15 million barrels of crude oil have been produced, we must pay 50 percent of all costs in return for a 50 percent net revenue interest. After payout and after 15 million barrels of crude oil have been produced, we must pay 40 percent of all costs in return for a 40 percent net revenue interest. We are currently evaluating the financing options for this project. In accordance with our agreement with Sovereign, we have the obligation to issue to Sovereign warrants to purchase 25,000 shares of our common stock for its efforts related to this project.
Stranded Gas Venture. In April 2005, we formed a venture for the primary purpose of providing funds to acquire rights to stranded gas and liquids with respect to projects currently being evaluated and future projects (“Stranded Gas Venture”) and have obtained commitments for $60,000,000. We may use funds from the venture to fund our costs of evaluation and acquisition of rights to stranded gas and liquids reserves, including costs to (1) conduct geologic, geophysical and reservoir analysis of investment opportunities, (2) conduct oil and gas project development activities and (3) acquire interests in oil and gas properties, including projects that involve traditional methods of production and processing, as well as projects that may later include the use of our GTL technologies.
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Under the terms of the participation agreements entered into with other venture participants, the other venture participants will fund 100 percent of the costs to acquire the rights to stranded gas and liquids projects and will receive 20 percent of the interest that we acquire in any such project. Net cash proceeds received from our share of any project, including bonuses, or net revenues from the sale of production attributable to our working interest or overriding royalty interests in a project, less the payment of any operating expenses and maintenance capital expenditures, taxes, royalties or other required payments to a governmental entity, will be paid as follows:
| | • | | first, 100 percent to the other venture participants proportionately until each such participant has received an amount equal in value to 80 percent of the sum of such participant’s individual cost basis in all of the then existing projects in which such participant participated; |
| | • | | second, 100 percent to the other venture participants proportionately until each such participant has received an amount equal in value to a return of 10 percent per annum, compounded annually, on 80 percent of the sum of such participant’s individual costs basis in all of the projects in which such participant participated; and |
| | • | | third 100 percent to us. |
As a result of entering into the participation agreements with respect to the Stranded Gas Venture, we have issued 103,627 shares of common stock and paid $600,000 in cash to TI Capital Management (“TI Capital”) in accordance with its amended consulting agreement.
Mobile GTL Facility. We refer to both our GTL Barge and GTL FPSO as a Mobile GTL Facility. In August 2003, we announced our plan to commercialize a GTL Barge. The GTL Barge is designed to develop offshore and near-shore coastal natural gas fields in the one to three trillion cubic feet (“TCF”) range where there is currently no infrastructure to produce and transport the stranded reserves. These fields are generally considered to be too small to support a liquefied natural gas facility. The GTL Barge builds on the strengths and advantages of the Syntroleum Process, which utilizes air instead of oxygen. The GTL Barge is also designed to have equipment to process natural gas liquids. We expect that a single GTL Barge would be designed to produce approximately 20,400 barrels per day (“b/d”) of total products, of which 8,700 b/d would be zero sulfur diesel fuel. The balance would be a mix of naphtha and natural gas liquids.
In February 2005, we executed an agreement with Bluewater Energy Services B.V. (“Bluewater”) to conduct a feasibility study and engineering study for placing a small GTL plant on an FPSO. The study is expected to cost $2.0 million, of which we and Bluewater will bear 25 percent and 75 percent of the costs, respectively. If, after the study, the parties to the agreement elect to pursue opportunities for a GTL FPSO, the parties will seek to negotiate definitive agreements covering the possible acquisition of oil and gas reserves or other opportunities for use of the GTL FPSO. Neither we nor Bluewater may pursue a study of opportunities for the GTL FPSO with third parties before December 31, 2006 without the consent of the other party.
In February 2006, we executed a Letter of Intent with Bluewater to memorialize the intentions of the formation of a joint venture to develop, construct, own and operate a FPSO vessel equipped with gas-to-liquids conversion capability. We and Bluewater will each bear 50 percent of the costs associated with the formation of the joint venture. The Letter of Intent will terminate on the first date to occur of an executed and mutually signed definitive agreement with respect to the joint venture or December 31, 2007.
Papua New Guinea. In November 2005, we entered into a Memorandum of Understanding with the government of Papua New Guinea to examine the development of an approximately 50,000 b/d GTL plant as part of an industrial complex dedicated to gas-based industries near the capital city of Port Moresby. We will work with the government of Papua New Guinea Ministry of Planning and Development to study the feasibility of a large GTL plant that would share natural gas pipeline infrastructure facilities with various other possible gas conversion participants, including ammonia, methanol and power plant developers.
During 2004, we completed a feasibility study with Oil Search Limited (“Oil Search”) for a GTL Mobile Facility in Papua New Guinea. We worked with Oil Search to develop cost estimates for upstream gas and liquids development and pipeline transportation in addition to the GTL facility. We recognized revenue of $100,000 related to this project in joint development revenue for the year ended December 31, 2004
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PT ELNUSA. In November 2005, we entered into a Memorandum of Understanding with PT ELNUSA, a subsidiary of the Indonesian state-owned company Pertamina. The agreement will establish a joint study to identify suitable gas reserves for development of a Syntroleum GTL facility. We have not yet completed any significant amount of work on this study.
Ivanhoe Energy.Ivanhoe Energy Inc. (“Ivanhoe”) and Egyptian Natural Gas Holding Company (“EGAS”), the state organization charged with the management of Egypt’s natural gas resources, signed a memorandum of understanding to enable Ivanhoe to conduct and prepare a feasibility study to construct and operate a GTL plant in Egypt. Ivanhoe holds a master unlimited-volume license with us. Ivanhoe has announced that, if the results of the feasibility study are positive, EGAS has agreed to commit up to 4.2 TCF of natural gas for the anticipated 20-year operating life of the proposed project. Ivanhoe has invited us to join this project as an equity participant and we are in the process of evaluating this alternative.
Linc Energy, Ltd.On August 15, 2005, we entered into a Memorandum of Agreement with Australian- based Linc Energy, Ltd. (“Linc Energy”) to pursue the development of a CTL project using the Syntroleum Process in Queensland, Australia. The agreement, which would enable our technology to benefit from Linc Energy’s underground coal gasification (“UCG”) expertise, is part of Linc Energy’s ongoing Chinchilla Project. The terms of the agreement include cooperation on the Chinchilla Project and future UCG-CTL projects to be pursued by Linc Energy under a CTL license from us, and provide us with an option to invest in the equity of these projects. We and Linc Energy have agreed to jointly fund a series of technology demonstration programs in advance of developing engineering designs for the CTL projects. The agreement has been extended to terminate on June 30, 2006, unless further extended by mutual agreement of the parties.
Sustec AG.On January 31, 2006, we entered into a Memorandum of Understanding (the “Agreement”) with Sustec AG (“Sustec”), a private company based in Basel, Switzerland and parent company of Future Energy of Freidberg, Germany that provides for exclusive joint business development of projects that will integrate Future Energy’s gasification technology with our Fischer-Tropsch technology. The purpose of the joint venture is to develop projects for the conversion of coal and other carbonaceous materials such as pet-coke, reside and biomass into ultra-clean fuels. Each company will own 50 percent of the joint venture. We and Sustec intend to commit exclusive licensing agreements of our respective technologies to a separate business unit that will develop jointly owned coal-to liquids facilities and other non-natural-gas-to-liquids projects worldwide. The agreement will terminate on the earlier of January 28, 2008 or the execution of definitive agreements with respect to the three initial projects to be undertaken in Germany and the United States in accordance with the Agreement.
Qatar.In the Middle East, Qatar has one of the world’s largest single gas fields, the North Field, with recoverable reserves that are sufficient to support multiple GTL projects. Marathon, one of our licensees, currently has development plans underway for building a large commercial GTL plant in Qatar. In April 2005, the Minister of Energy of Qatar announced that the Marathon GTL project in Qatar, along with ConocoPhillips, Chevron and others, are being delayed for approximately three years. Marathon has announced that it remains interested in pursuing the project in Qatar, notwithstanding the delay, as well as other GTL projects around the world.
Demonstration and Scale-up Activities
DOE Catoosa Project. The DOE concluded an agreement in 2001 with Integrated Concepts and Research Corporation to provide funding to a team of companies for the DOE Catoosa Project for which we received preliminary approval in October 2000. In May 2002, we signed a participation agreement with Marathon in connection with this project. This project included the relocation of certain modules from our Cherry Point GTL facility from ARCO’s refinery in Washington State to the Port of Catoosa near Tulsa, Oklahoma. These modules were the basis for construction of Catoosa Demonstration Facility, a plant designed to produce up to approximately 70 b/d of synthetic product. The plant was mechanically completed and dedicated on October 3, 2003, and startup and fuel deliveries commenced in the first quarter of 2004. The fuels from this facility have been tested by other project participants in advanced power train and emission control technologies and were also tested in bus fleets by the Washington Metropolitan Area Transit Authority and the U.S. National Park Service at Denali National Park in Alaska. We have installed additional facilities at the Catoosa Demonstration Facility outside the scope of the DOE Catoosa Project.
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Since this project is not for commercial operations, the costs associated with it have been expensed in accordance with SFAS No. 2,Accounting for Research and Development Costs. The project has been funded by us and the other project participants, including $12.0 million from the DOE, labor and cash contributions of $9.3 million by Marathon, and a $21.3 million loan agreement between Marathon and us. We completed our fuel production and delivery commitments in connection with the DOE Catoosa Project during 2005 and as a result, we have recognized $5,798,000 in joint development revenues for the year ended December 31, 2005.
We have operated the plant since completion of the DOE Catoosa Project and plan to continue operating the plant during portions of 2006 for ourselves, producing fuels, seeking to create new efficiency improvements, increasing our data and extending our operating experience. We intend to mothball the plant once we have completed these projects until such time as additional joint development programs or government fuels production contracts are forthcoming.
DOD Project. In January 2002, Congress appropriated $3.5 million for a proposed Flexible JP-8 (“single battlefield fuel”) Pilot Plant program under the Department of Defense Appropriation Bill, 2002. In September 2002, we signed a $2.2 million contract with the DOD to participate in the program, to provide for the design of a marine-based fuel-production plant, as well as testing of synthetically made GTL JP-8 fuel in military diesel and turbine engine applications. Phase I of this program is now complete, and all the work done to date has validated our beliefs in the performance of the single battlefield fuel product and in the design of the barge-mounted unit to produce the fuel. We have recorded joint development revenues totaling $2.2 million over the life of this contract, including $1.7 million during 2003 and the remainder in 2002.
Congress has appropriated $2.0 million for Phase II development of our proposed Flexible JP-8 single battlefield fuel Pilot Plant Program under fiscal year 2004 DOD appropriations legislation. We expect to receive approximately $950,000 under the appropriation. Phase II will include expanded engineering and design work for fuel production systems and further single battlefield fuel characterization and demonstration work. Finalization of our contracts occurred in the fourth quarter and we began work at that time. We have recognized $435,000 in joint development revenue from this project for 2005 and expect to complete the remainder of the work by 2007.
In August 2004, Congress appropriated $4.5 million for Phase III development of our Flexible JP-8 single battlefield fuel Pilot Plant Program under the DOD fiscal 2005 appropriations legislation. We expect to receive approximately $2.8 million under the appropriation. Phase III of this program will include expanded engineering and design work for single battlefield fuel production systems for sea and land and further single battlefield fuel characterization and demonstration work for all branches of the military. Finalization of the contracts for this phase occurred in the second quarter of 2005. We have recognized $747,000 in joint development revenue from this project for the year ended December 31, 2005 and expect to complete the remainder of the work by August 2006.
DOE Coal-to-Liquids Project. In March 2005, Congress appropriated funding of $4.5 million to Integrated Concepts and Research Corporation and us to evaluate commercially available coal gasification and synthesis gas cleanup technologies and the integration of these processes with a cobalt catalyst based Fischer-Tropsch (“FT”) technology. We anticipate that the results of this work will provide a foundation for the development of a coal-to-liquids plant based on a cobalt catalyst FT technology. Additionally, engineering and economic analysis will be utilized to evaluate the commercial feasibility of a plant in a coal-producing state.
DOT Fuel Evaluation Program.In November 2005, the DOT concluded an agreement with ICRC to provide funding for demonstration of the operating performance benefits and development of the market acceptance of Ultra-Clean Fischer-Tropsch diesel fuels in transit bus fleet covering a range of climates. Oklahoma and Alabama transit bus fleets will demonstrate and test our S-2 FT diesel fuel. Alaskan transit bus fleets will demonstrate and test our S-1 arctic-grade FT diesel fuel. We expect to receive approximately $1.0 million in fuel sales and labor for this program. We have recognized $364,000 in other revenue from this project for the year ended December 31, 2005.
Coal Derived Synthesis Gas. In November 2005, we announced an agreement to conduct laboratory-scale demonstration of our Fischer-Tropsch (FT) catalyst with coal-derived synthesis gas produced at an established gasification facility. The new testing program will demonstrate the effectiveness of the Syntroleum FT catalysts with proven coal-derived synthesis gas clean-up and treatment processes for use in a CTL application. The testing protocol will include two bench-scale FT reactors and gas sampling connections to the clean synthesis gas
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production flow. The testing program is planned to begin in the second quarter of 2006 and is expected to run for approximately six months. Our specialists will work with the personnel from the gasification company in this program funded by us.
Research and Development Projects
Our primary research and development projects during the year ended December 31, 2005 related to our GTL technologies for use in GTL plants, including catalyst performance evaluation and enhanced reactor designs. Expenses for pilot plant, engineering and research and development incurred during the year ended December 31, 2005 totaled $11,734,000. These expenses related to salaries and wages, outside contract services, lab equipment and improvements and laboratory operating expenses, which primarily supported work on technology we plan to use in fuels plants and our GTL Mobile Facility. We also operated our Catoosa Demonstration Facility throughout 2005 for further research and development, fuel production, and additional testing. Expenses incurred for the operations and modifications to our Catoosa Demonstration Facility during the year ended December 31, 2005 totaled $10,710,000.
Other Activities
Agreement with ExxonMobil.In December 2004, we signed an agreement with ExxonMobil Research and Engineering Company (“ExxonMobil”) pursuant to which we received a worldwide license to use ExxonMobil’s patented processes to produce and sell fuels from natural gas or substances such as coal. In addition, we have the right to extend the terms of this agreement to our licensees. The scope of this agreement includes the fields of synthesis gas production, Fischer-Tropsch synthesis, product upgrading to make fuels and various processes that relate to these areas. The agreement includes all existing ExxonMobil patents (which number over 3,000 worldwide) and future improvements to patents in these areas over the next several years. This agreement does not include patents covering certain specific catalyst formulations and manufacturing steps. We have agreed that we will not enforce against ExxonMobil and its affiliates any patents that we obtain after the date of the license agreement, to the extent that those patents overlap with any of ExxonMobil’s patents. We intend to continue to develop and commercialize our process; however, we recognize a potential to utilize some ExxonMobil patents in our process. We believe that there is a potential for savings from the utilization of these patents that more than offsets the cost of the license.
Results of Operations
Consolidated Results for the Years Ended December 31,
| | | | | | | | | |
| | | 2005 | | 2004 | | 2003 |
| | | (in thousands) |
Revenues | | | | | | | | | |
Joint Development Revenue | | $ | 7,444 | | $ | 923 | | $ | 14,183 |
Catalyst Materials Revenue | | | — | | | 5,674 | | | 4,966 |
Other | | | 464 | | | 9 | | | 91 |
| | | | | | | | | |
Total Revenues | | $ | 7,908 | | $ | 6,606 | | $ | 19,240 |
| | | | | | | | | |
2005 vs. 2004
Joint Development Revenue. Revenues from our joint research and development and demonstration operations were $7,444,000 in 2005, compared with $923,000 in 2004. The increased revenues in 2005 primarily were due to:
| | • | | Increased funding for research and development activities by licensees, the U.S. government and other third parties |
| | • | | Revenue recognition of previously deferred revenue related to fuel delivery commitments associated with the DOE Ultra Clean Fuels Demonstration project in the amount of $5,798,000 |
Catalyst Materials Revenue.Revenues from catalyst materials sales were $0 in 2005 compared to $5,674,000 in 2004. The decrease relates to the following:
| | • | | Liquidation of catalyst materials from our suspended Sweetwater project in 2004 |
| | • | | No remaining catalyst materials available for sale in 2005 |
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Other Revenue.Revenues from other revenue were $464,000 in 2005 compared to $9,000 in 2004. The increase is due to:
| | • | | Other revenue in 2005 consisted of GTL fuel sales to the Tulsa Transit Authority in Oklahoma and Alaska in accordance with our sub-agreement with the Department of Transportation |
| | • | | Approximately $101,000 of GTL fuel sales were recognized for shipments to various customers for further research on fuel capabilities in 2005. |
| | • | | Smaller quantities of sales of GTL fuel were recognized in 2004 |
2004 vs. 2003
Joint Development Revenue. Revenues from our joint research and development and demonstration operations were $923,000 in 2004, compared with $14,183,000 in 2003. The decrease in revenue in 2004 resulted from:
| | • | | Revenues in 2003 resulted from release of license credits and related indemnifications, as well as project equity contributions that are non-recurring |
| | • | | Release of license credits resulted in revenue recognition of previously deferred revenue of $12,000,000 |
| | • | | Revenue resulting from feasibility studies with the Department of Defense occurred in 2003 |
| | • | | Revenues in 2004 resulted from feasibility studies and research for other licensees and third parties |
Catalyst Materials Revenue.Revenues from catalyst materials sales was $5,674,000 in 2004 compared to $4,966,000 in 2003. Revenues resulted from the following:
| | • | | Liquidation of catalyst materials from our suspended Sweetwater project |
Other Revenue.Revenues from other revenue were $9,000 in 2004 compared to $91,000 in 2003. The decrease is due to:
| | • | | Fuel sales and small research and development projects to third parties in 2003 |
| | • | | Smaller quantities of sale of GTL fuel were recognized in 2004 |
| | | | | | | | | |
| | | 2005 | | 2004 | | 2003 |
| | | (in thousands) |
Operating Costs and Expenses | | | | | | | | | |
Cost of catalyst materials sales and impairment | | $ | — | | $ | 3,033 | | $ | 7,886 |
Catoosa Demonstration Facility | | | 10,710 | | | 12,994 | | | 21,843 |
Pilot plant, engineering and research and development | | | 11,734 | | | 9,260 | | | 8,135 |
Depreciation, depletion, amortization and impairment | | | 5,064 | | | 602 | | | 639 |
Non-cash equity compensation | | | 4,686 | | | 4,341 | | | 85 |
General and administrative and other | | | 18,385 | | | 16,843 | | | 15,305 |
| | | | | | | | | |
Total Operating Costs and Expenses | | $ | 50,579 | | $ | 47,073 | | $ | 53,893 |
| | | | | | | | | |
2005 vs. 2004
Cost of Sales and Impairment of Catalyst Materials. Costs of catalyst material sales during 2005 were $0 as compared to $3,033,000 in 2004. The decrease resulted from:
| | • | | Catalyst materials are held at market value in 2004 and were fully liquidated resulting in the total cost incurred in 2004 |
| | • | | No remaining catalyst materials held for sale in 2005 |
Catoosa Demonstration Facility. Expenses related to the Catoosa Demonstration Facility totaled $10,710,000 during 2005 compared to $12,994,000 during 2004. The decrease resulted from:
| | • | | Decreased expenditures in 2005 resulted from the installation of major equipment modules during 2004 |
| | • | | Continuous operations with smaller modifications and maintenance for 2005 |
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Pilot Plant, Engineering and R&D Expense. Expenses from pilot plant, engineering and research and development activities were $11,734,000 in 2005 compared to $9,260,000 in 2004. The increase in expenditures resulted from:
| | • | | Increased salaries and wages for technical and engineering group |
| | • | | Continuous and increased studies and documentation for process design of a GTL plant |
| | • | | Modifications to Tulsa Pilot Plant and start up operations with modifications in place in 2005 compared to 2004 |
Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion, amortization and impairment expenses were $5,064,000 in 2005 compared to $602,000 in 2004, the increase resulted from:
| | • | | Aje-3 delineation well resulted in a write down of $3,331,000 in 2005 due to unfavorable geologic factors for commercial completion |
| | • | | Geological and geophysical costs in the amount of $1,034,000 impaired due to the unlikely nature of future development by management |
Non-Cash Equity Compensation. Equity compensation expense for the vesting of stock compensation awards to employees and consultants totaled $4,686,000 in 2005 and $4,341,000 in 2004. The increase resulted from:
| | • | | Vesting of warrants issued to consultants for the achievement of goals under agreements with these consultants for 2004 and 2005 |
| | • | | Increased consultant stock compensation and stock compensation bonus structure for employees in 2005 |
General and Administrative and Other.General and administrative expenses for 2005 were $18,385,000 compared to $16,843,000 in 2004. The increase resulted from:
| | • | | Increased general and administrative staffing resulting in higher salaries and wages and other components directly correlated with increased staffing |
| | • | | Increased corporate liability insurance in 2005 |
2004 vs. 2003
Cost of Sales and Impairment of Catalyst Materials. Costs of catalyst material sales during 2004 were $3,033,000 as compared to $7,866,000 in 2003. The decrease resulted from:
| | • | | Catalyst materials written down to market value in 2003 resulting in an impairment of $2,931,000 in 2003 as market value decreased from original purchase price |
Catoosa Demonstration Facility. Expenses related to the Catoosa Demonstration Facility totaled $12,994,000 during 2004 compared to $21,843,000 during 2003. The decrease resulted from:
| | • | | Expenditures consisted of construction completion of plant in 2003 |
| | • | | Partial operation cost incurred in 2004 as well as major equipment module modifications in 2004 |
Pilot Plant, Engineering and R&D Expense. Expenses from pilot plant, engineering and research and development activities were $9,260,000 in 2004 compared to $8,135,000 in 2003. The increase in expenditures resulted from:
| | • | | Increased engineering and design work completed on GTL barge in 2004 |
| | • | | Increased research and development of catalyst development, including development and testing of an improved catalyst formation in 2004 |
| | • | | Certain other research and development projects completed in 2004 and 2003 |
Depreciation, Depletion, Amortization and Impairment. Depreciation, depletion, amortization and impairment expenses were $602,000 in 2004 compared to $639,000 in 2003.
| | • | | Depreciation of property, plant and equipment remained relatively the same due to no major increases in property, plant and equipment |
Non-Cash Equity Compensation. Equity compensation expense for the vesting of stock compensation awards to employees and consultants totaled $4,341,000 in 2004 and $85,000 in 2003. The increase resulted from:
| | • | | Vesting of warrants issued to consultants for the achievement of goals under agreements with these consultants for 2004 |
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General and Administrative and Other.General and administrative expenses for 2004 were $16,843,000 compared to $15,305,000 in 2003. The increase resulted from:
| | • | | Increased travel, salaries and wages, and management bonuses in 2004 |
| | | | | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (in thousands) | |
Other Income and Expenses | | | | | | | | | | | | |
Investment and Interest Income | | $ | 2,554 | | | $ | 891 | | | $ | 1,310 | |
Interest Expense | | | (1,869 | ) | | | (1,697 | ) | | | (1,196 | ) |
Other Income (Expense) | | | 3,729 | | | | (418 | ) | | | 785 | |
Foreign Currency Exchange | | | 745 | | | | (367 | ) | | | (2,027 | ) |
Income Taxes | | | — | | | | (12 | ) | | | (60 | ) |
Income from discontinued domestic oil and gas business | | | (3,882 | ) | | | (480 | ) | | | (164 | ) |
Income from discontinued real estate operations | | | — | | | | — | | | | 315 | |
Minority interest of discontinued real estate operations | | | — | | | | — | | | | (99 | ) |
Gain on sale of discontinued operations | | | — | | | | — | | | | 1,151 | |
2005 vs. 2004
Investment and Interest Income. Investment and interest income was $2,554,000 in 2005 compared to $891,000 in 2004. The increase resulted from:
| | • | | Increased cash balance resulting in higher interest received on cash held in money market accounts in 2005 |
Interest Expense. Interest expense was $1,869,000 during 2005 compared to interest expense of $1,697,000 in 2004. The increase resulted from:
| | • | | Expense related to Marathon Convertible debt. Forms of repayment for this interest can be through capital contributions from a third party, credits again future license fees or conversion into our common stock at no less than $6.00 and not more than $8.50 per share or a cash payment at our option |
| | • | | Higher principal and interest balance in 2005 than in 2004 resulting in increased interest |
| | • | | Debt issuance costs associated with Joint Venture resulted in approximately $165,000 in interest expense for 2005 |
Other Income (Expense), Foreign Exchange and Minority Interests. Other income (expense), including foreign exchange loss and minority interest, was income of $4,474,000 in 2005, compared to expense of $785,000 during 2004. The increase resulted from:
| | • | | Income resulted from signature bonus received in the second quarter of 2005 from the Participants in the Aje Field development project |
| | • | | Foreign currency gains were recognized in 2005 compared to the foreign currency loss in 2004 |
Provision for Income Taxes. Income tax expense was $0 and $12,000 in 2005 and 2004, respectively. The decrease resulted from:
| | • | | Tax expense during 2004 period represents the Australian withholding tax imposed on interest earned on funds held in Australian bank accounts. No recognition of an income tax benefit for these losses occurred as a loss was incurred in 2004 |
| | • | | No remaining funds in Australian escrow bank accounts in 2005 thus resulting in $0 income tax expense |
Income from Operations of Discontinued Domestic Oil and Gas Business. Loss from the discontinuation of the domestic oil and gas business in 2005 was $3,882,000 and $480,000 in 2004. The increase resulted from:
| | • | | Loss resulted from depreciation, depletion, amortization, and impairment of properties and equipment associated with the domestic oil and gas business. These assets are classified as held for sale and have been written to estimated market value. Depreciation, depletion, amortization, and impairment in 2005 was approximately $3,783,000 |
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| | • | | Acquisition of oil and gas properties and equipment with non-producing properties resulted in a loss for 2004 |
2004 vs. 2003
Investment and Interest Income. Investment and interest income was $891,000 in 2004 compared to $1,310,000 in 2003. The decrease resulted from:
| | • | | Decrease in interest income received on Australian escrow accounts which were returned to the commonwealth of Australia in 2004 under the agreement with the Commonwealth |
| | • | | Interest received on escrow funds during 2003 |
Interest Expense. Interest expense was $1,697,000 during 2004 compared to interest expense of $1,196,000 in 2003. The increase resulted from:
| | • | | Expense related to Marathon convertible debt. Forms of repayment for this interest can be through capital contributions from a third party, credits again future license fees or conversion into our common stock at no less than $6.00 and not more than $8.50 per share or a cash payment at our option |
| | • | | Higher principal and interest balance in 2004 than in 2003 resulting in increased interest |
Other Income (Expense), Foreign Exchange and Minority Interests. Other income (expense), including foreign exchange loss and minority interest, was expense of $785,000 in 2004, compared to expense of $1,242,000 during 2003. The decrease resulted from:
| | • | | Foreign currency gains were adjustments related to deferred credit and related debt in Australian currency in both periods |
Provision for Income Taxes. Income tax expense was $12,000 and $60,000 in 2004 and 2003, respectively. The decrease resulted from:
| | • | | Tax expense during both periods represents the Australian withholding tax imposed on interest earned on funds held in Australian bank accounts. No recognition of an income tax benefit for these losses occurred as a loss was incurred in 2004 and in 2003 |
Income from Operations of Discontinued Domestic Oil and Gas Business. Loss from the discontinuation of the domestic oil and gas business in 2004 was $480,000 and $164,000 in 2003. The increase resulted from:
| | • | | Acquisition of oil and gas properties and equipment with non-producing properties |
Income from Operations of Discontinued Real Estate business. Income from the discontinuation of the real estate business in 2004 was $0 and $1,367,000 in 2003. The decrease resulted from:
| | • | | Netted Real estate revenues, cost of real estate sold, and operating expenses resulted from the sale of interest in certain undeveloped land and residential lots in Houston, Texas in July 2003 |
| | • | | Minority interest expense related to our discontinued real estate business during 2003 was $99,000 |
| | • | | Sale of operations resulted in a gain on disposal of assets in the amount of $1,151,000 |
| | • | | All real estate inventory has been eliminated and we will not receive revenue from the sale of any further real estate |
Net Income (Loss)
| | | | | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (in thousands) | |
Net Income (Loss) | | $ | (41,394 | ) | | $ | (42,550 | ) | | $ | (34,638 | ) |
2005 vs. 2004
In 2005, we experienced a loss of $41,394,000 compared to $42,550,000 in 2004. The decrease in net loss relates primarily to factors stated above, increased operating expenditures as well as non-cash depreciation, depletion, amortization, and impairment from oil and gas exploration and processing activities. The non-cash expenditures are expected to be non-recurring.
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2004 vs. 2003
In 2004, we experienced a loss of $42,550,000 compared to $34,638,000 in 2003. The increase in the net loss primarily relates to lower joint development revenues as well as other factors stated in the explanations above.
Liquidity and Capital Resources
General
As of December 31, 2005, we had $69,663,000 in cash and short-term investments. We also had $1,684,000 in restricted cash related primarily to our agreement with Sovereign, a consulting firm that has assisted us in acquiring natural gas fields worldwide. Our current liabilities totaled $31,363,000, including $25,925,000 of convertible debt with Marathon that matures on June 30, 2006.
At December 31, 2005, we had $1,224,000 in accounts receivable outstanding relating to our GTL fuel sales and joint development activities. We believe that all of the receivables currently outstanding will be collected and therefore we have not established a reserve for bad debts.
Cash flows used in operations were $38,470,000 during the year ended December 31, 2005, compared to $43,635,000 during the year ended December 31, 2004. The decrease results from lower costs at the Catoosa Demonstration Facility and increased investment and interest income, offset by increased research, development, and engineering costs, and general and administrative expenditures compared to 2004. Operating cash flows during 2004 also included the liquidation of catalyst materials.
Cash flows used in investment activities were $7,942,000 during the year ended December 31, 2005, compared to cash flows provided by investment activities of $19,279,000 during the year ended December 31, 2004. The increase in cash used in investing activities is primarily related to the increase in capital expenditures of oil and gas assets and escrow accounts established for the Aje-3 well and Sovereign, offset by the increase in cash provided by the settlement with the Commonwealth of Australia in the same period in 2004.
Cash flows provided by financing activities were $84,507,000 during the year ended December 31, 2005, compared to $23,454,000 during the year ended December 31, 2004. The increase in cash flows provided by financing activities relates to the proceeds received from the sale of stock and option exercises totaling $81,792,000 during the year ended December 31, 2005 compared to $37,853,000 during the same period in 2004.
We have expended and will continue to expend a substantial amount of funds to continue the research and development of our GTL technologies, to market the Syntroleum Process, to design and construct GTL plants, and to develop our other commercial projects. Our current plan includes funds for projects for pilot plant, engineering and research and development activities throughout the rest of the year and operations of our Catoosa Demonstration Facility throughout 2006. We also expect to invest capital into our international oil and gas opportunities during 2006, with partial funding provided by our Stranded Gas Venture. We intend to obtain additional funds through collaborative or other arrangements with strategic partners and others and through debt (including debt which is convertible into our common or preferred stock) and equity financing. We also intend to obtain additional funding through joint ventures, license agreements and other strategic alliances, as well as various other financing arrangements to meet our capital and operating cost needs for various projects. We are currently exploring alternatives for raising capital to fund the growth of our CTL business, including the development, and demonstration of effectiveness, of our technology with coal-derived synthesis gas. In January 2006, we entered into a memorandum of understanding with Sustec AG (“Sustec”) to form a joint venture to develop projects that will integrate Sustec’s coal gasification technology with our Fischer-Tropsch technology.
We have an effective registration statement for the proposed offering from time to time of shares of our common stock, preferred stock, debt securities, depository shares or warrants for an aggregate offering price of approximately $102 million. If adequate funds are not available, we may be required to delay or to eliminate expenditures for our capital projects, as well as our research and development and other activities or seek to enter into a business combination transaction with or sell assets to another company. We could also be forced to license to third parties the rights to commercialize additional products or technologies that we would otherwise seek to develop ourselves. If we obtain additional funds by issuing equity securities, dilution to stockholders may occur. In
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addition, preferred stock could be issued in the future without stockholder approval, and the terms of our preferred stock could include dividend, liquidation, conversion, voting and other rights that are more favorable than the rights of the holders of our common stock. We can give no assurance that any of the transactions outlined above will be available to us when needed or on terms acceptable or favorable to us.
Assuming the commercial success of the plants based on the Syntroleum Process, we expect that license fees, catalyst sales and sales of products from GTL or CTL plants in which we own an interest will be a source of revenues. In addition, we could receive revenues from other commercial projects we are pursuing. However, we may not receive any of these revenues, and these revenues may not be sufficient for capital expenditures or operations and may not be received within the expected time frame. If we are unable to generate funds from operations, our need to obtain funds through financing activities will be increased.
We have sought and intend to continue to temporarily invest our assets, pending their use, so as to avoid becoming subject to the registration requirements of the Investment Company Act of 1940. These investments are likely to result in lower yields on the funds invested than might be available in the securities market generally. If we were required to register as an investment company under the Investment Company Act, we would become subject to substantial regulation that could materially and adversely affect us.
Contractual Obligations
The following table sets forth our contractual obligations as of December 31, 2005:
| | | | | | | | | | | | | | | |
| | | Payments Due by Period |
| | Total | | Less than 1
year | | 1-3 years | | 4-5 years | | After 5
years |
Contractual Obligations | | | | | | | | | | | | | | | |
Long Term Debt Obligations | | $ | 25,925 | | $ | 25,925 | | $ | — | | $ | — | | $ | — |
Purchase Obligations | | | 2,500 | | | 2,500 | | | — | | | — | | | — |
Capital (Finance) Lease Obligations | | | 190 | | | 76 | | | 114 | | | — | | | — |
Operating Lease Obligations | | | 7,418 | | | 972 | | | 1,809 | | | 744 | | | 3,893 |
Other Long-Term Liabilities reflected on the Balance Sheet under GAAP | | | 4,247 | | | — | | | — | | | — | | | 4,247 |
| | | | | | | | | | | | | | | |
Total | | $ | 40,280 | | $ | 29,473 | | $ | 1,923 | | $ | 744 | | $ | 8,140 |
| | | | | | | | | | | | | | | |
We have entered into employment agreements, which provide severance benefits to several key employees. Commitments under these agreements totaled approximately $5,449,000 at December 31, 2005.
Long-term debt obligations represent our convertible loan agreement with Marathon related to our DOE Catoosa Project. This agreement provides project funding pursuant to advances under two secured promissory notes totaling $21.3 million between Marathon and us for costs relating to the DOE Catoosa Project. At December 31, 2005, we had received advances of $21.3 million under the loan and we had accrued interest of $4.6 million. Each note bears interest at a rate of 8 percent per year and has been extended to mature on June 30, 2006. If we obtain capital for the DOE Catoosa Project from a third party, these capital contributions will be required to be applied towards the outstanding principal and interest of the notes. Under this agreement, the form of repayment includes a right for Marathon to convert the investment into a combination of credits against future license fees or into our stock at no less than $6.00 per share and no more than $8.50 per share. Under certain circumstances, we may also elect to repay the notes in cash. The promissory notes are secured by a mortgage in the assets of the project that would allow Marathon to complete the project in the event of a default by us. Events of default under the promissory notes include failure by us to comply with the terms of the promissory notes, events of our bankruptcy, a material adverse effect on us, a change of control of us and our current assets minus current liabilities falling below $10 million (excluding amounts due under the promissory notes and liabilities associated with prepaid license fees). At December 31, 2005, we were in compliance with the provisions of the note agreements. The DOE Catoosa Project was partially funded with these note agreements, as changes in the scope of the project have occurred. Continued operation of the Catoosa Demonstration Facility has been funded by us.
The Participation Agreement with respect to the Stranded Gas Venture provides for project funding to be used to evaluate investment opportunities, conduct oil and gas project development activities, and acquire interests in oil and gas properties. Once proceeds are received from the venture group for these costs, a joint venture liability
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is recognized. This liability consists of 80 percent principal and 20 percent ownership interest. Interest is accrued on the principal amount at an annual rate of 10 percent, compounded annually, in accordance with the guaranteed rate of return in the Participation Agreement. Once proceeds are received from a venture project, the joint venture liability for the principal amount and accrued interest will be reduced appropriately for any repayment of the funds advanced by the venture group.
In accordance with our Participation Agreement and Joint Operating Agreement with Brittania-U described above in “-Significant Developments During 2005 and Early 2006 – Commercial and Licensee Projects – Qatar,” we must commence Phase I drilling which includes drilling and evaluation and if necessary, testing of the Ajapa-2 well on OML 90 at an estimated cost of $10 million. Phase I will not commence until Brittania-U obtains all of the necessary approvals and consents. If necessary approvals and consents are not received before May 3, 2006, the Participation Agreement and Joint Operating Agreement will terminate.
Our operating leases include leases for corporate equipment such as copiers, printers and vehicles. We had leases on our laboratory, our Houston office and our Bolivian office. Because the ground lessor did not remove us from the lease, we also remain the lessee of a parking garage in Reno, Nevada that we sold to Fitzgerald’s Casino in 2001. This lease is currently paid by Fitzgerald’s Casino and is part of the sale agreement executed in 2001; however, it is included in our schedule of contractual obligations above.
Subsequent to December 31, 2005, we entered into an agreement with a third party regarding a potential development of an oil and gas discovery in Nigeria. We have provided a $2.5 million letter of credit associated with this agreement which is secured with cash.
We are also in discussions with various parties regarding joint venture projects. If these discussions progress, we could enter into additional commercial commitments. These discussions currently relate to projects to be located in Australia, Bolivia, Egypt, Nigeria, Papua New Guinea, Trinidad and the United States.
Notes Receivable from Related Parties
During 2001, we loaned Kenneth L. Agee, our Chairman and former Chief Executive Officer, $300,000 under a loan agreement that allowed up to $1,100,000 in loan advances and which matured on June 25, 2002. In May and June of 2002, we made additional advances of $683,000 to Mr. Agee. The proceeds of these advances were used by Mr. Agee to reduce third party margin account loans and thereby avoid the sale of shares of our common stock to satisfy margin calls as a result of a decline in the market price of our common stock. The loan to Mr. Agee was full recourse, bore interest at the rate of 6 percent, and was secured by the pledge of shares of our common stock that he owned and which had a value (based on Syntroleum’s stock price) equal to or greater than two times the outstanding principal and accrued interest of his loan. On June 25, 2002, the promissory note was renewed for an additional year with an interest rate of 3.75 percent. The renewal of the promissory note increased the amount available to be borrowed to $1,460,000. On June 26 and July 6, 2002, an additional $458,000 was loaned to Mr. Agee to pay off all remaining third party margin account loans. At the maturity of the promissory note on June 25, 2003, Mr. Agee paid us for the entire outstanding balance of the loans, including accrued interest. As a result of this transaction, we have no additional loans outstanding with Mr. Agee.
In February 1999, we loaned $29,000 to Paul F. Schubert, previously our Vice President of Research and Development. In September 1999, we loaned Mr. Schubert an additional $30,000. These notes were unsecured and bore interest rates of 5.18 percent and 5.98 percent, respectively. The initial note matured on February 25, 2003, on which date Mr. Schubert settled the note by paying $35,000 in principal and interest. On April 11, 2003, Mr. Schubert left Syntroleum, and in connection with his separation, the second note was forgiven and recorded as compensation expense.
In June 1995, Larry J. Weick, our Senior Vice President of Business Development, purchased 200,000 shares of common stock of a predecessor of Syntroleum for a purchase price of $0.50 per share, paid by delivery of promissory notes totaling $100,000, the amount of the aggregate purchase price. In September 1997, our predecessor company loaned Mr. Weick approximately $117,000, the proceeds of which were used to repay his previously outstanding note and accrued interest. To secure his note, Mr. Weick pledged to our predecessor shares of our predecessor’s common stock with a market value equal to no less than two times the indebtedness under the note. The note was full recourse, bore interest at the rate of 6.1 percent per year and matured in May 2004. The
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amount outstanding, including accrued interest was approximately $169,000 at December 31, 2003. In May 2004, Mr. Weick paid us for the entire outstanding balance of the loan, including accrued interest. As a result of this transaction, we have no additional loans outstanding with any directors or officers of the Company.
Equity Issuances
Private Placements and Public Offerings. In February 2003, we sold in a private placement one million shares of our common stock and warrants to purchase additional shares of common stock for a total of $3.0 million. The warrants allowed for the purchase an additional one million shares of our common stock at an exercise price of $6.00 per share, with expiration on December 31, 2004. All of these warrants were exercised on December 29, 2004, and we issued one million shares of our common stock for proceeds of $6.0 million. These warrants had a fair market value of approximately $961,000 at the date of issuance and were recorded as additional paid-in capital in the accompanying financial statements. We expect to use the net proceeds from the offering for working capital and general corporate purposes. This transaction was exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) thereof as a transaction not involving any public offering.
In November 2003, we closed a public offering of 5,180,000 shares of common stock and warrants to purchase 1,554,000 shares of common stock, priced at $3.95 per share, including 30 percent of a common warrant. Each warrant is exercisable at a price of $5.00 per share of common stock beginning on the date of issuance and expiring November 4, 2007. The warrants were deemed to have a fair market value of approximately $2.6 million for financial accounting purposes at the date of issuance and were recorded as additional paid-in capital in 2003. Net proceeds to us were approximately $19.0 million. We used a portion of the net proceeds from the offering to fund a portion of the costs associated with our projects related to the monetization of sub-quality gas. We intend to use any remaining net proceeds to fund a portion of the costs associated with our GTL Mobile Facility project and larger scale GTL projects we are pursuing, if necessary, pilot plant facilities, research and development activities, the acquisition of complementary technologies, working capital needs and other general corporate purposes.
In May 2004, we completed the sale of 5,916,000 shares of common stock and warrants to purchase 887,400 shares of common stock pursuant to a public offering at a price to the public of $5.60 per share and 15 percent of a warrant. Each warrant is initially exercisable at a price of $7.60 per share of common stock beginning on the date of issuance and ending on May 26, 2008. The warrants were deemed to have a fair market value of approximately $1.9 million at the date of issuance and were recorded as additional paid-in-capital. We received net proceeds of approximately $31.1 million after underwriting discount and offering expenses.
In March 2005, we completed the sale of 7,000,000 shares of common stock at a price of $10.00 per share. We sold all of these shares directly to Legg Mason Opportunity Trust, a series of Legg Mason Investment Trust, Inc., a registered investment company. The sale resulted in net proceeds to us of approximately $69,950,000.
In April 2005 we completed the sale of 1,000,000 shares of our common stock at a price of $10.00 per share directly to Dorset Group Corporation. The sales resulted in net proceeds to us of approximately $9,968,000.
TI Capital Management. During October 2003, we consummated the private issuance and sale to Mr. Ziad Ghandour a total of 400,000 shares of our common stock for an aggregate purchase price of $1.8 million. Mr. Ghandour is one of our directors and also serves as a consultant to us. Mr. Ghandour became an employee of our Company in October of 2005. In February 2004, we issued warrants to purchase up to 1,170,000 shares of our common stock to TI Capital Management (“TI Capital”), a consulting firm owned by Mr. Ziad Ghandour, pursuant to an amended and restated consulting agreement. These warrants replace the 600,000 options that were granted to Mr. Ghandour in October 2003. The warrants to purchase 170,000 shares at an exercise price of $5.00 per share are exercisable from the date of stockholder approval, which was received on April 26, 2004. The vesting period for these warrants did not begin until they were approved by stockholders, at which time we recognized expense totaling $636,000 with respect to these warrants during the year ended December 31, 2005. The warrants to purchase 500,000 shares at an exercise price of $5.25 per share became exercisable upon the execution of the agreement with Bluewater in February 2005. Warrants to purchase 500,000 shares at an exercise price of $4.50 per share vested in September 2004 in relation to work completed with Dragados. Related to the vesting of these warrants for the year ended December 31, 2005, we recognized expense of $2,759,000. All warrants will expire on November 4, 2007. This transaction was exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 4(2) thereof as a transaction not involving any public offering.
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In October 2004, we amended our consulting agreement with TI Capital to provide that in connection with the closing of a financing with a company introduced to us by TI Capital, we will pay TI Capital, a number of shares of our common stock equal to one percent of the net proceeds that we receive in connection with such financing divided by $5.79 per share, provided that the closing occurs by February 2006, or such later date as we, in our sole discretion, may designate. The cash payment will be made promptly after the meeting of stockholders at which the proposal to approve the issuance of the shares is submitted. As a result of the Stranded Gas Venture, we have issued TI Capital 103,627 shares of common stock and paid cash bonuses totaling $600,000 in accordance with this agreement. TI Capital and Mr. Ghandour collectively own 603,627 shares of our common stock at December 31, 2005.
In February 2006, we amended this agreement to provide that in connection with the closing of a financing with a company introduced to Syntroleum by TI Capital, we will make a payment to TI Capital equal to 1.5 percent of the total equity and debt financing provided by parties other than us for each of the first two GTL plants, provided that the cumulative amount of the two payments does not exceed $50,000,000.
Sovereign Oil and Gas Company II, LLC. In March 2004, we entered into a joint development agreement with Sovereign Oil & Gas Company II, LLC (“Sovereign”), a consulting firm that we have retained to assist us in acquiring stranded natural gas fields worldwide utilizing the Syntroleum Process as feedstock for our GTL Mobile Facility. Under the agreement, we agreed to issue warrants to purchase 50,000 shares of our common stock at an exercise price of $6.40 upon stockholder approval of the agreement. These warrants are exercisable for five years beginning on the date of stockholder approval, which was received on April 26, 2004. The vesting period for these warrants did not begin until they were approved by stockholders, at which time we recognized expense totaling $165,000 with respect to these warrants for the period ended December 31, 2005.
In addition, under the agreement we are required to issue warrants to purchase 25,000 shares upon our acquisition of an interest in a property proposed by Sovereign, the acquisition from us by another company of such property or the execution of an agreement by us and another company regarding joint participation in the project involving such a property, exercisable five years from the acquisition or agreement date. If we and Sovereign do not receive a cash bonus or overriding royalty interest in connection with the acquisition from us by another company of such property or the execution of an agreement by us and another company regarding our joint participation in the project involving such a property, we will issue an additional 25,000 warrants exercisable for five years from the acquisition or agreement date plus an additional 50,000 warrants exercisable for five years from the date of first production of hydrocarbons from the property. We are required under the agreement to issue warrants to purchase 12,500 shares upon our acquisition of an interest in a property proposed by us and accepted by Sovereign or for which we initiated negotiations, the acquisition from us by another company of such property or the execution of an agreement by us and another company regarding participation in the project involving such a property, exercisable for five years from the acquisition or agreement date.
Warrants issued in connection with properties acquired or third party participation achieved between March 1, 2004 and March 1, 2005 had an exercise price of $6.40. Warrants issued in connection with properties acquired or third party participation achieved after March 1, 2005 will have exercise prices per share to be determined based on the price of our common stock on March 1 of the contract year stated in the agreement during which the project commences. No more than 2,000,000 shares of our common stock are issuable upon exercise of the warrants issued pursuant to the agreement.
As a result of our agreements on OML 113 offshore Nigeria, we issued Sovereign warrants to purchase a total of 50,000 shares of our common stock at an exercise price of $6.40 per share. Sovereign has also earned warrants to purchase 25,000 shares of our common stock in relation to our agreement on OML 90. On January 28, 2005, Sovereign exercised warrants to purchase 8,750 shares of our common stock at an exercise price of $6.40 per share, resulting in proceeds of approximately $56,000.
We intend to submit a proposal to our shareholders to approve an amendment to the joint development agreement with Sovereign to change the exercise price of warrants issued to the closing per share sale price of our common stock as of December 1 prior to a contract year in which the warrants are issued. This amendment was made because this is the date that we must give notice to Sovereign of continuation or termination of the joint development agreement for the next contract year. This amendment is subject to shareholder approval at our annual meeting in April 2006. For the 2005 and 2006 contract years, the exercise price for all warrants issued, after shareholder approval, is $6.94 and $7.98 per share,
50
respectively. If shareholder approval is received, the exercise price for the 25,000 warrants to purchase shares of common stock issued for OML 90 will change from $11.16 to $6.94 per share.
Employee and Stock-Based Compensation.During 2004, we granted an aggregate of 398,500 restricted common stock units to certain employees under our existing stock option and incentive plans. These restricted common stock units vest over various periods through 2007. We recorded deferred compensation for these units totaling $2,305,000 at the time of grant based on the market price of our common stock on that date. Total compensation expense related to the vesting of these units was $885,000, net of terminations, during 2005. In connection with the vesting of restricted units, we repurchased and subsequently cancelled a total of 41,162 shares of common stock as settlement for the employees’ payroll taxes.
In January 2005, we granted an aggregate of 84,081 shares of common stock to certain employees under our existing stock option and incentive plans related to service performed in 2004. These shares were fully vested on the date of grant. We recognized compensation expense of $774,000 during the year ended December 31, 2004 for the stock awards that were granted to employees in 2005 related to this plan based on the value of our common stock on January 24, 2005. In connection with the vesting of restricted shares we repurchased and subsequently cancelled a total of 17,282 shares of common stock as settlement for the employees’ payroll taxes.
On April 25, 2005, our stockholders approved the adoption of the Syntroleum Corporation 2005 Stock Incentive Plan (the “Plan”), which provides for the issuance of up to 6,600,000 shares of our common stock pursuant to the grant of stock options, stock appreciation rights, stock awards (including restricted stock and stock units) and performance awards. Awards will be available for grant to our employees, independent contractors and non-employee directors, except that non-employee directors may only be granted awards of stock appreciation rights, stock options or restricted stock under the Plan. The Board of Directors has established an annual incentive plan under which employees are eligible to receive a certain number of shares of common stock based on the achievement of certain company-wide objectives and the individual’s performance rating for the year. The Board of Directors has established objectives on which we will be measured which determines a number of shares to be issued to employees based on a rating system. In January 2006, we granted an aggregate of 91,707 shares of common stock to certain employees under our existing stock option and incentive plans related to service performed in 2005. These shares were fully vested on the date of grant. We recognized compensation expense of $877,000 during the year ended December 31, 2005 for the stock awards that were granted to employees in 2006 related to this plan based on the value of our common stock on January 23, 2006.
On June 30, 2005, we entered into stock option award agreements with certain of our officers under our 2005 Stock Incentive Plan. The agreements granted the officers options to purchase up to 2,000,000 shares of our common stock at an exercise price of $10.52 per share. Depending on the sustained stock price of our common stock and the net present value of future cash flows, a percentage of the options will vest as determined in a performance vesting schedule with respect to the period commencing on the date of grant and ending on December 31, 2010 (the “Performance Period”). The term of each option is ten years from the date of grant. “Sustained stock price” means the average fair market value of a share of our common stock during any six-month period commencing on or after the first day of the Performance Period and ending on or before the last day of the Performance Period. “Net present value of future cash flows” means the net present value of estimated future cash flows from executed agreements (such as a contract to supply natural gas), proven reserves or any other source of future cash flows with analogous certainty to the aforementioned sources as estimated by an independent auditor designated by our Board of Directors. For this purpose, an annual discount rate of 10 percent is used to calculate net present value.
In July 2005, we entered into a stock option award agreements with certain of our officers under our 2005 Stock Incentive Plan similar to those described above. The agreements granted the officers options to purchase up to 600,000 shares of our common stock at an exercise prices of $10.14 per share. The term of each option is ten years from the date of grant. Depending on the sustained stock prices of our common stock and the net present value of future cash flows, a percentage of options will vest as according to the Performance Period.
During 2005, we granted an aggregate of 250,000 restricted common stock units to certain employees under the 2005 Stock Incentive Plan. These restricted common stock units vest over various periods through 2010. We recognized $238,000 in compensation expense for the year ending December 31, 2005. Throughout the remainder of the vesting period we expect to recognize $2,297,000 in compensation expense relating to the vesting
51
of these restricted common stock units. We recorded deferred compensation for these units totaling $2,535,000 at the time of grant based on the market prices of our common stock on that date.
Subsequent to December 31, 2005, we granted an aggregate of 261,500 options to purchase shares of common stock to employees at a weighted average exercise price of $9.59 per share. We also issued 119,998 shares of common stock as a result of the vesting of restricted common stock units. We granted 45,230 restricted common stock units to employees and issued 38,759 shares of common stock to our directors for services to be provided in the future.
Commonwealth of Australia Settlement
In early 2000 we began developing a nominal 11,500 b/d specialty product GTL plant, about four kilometers from the North West Shelf liquefied natural gas facility on the Burrup Peninsula of Western Australia, which we refer to as the Sweetwater Project. We selected this site after receiving a financial commitment, in the form of loans and license agreements, from the Commonwealth of Australia. The plant design was intended to produce synthetic lube oil, normal paraffins, process oils and light paraffins using a fixed tube reactor design, operating with a proprietary catalyst, which produces a high yield that can be further refined into the desired products. The total estimated cost of this project was approximately $756 million.
Our engineering, procurement and construction contract with Tessag Industrie Anlagen GmbH expired on August 30, 2002. On October 29, 2002, we announced the suspension of our Sweetwater Project. We had been attempting to arrange financing for the Sweetwater plant using non-recourse senior and subordinated debt totaling approximately 60 percent of the total project costs, as well as equity financing from third parties, together with our own equity contribution for the remaining balance of the costs. We had been in discussions with several potential equity participants in the project. Additionally, we had been approached regarding the possibility of moving the plant to other locations. In connection with proposals to move the plant to other sites, we had discussed the availability of financial sponsorship. However, after evaluating the alternatives, we determined that insufficient economic support existed to continue pursuing the plant at the time. Our decision was based on decreased financing activities for international projects subsequent to the events of September 11, 2001, our inability to negotiate long-term product off-take agreements, lower than expected product margins caused by increased capital costs and reduced expectations for product market prices for the proposed product slate and the loss of Enron Corporation as a 13 percent equity partner. In connection with the suspension of the project, we expensed approximately $31 million of costs previously capitalized as property and equipment on our consolidated balance sheet in September 2002. This amount reflected engineering, catalyst materials, upgrading and other site costs associated with the construction of the plant. No construction work on the plant had occurred.
On April 27, 2004, we announced that we had reached an agreement with the Commonwealth of Australia to resolve all issues between both parties regarding the suspension of the Sweetwater Project. Under this agreement, all of the funds that were held in escrow accounts in Australia related to advances on the loan and the license agreement, plus all interest earned on these funds since the suspension of the project and other associated costs, was returned to the Commonwealth of Australia in September 2004. The Commonwealth will retain its license for the Syntroleum Process; however, it will not receive AUD $15 million of the original AUD $30 million in credits against future license fees for the funds that are being returned. The income statement impact of this transaction was a charge against earnings of $610,000 for interest and other associated costs since the suspension of the project and is included in other income (expense) on our consolidated statement of operations for the year ended December 31, 2004. We have no plans to re-start the Sweetwater Project.
Real Estate and Other Asset Sales
Our other non-current assets at December 31, 2005 included an investment in First Century Partnership III, L.P., a privately held venture capital limited partnership with a carrying value of $27,000. We sold our equity investment in the Hotel Ambassador, a recently renovated hotel in Tulsa, Oklahoma, in March 2004 for $70,000. The investment had a carrying value of $47,000 at the time of sale.
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New Accounting Pronouncements
In December, 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004), “Share-Based Payment” (“SFAS 123(R)”), which amends SFAS 123 and SFAS 95 “Statement of Cash Flows”. SFAS 123(R) requires companies to measure all employee stock-based compensation awards using a fair value method and record such expense in its consolidated financial statements. In addition, the adoption of SFAS 123(R) requires additional accounting and disclosure related to the income tax and cash flow effects resulting from share-based payment arrangements. SFAS 123(R) became effective for us as of January 1, 2006, the first day of the 2006 fiscal year. We will adopt SFAS 123(R) using the modified prospective application basis as defined in the statement. Under this adoption method, we will record expense relating to employee stock-based compensation awards in the periods subsequent to adoption. This expense will be based on all unvested options as of the adoption date as well as all future stock-based compensation awards. Adoption of SFAS No. 123R will not affect our cash flows or financial position, but it will reduce reported income and earnings per share because we will be required to recognize compensation expense for stock-based compensation granted under our employee stock option and incentive plans, whereas we may not have not been required to record such expense under current accounting rules. Under SFAS 123(R), we will recognize compensation expense for our stock options over the vesting period, which is generally three years following the grant date. Based on the current options outstanding, our 2006 pretax expense for those options is expected to be between $4,100,000 and $4,500,000. This amount may increase to the extent any options are granted in 2006.
In December 2003, the FASB issued FASB Interpretation No. 46 (R), aConsolidation of Variable Interest Entities(“FIN 46R”), a revision of FASB Interpretation No. 46 and clarifies the application of Accounting Research Bulletin No. 51,Consolidated Financial Statements, to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have a sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. Application of this Interpretation is required for fiscal years ending after March 15, 2004. We have adopted FIN 46R as of December 31, 2005. Management has determined that the adoption of this Interpretation does not affect the financial statements as of December 31, 2005, as we do not have any variable interest entities to include in consolidation.
In March 2005, the FASB issued FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations (“FIN 47”) an interpretation of SFAS No. 143,Accounting for Asset Retirement Obligation. FIN 47 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. The interpretation is effective for fiscal years ending on or after December 15, 2005. We have adopted FIN 47 as of December 31, 2005. We have determined that no liability exists for conditional assets as of December 31, 2005 and therefore there is no impact to our financial statements resulting from the adoption of FIN 47.
In May 2005, the FASB issued SFAS No. 154,Accounting for Changes and Error Corrections (“SFAS No. 154”), a replacement of APB Opinion No. 20,Accounting Changes, and FASB Statement No. 3,Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. We have adopted SFAS No. 154 as of September 30, 2005. There is no impact to our financial statements resulting from the adoption of SFAS No. 154.
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and use assumptions that affect reported amounts. We believe that the following items represent our critical accounting policies and estimates:
Revenue Recognition. We recognize revenues from joint development activities based on the terms and conditions of the related contracts. Generally, these contracts provide that revenue is earned as the expenses under the contract are incurred. Substantially all of our joint development revenues during 2005, 2004 and 2003 have been from activities with several major oil companies, the DOE and the DOD. All such joint development activities were pursuant to agreements where we expense the research and development costs as incurred.
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License fee deposits received as cash upon the sale of master volume or regional license agreements are recorded as deferred revenue until recognized as revenue. We expect to recognize revenue on the sale of license agreements by recording 50 percent of the license fee deposit as revenue when: (1) a site license agreement has been formally executed, (2) the license fee deposit has been paid in cash and (3) we have delivered to the licensee the process design package for the licensee’s initial licensed plant. Since 50 percent of the license fee deposit is subject to our indemnity obligation with respect to the performance guarantee on the related plant, the remaining license fee deposit will be recognized as revenue after the related plant has passed certain performance tests. Option fees, which provide licensees the right to include additional geographic areas in its license agreement territory, are deferred until the earlier of the option being exercised or lapsing. The license agreements currently allow us to work with outside engineering contractors to develop a site-specific plant design in accordance with licensee specifications; this design package is called the Process Design Package, or “PDP,” and allows for a 100 percent cost recovery plus a 10 percent mark-up from the licensee. To date, we have not delivered any PDPs for initial licensed plants. We are under no obligation to return these deferred revenues except in the case in which a licensee builds a plant and the plant does not pass certain performance tests. In this situation, the licensee would be able to receive a refund of 50 percent of the license fees paid. The license agreements have a 15-year life and, after this time, the deferred revenue will be recorded as license revenue in the statements of operations unless a site license has been executed. Our current licenses generally begin to expire in 2011 and the initial deposits will be recognized as licensing revenue as the licenses expire should a licensee not purchase a site license and begin construction of a plant prior to expiration of the license.
We sold a certain amount of the catalyst materials we had on-hand during the years ended December 31, 2004 and 2003. Any revenues and costs of sales related to the sale of these materials are recorded in the statement of operations in the period in which the materials are sold. We liquidated all of these materials in 2004.
We expect to earn revenue from the sale of proprietary catalysts to licensees. Our license agreements currently require catalyst to be used in the initial loading of the catalyst into the Fischer-Tropsch reactor for the licensee to receive a process guarantee. After the initial fill, the licensee may use other catalyst vendors if appropriate catalysts are available. The price for catalysts purchased from us pursuant to license agreements is equal to cost plus a specified margin. We will receive revenue from catalyst sales if and when the licensees purchase catalysts. We expect that catalysts will need to be replaced every three to five years.
We have pursued and are pursuing projects in which we are directly involved in oil and gas field development and the processing of natural gas using gas processing technologies. We pursued projects involving processing of natural gas using gas processing technologies in 2005. These include projects in which we would process developed gas on a fee basis and projects that may later evolve into integrated projects including development, production and processing of hydrocarbons. Revenue from these projects will be recognized based on actual volumes processed for customers and sold to purchasers. We expect these projects will be pursued by us with co-venturers through various arrangements. We anticipate receiving revenues from these projects, including sales of oil and gas from properties owned by us or jointly with another party, as well as processing and gathering fees from facilities in which we own an interest.
Research and Development.We incur significant costs for research, development and engineering programs. Expenses classified as research and development include salaries and wages, rent, utilities, equipment, engineering and outside testing and analytical work associated with our research, development and engineering programs. Since these costs are for research and development purposes, and not commercial or revenue producing, they are charged to expense when incurred in accordance with SFAS No. 2,Accounting for Research and Development Costs.
Stock-Based Compensation. We have elected to follow the intrinsic-value method of accounting for stock-based compensation as prescribed by Accounting Principle Board (“APB”) 25.Additionally, we apply the disclosure-only provisions of SFAS 123, as amended by SFAS No. 148, Accounting for Stock-Based Compensation- Transition and Disclosure(“SFAS 148”) for options granted to employees. Accordingly, no compensation cost has been recognized for stock options issued to employees under the stock option plans because the plans qualify for “fixed” plan accounting and the exercise price of all options granted to employees is greater than or equal to the market price of our stock on the date of grant. However, pursuant to the requirements of SFAS 123 and SFAS 148,
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we are required to disclose our pro forma net income (loss) for the three years in the period ended December 31, 2005 as if the fair value method of accounting prescribed by SFAS 123 had been used. Management uses various assumptions in assigning a value to these stock options based on a Black-Scholes option pricing model.
In 2005, we announced to our employees an incentive compensation plan whereby employees could receive a certain number of shares of common stock based on the achievement of certain goals and objectives by the individual employee and by us. The Board of Directors establishes the objectives on which we will be measured and determines the number of shares to be issued based on a rating system. Individual objectives are measured by management based on a similar rating system.
We also grant stock-based incentives to certain non-employees under stock-based compensation plans. These stock-based incentives are accounted for in accordance with SFAS 123, as amended, because the individuals receiving these instruments are not considered employees of Syntroleum. These stock-based incentives have various vesting requirements, strike prices and expiration dates. Certain stock-based incentives vest upon the achievement of certain performance goals associated with the consulting agreement. These stock-based incentives will be measured and expense will be recorded at the time these performance goals are met using various assumptions in assigning a value to these awards based on a Black-Scholes option pricing model. Any stock awards granted to non-employees that are not related to specific performance criteria are expensed at the time of the grant.
Oil and Gas Properties. We follow the full cost method of accounting for exploration, development, and acquisition of gas and oil reserves. Under this method, all such costs (productive and nonproductive) including salaries, benefits, and other internal costs directly attributable to these activities are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method. We exclude all costs of unevaluated properties from immediate amortization. Our unamortized costs of oil and gas properties are limited to the sum of the future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of any unproved properties. If our unamortized costs in oil and gas properties exceed this ceiling amount, a provision for additional depreciation, depletion and amortization is required. All of the capitalized costs for oil and gas activities are currently considered to be unevaluated and are therefore excluded from amortization.
Discontinued Operations and Impairment of Assets.We follow the provisions of SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assetsfor assets, other than oil and gas properties, including for the presentation and disclosure of discontinued operations. We make assessments of impairment on a project-by-project basis. Management reviews assets for impairment when certain events have occurred that indicate that the asset may be impaired. An asset is considered to be impaired when the estimated undiscounted future cash flows are less than the carrying value of the asset. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future cash flows of a project.
We follow the full cost method of accounting for the exploration, development and acquisition of oil and reserves as stated above. All unamortized costs of oil and gas properties are limited to the sum of future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of any unproved properties. We completed an evaluation of the potential reserves and the economics related to our domestic oil and gas properties and decided to focus our efforts on aligning the Company with specific goals and projects that have GTL and CTL potential. As a result, we decided to discontinue further expenditures in the Central Kansas Uplift area and began disposing of these properties. The net effect of the United States oil and gas activities, including the related gas processing plant and equipment, is presented as discontinued operations in the financial statements for the years ended December 31, 2005, 2004, and 2003 in accordance with SFAS No. 144.
Critical Estimates.Some of the more significant estimates made by management include, but are not limited to, realization of notes receivable, impairment on catalyst materials, valuation of stock-based compensation, ultimate costs of dismantling and restoring oil and gas properties, and impairment of property and equipment. Actual results have not been materially different than the estimates made by management in the past. Management bases these estimated on the most current information available. These estimates are subject to change in the future as a result of changes in the fair values of the assets.
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| Item 7A. | Quantitative and Qualitative Disclosures about Market Risk |
We had approximately $69,663,000 in cash and cash equivalents in the form of money market instruments and short-term certificates of deposit at December 31, 2005. This compares to approximately $31,573,000 in cash and cash equivalents at December 31, 2004. Our cash and cash equivalents balances are subject to fluctuations in interest rates and we are restricted in our options for investment by our short-term cash flow requirements. Our cash and cash equivalents are held in a few financial institutions; however, we believe that our counter-party risks are minimal based on the reputation and history of the institutions selected.
We expect to conduct a portion of our business in currencies other than the United States dollar. We may attempt to minimize our currency exchange risk by seeking international contracts payable in local currency or we may choose to convert our currency position into United States dollars. In the future, we may also have significant investments in countries other than the United States. The functional currency of these foreign operations may be the local currency; accordingly, financial statement assets and liabilities may be translated at prevailing exchange rates and may result in gains or losses in current income. Currently, all of our subsidiaries use the United States dollar for their functional currency. Monetary assets and liabilities are translated into United States dollars at the rate of exchange in effect at the balance sheet date. Transaction gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the United States dollar are included in the results of operations as incurred.
Foreign exchange risk currently relates to deferred revenue, a portion of which is denominated in Australian dollars. The portion of deferred revenue denominated in Australian currency was U.S. $10,951,000 at December 31, 2005. The deferred revenue is converted to U.S. dollars for financial reporting purposes at the end of every reporting period. To the extent that conversion results in gains or losses, such gains or losses will be reflected in our statements of operations. The exchange rate of the United States dollar to the Australian dollar was $0.73 and $0.78 at December 31, 2005 and December 31, 2004, respectively.
We do not have any purchased futures contracts or any derivative financial instruments, other than warrants issued to purchase common stock at a fixed price in connection with consulting agreements, private placements and other equity offerings.
| Item 8. | Financial Statements and Supplementary Data |
Our consolidated financial statements, together with the reports thereon of Grant Thornton LLP dated March 3, 2006, are set forth on pages F-1 through F-29 hereof. See Item 15 for an index to our consolidated financial statements.
| Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure |
None.
| Item 9A. | Controls and Procedures |
Evaluation of Disclosure Controls and Procedures.In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2005 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms.
Changes in Internal Controls.There has been no change in our internal controls over financial reporting that occurred during the three months ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
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Management’s Report on Internal Control Over Financial Reporting.Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15(d)-15(f). Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2005 based on the framework in “Internal Control-Integrated Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the criteria set forth in “Internal Control-Integrated Framework”, our management believes that our internal control over financial reporting was effective as of December 31, 2005.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Grant Thornton LLP, an independent registered public accounting firm that audited our financial statements included in this Annual Report on Form 10-K, has issued an attestation report on management’s assessment of our internal control over financial reporting. Such attestation is included below.
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Syntroleum Corporation
We have audited management’s assessment, included in Syntroleum Corporation’s Item 9A of Form 10-K for the year ended December 31, 2005, under the heading “Management’s Report on Internal Control Over Financial Reporting”, that Syntroleum Corporation (a Delaware Corporation) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control—Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Syntroleum Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
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In our opinion, management’s assessment that Syntroleum Corporation maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established inInternal Control—Integrated Framework issued by COSO. Also in our opinion, Syntroleum Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Syntroleum Corporation and subsidiaries as of December 31, 2005 and 2004, and the related statements of operations, stockholders’ equity (deficit), and cash flows for each of the three years in the period ended December 31, 2005 and our report dated March 3, 2006, expressed an unqualified opinion on those financial statements.
GRANT THORNTON LLP
Tulsa, Oklahoma
March 3, 2006
| Item 9B. | Other Information |
None.
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PART III
| Item 10. | Directors and Executive Officers of the Registrant |
The information required by Item 10 is incorporated herein by reference to the section entitled “Proposal 1—Election of Directors” in our definitive proxy statement for our 2006 annual meeting of stockholders, which will be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 within 120 days of December 31, 2005. Certain information with respect to our executive officers is set forth at the end of Part I of this Annual Report on Form 10-K under the caption “Executive Officers of the Registrant.”
We have adopted a written Code of Ethics that is applicable to our directors, chief executive officer, chief financial officer, chief accounting officer, controller and other executive officers. A copy of our Code of Ethics is available on our website atwww.syntroleum.com and was included as Exhibit 14 to our Annual Report on Form 10-K for the year ended December 31, 2003 filed with the SEC on March 23, 2004. Investors may request a copy of our Code of Ethics at no charge by writing to Richard L. Edmonson, Senior Vice President, General Counsel and Corporate Secretary, Syntroleum Corporation, 4322 South 49th West Avenue, Tulsa, Oklahoma 74107. We will disclose any amendments to the Code of Ethics and any waivers to the Code of Ethics for directors and executive officers by posting such information on our website or in a current report on Form 8-K filed with the SEC.
| Item 11. | Executive Compensation |
The information required by Item 11 is incorporated herein by reference to the section entitled “Executive Compensation” in our definitive proxy statement for our 2006 annual meeting of stockholders, which will be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 within 120 days of December 31, 2005. Certain information with respect to our executive officers is set forth in Item 1 of this Annual Report on Form 10-K under the caption “Executive Officers of the Registrant.”
| Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters |
The information required by Item 12 is incorporated herein by reference to the section entitled “Security Ownership of Management and Certain Beneficial Owners” in our definitive proxy statement for our 2006 annual meeting of stockholders, which will be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 within 120 days of December 31, 2005. Information required by Item 201(d) of Regulation S-K is set forth in Item 5 of this Annual Report on Form 10-K.
| Item 13. | Certain Relationships and Related Party Transactions |
The information required by Item 13 is incorporated herein by reference to the section entitled “Certain Transactions” in our definitive proxy statement for our 2005 annual meeting of stockholders, which will be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 within 120 days of December 31, 2005.
| Item 14. | Principal Accountant Fees and Services |
The information required by Item 14 is incorporated herein by reference to the sections entitled “Independent Public Accountant Fees” in our definitive proxy statement for our 2005 annual meeting of stockholders, which will be filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 within 120 days of December 31, 2005.
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PART IV
| Item 15. | Exhibits and Financial Statement Schedules |
(a)(1) Financial Statements
Consolidated Financial Statements for the Three Years Ended December 31, 2005:
(a)(2) Financial Statement Schedules
All schedules and other statements for which provision is made in the applicable regulations of the SEC have been omitted because they are not required under the relevant instructions or are inapplicable.
(a)(3) Exhibits
The following exhibits are filed as part of this Annual Report on Form 10-K:
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Exhibit No. | | Description of Exhibit |
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| *3.1 | | Certificate of Incorporation of the Company (incorporated by reference to Appendix B to the Company’s Proxy Statement filed with the Securities and Exchange Commission on May 12, 1999 (File No. 0-21911)). |
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| *3.2 | | Amended and Restated Certificate of Designations of Series A Junior Participating Preferred Stock of the Company dated October 24, 2004 (incorporated by reference to Exhibit 4.5 to Amendment No. 2 to the Company’s Current Report on Form 8-K dated June 17, 1999 and filed with the Securities and Exchange Commission on October 28, 2004 (File No. 0-21911)). |
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| 3.3 | | Bylaws of the Company. |
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| 3.3.1 | | Amendment to the Bylaws of the Company. |
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| *4.1 | | Second Amended and Restated Rights Agreement dated as of October 28, 2004 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 29, 2004 (File No. 0-21911)). |
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| *4.2 | | Warrant Agreement, dated as of November 4, 2003, between the Company and American Stock Transfer and Trust Company, as warrant agent (including form of warrant certificate) (incorporated by reference to Exhibit 4.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2003 filed with the Securities and Exchange Commission on November 14, 2003 (File No. 0-21911)). |
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| *4.3 | | Warrant Agreement, dated as of May 26, 2004, between the Company and American Stock Transfer and Trust Company, as warrant agent (including form of warrant certificate) (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 25, 2004 (File No. 0-21911)). |
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The Company is a party to debt instruments under which the total amount of securities authorized does not exceed 10 percent of the total assets of the Company and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, the Company agrees to furnish a copy of such instruments to the Commission upon request.
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| *10.1 | | Form of Master License Agreement of the Company (incorporated by reference to Exhibit 10.9 to the Company’s Registration Statement on Form S-4 (Registration No. 333-50253) filed with the Securities and Exchange Commission on April 16, 1998). |
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| +*10.2 | | Form of Amended and Restated Indemnification Agreement between the Company and each of its officers and directors (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2000 filed with the Securities and Exchange Commission on March 22, 2001 (File No. 0-21911)). |
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| +*10.3.1 | | Stock Option Plan for Outside Directors of the Company (incorporated by reference to Appendix F to the Company’s Joint Proxy Statement/Prospectus filed with the Securities and Exchange Commission on July 6, 1998 (File No. 0-21911)). |
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| +*10.3.2 | | Form of Option Agreement under the Stock Option Plan for Outside Directors of the Company (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 16, 2005 (File No. 0-21911)). |
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| *10.4 | | Master Preferred License Agreement dated March 7, 1997 between the Company and Marathon Oil Company (incorporated by reference to Exhibit 10.23 to the Company’s Registration Statement on Form S-4/A (Registration No. 333-50253) filed with the Securities and Exchange Commission on June 8, 1998). |
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| *10.5 | | Master Preferred License Agreement dated April 10, 1997 between the Company and Atlantic Richfield Company (incorporated by reference to Exhibit 10.24 to the Company’s Registration Statement on Form S-4/A (Registration No. 333-50253) filed with the Securities and Exchange Commission on June 8, 1998). |
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| *10.6 | | Volume License Agreement dated August 1, 1997 between the Company and YPF International, Ltd. (incorporated by reference to Exhibit 10.25 to the Company’s Registration Statement on Form S-4/A (Registration No. 333-50253) filed with the Securities and Exchange Commission on June 8, 1998). |
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| *10.7 | | Volume License Agreement dated February 4, 1998 between the Company and Kerr-McGee Corporation (incorporated by reference to Exhibit 10.26 to the Company’s Registration Statement on Form S-4/A (Registration No. 333-50253) filed with the Securities and Exchange Commission on June 8, 1998). |
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| *10.8 | | Volume License Agreement dated January 12, 1998 between the Company and Enron Capital & Trade Resources Corp. (incorporated by reference to Exhibit 10.27 to the Company’s Registration Statement on Form S-4/A (Registration No. 333-50253) filed with the Securities and Exchange Commission on June 8, 1998). |
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| +*10.9.1 | | SLH Corporation 1997 Stock Incentive Plan (incorporated by reference to Exhibit 10(c) to Amendment No. 1 to the Company’s Annual Report on Form 10-K/A for the year ended December 31, 1997 filed with the Securities and Exchange Commission on April 13, 1998 (File No. 0-21911)). |
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| +*10.9.2 | | Form of Option Agreement with certain executive officers under the SLH Corporation 1997 Stock Incentive Plan (incorporated by reference to Exhibit 10(e) to Amendment No. 1 to the Company’s Annual Report on Form 10-K/A for the year ended December 31, 1997 filed with the Securities and Exchange Commission on April 13, 1998 (File No. 0-21911)). |
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| +*10.9.3 | | Form of Option Agreement with directors under the SLH Corporation 1997 Stock Incentive Plan (incorporated by reference to Exhibit 10(f) to Amendment No. 1 to the Company’s Annual Report on Form 10-K/A for the year ended December 31, 1997 filed with the Securities and Exchange Commission on April 13, 1998 (File No. 0-21911)). |
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| +*10.10 | | Form of Consent to Adjustment to Option Agreements called for by Section 2.1(c) of the Agreement and Plan of Merger dated as of March 30, 1998 by and between SLH and the Company (incorporated by reference to Exhibit 10.8 to the Company’s Registration Statement on Form S-4 (Registration No. 333-50253) filed with the Securities and Exchange Commission on April 16, 1998). |
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| *10.11 | | License Agreement dated April 26, 2000 between the Company and Ivanhoe Energy Inc. (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2000 filed with the Securities and Exchange Commission on May 12, 2000 (File No. 0-21911)). |
| |
| *10.12 | | License Agreement dated August 2, 2000 between the Company and Syntroleum Australia Licensing Corporation (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000 filed with the Securities and Exchange Commission on August 14, 2000 (File No. 0-21911)). |
| |
| *10.13 | | License Agreement dated August 3, 2000 between Syntroleum Australia Licensing Corporation and the Commonwealth of Australia (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000 filed with the Securities and Exchange Commission on August 14, 2000 (File No. 0-21911)). |
| |
| *10.14 | | Loan Agreement dated August 3, 2000 between Syntroleum Australia Credit Corporation and the Commonwealth of Australia (incorporated by reference to Exhibit 10.3 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000 filed with the Securities and Exchange Commission on August 14, 2000 (File No. 0-21911)). |
| |
| *10.15 | | Deposit Agreement dated August 3, 2000 between Syntroleum Australia Licensing Corporation, the Commonwealth of Australia and Westpac Banking Association (incorporated by reference to Exhibit 10.4 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000 filed with the Securities and Exchange Commission on August 14, 2000 (File No. 0-21911)). |
| |
| *10.16 | | Deposit Agreement dated August 3, 2000 between Syntroleum Australia Credit Corporation, the Commonwealth of Australia and Westpac Banking Corporation (incorporated by reference to Exhibit 10.5 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000 filed with the Securities and Exchange Commission on August 14, 2000 (File No. 0-21911)). |
| |
| *10.17 | | Letter Agreement dated August 3, 2000 between the Company and the Commonwealth of Australia (incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2000 filed with the Securities and Exchange Commission on August 14, 2000 (File No. 0-21911)). |
62
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| |
| *10.18 | | Amendment No. 1 to Volume License Agreement dated October 11, 2000 between the Company and Ivanhoe Energy Inc. (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2000 filed with the Securities and Exchange Commission on November 14, 2000 (File No. 0-21911)). |
| |
| +*10.19 | | Form of Employment Agreement between the Company and its executive officers dated June 17, 1999 (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1999 filed with the Securities and Exchange Commission on August 12, 1999 (File No. 0-21911)). |
| |
| +*10.20.1 | | Syntroleum Corporation 1993 Stock Option and Incentive Plan Second Amendment and Restatement (incorporated by reference to Annex A to the Company’s Proxy Statement filed with the Securities and Exchange Commission on April 10, 2003 (File No. 0-21911)). |
| |
| +*10.20.2 | | Form of Option Agreement under the Syntroleum Corporation 1993 Stock Option and Incentive Plan Second Amendment and Restatement (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 16, 2005 (File No. 0-21911)). |
| |
| +*10.20.3 | | Form of Restricted Stock Award Agreement under the Syntroleum Corporation 1993 Stock Option and Incentive Plan Second Amendment and Restatement (incorporated by reference to Exhibit 10.2 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 16, 2005 (File No. 0-21911)). |
| |
| *10.21 | | Participation Agreement between the Company and Marathon Oil Company dated May 8, 2002 (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report of Form 10-Q for the period ended June 30, 2002 filed with the Securities and Exchange Commission on August 14, 2002 (File No. 0-21911)). |
| |
| *10.22.1 | | Secured Promissory Note between the Company and Marathon Oil Company dated May 8, 2002 (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002 filed with the Securities and Exchange Commission on August 14, 2002 (File No. 0-21911)). |
| |
| *10.22.2 | | Amendment No. 1 to Secured Promissory Note dated May 8, 2002 entered into on June 9, 2004 between the Company and Marathon Oil Company (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004 filed with the Securities and Exchange Commission on August 13, 2004 (File No. 000-21911)). |
| |
| *10.22.3 | | Amendment No. 2 to Secured Promissory Note dated May 8, 2002, effective as of March 4, 2005 between the Company and Marathon Oil Company (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 8, 2005 (File No. 0-21911)). |
| |
| *10.22.4 | | Secured Promissory Note between the Company and Marathon Oil Company dated February 1, 2003 (incorporated by reference to Exhibit 10.30 to the Company’s annual report on Form 10-K for the year ended December 31, 2002 filed with the Securities and Exchange Commission on March 31, 2003 (File No. 0-21911)). |
| |
| *10.22.5 | | Amendment No. 1 to the Syntroleum Corporation Secured Promissory Note dated February 1, 2003 entered into on June 9, 2004 between the Company and Marathon Oil Company (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004 filed with the Securities and Exchange Commission on August 13, 2004 (File No. 000-21911)). |
63
| | |
| |
| *10.22.6 | | Amendment No. 2 to the Syntroleum Corporation Secured Promissory Note dated February 1, 2003, effective as of March 4, 2005 between the Company and Marathon Oil Company (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 8, 2005 (File No. 0-21911)). |
| |
| *10.23 | | Separation Agreement dated June 12, 2002 between the Company and Mark A. Agee (incorporated by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2002 filed with the Securities and Exchange Commission on August 14, 2002 (File No. 0-21911)). |
| |
| +*10.24 | | Employment Agreement dated August 31, 2002 between the Company and John B. Holmes, Jr. (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2002 filed with the Securities and Exchange Commission on November 14, 2002 (File No. 0-21911)). |
| |
| +*10.25 | | Indemnification Agreement dated as of October 1, 2002 between the Company and John B. Holmes, Jr. (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2002 filed with the Securities and Exchange Commission on November 14, 2002 (File No. 0-21911)). |
| |
| +*10.26 | | Employment Agreement dated September 17, 2002 between the Company and Kenneth R. Roberts (incorporated by reference to Exhibit 10.3 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2002 filed with the Securities and Exchange Commission on November 14, 2002 (File No. 0-21911)). |
| |
| +*10.27 | | Indemnification Agreement dated as of September 16, 2002 between the Company and Kenneth R. Roberts (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report of Form 10-Q for the period ended September 30, 2002 filed with the Securities and Exchange Commission on November 14, 2002 (File No. 0-21911)). |
| |
| +*10.28 | | Employment Agreement dated September 17, 2002 between the Company and Jeffrey M. Bigger (incorporated by reference to Exhibit 10.7 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2002 filed with the Securities and Exchange Commission on November 14, 2002 (File No. 0-21911)). |
| |
| +*10.29 | | Indemnification Agreement dated September 16, 2002 between the Company and Jeffrey M. Bigger (incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2002 filed with the Securities and Exchange Commission on November 14, 2002 (File No. 0-21911)). |
| |
| *10.30.1 | | Warrant Agreement dated February 7, 2003 between the Company and Michael and Selim Zilkha (incorporated by reference to Exhibit 4.1 to the Company’s Form 8-K dated February 7, 2003 filed with the Securities and Exchange Commission on February 19, 2003 (File No. 0-21911)). |
| |
| *10.30.2 | | Registration Rights Agreement dated February 7, 2003 between the Company and Michael and Selim Zilkha (incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K dated February 7, 2003 filed with the Securities and Exchange Commission on February 19, 2003 (File No. 0-21911)). |
| |
| +*10.31 | | Indemnification Agreement dated as of March 13, 2003 between the Company and Ronald E. Stinebaugh (incorporated by reference to Exhibit 10.42 to the Company’s Annual Report of Form 10-K for the year ended December 31, 2002 filed with the Securities and Exchange Commission on March 31, 2003 (File No. 0-21911)). |
64
| | |
| |
| +*10.32 | | Employment Agreement dated February 17, 2003 between the Company and Ronald E. Stinebaugh (incorporated by reference to Exhibit 10.43 to the Company’s Annual Report of Form 10-K for the year ended December 31, 2002 filed with the Securities and Exchange Commission on March 31, 2003 (File No. 0-21911)). |
| |
| +*10.33 | | Stock Option Agreement dated October 1, 2002 between the Company and John B. Holmes, Jr. (incorporated by reference to Exhibit 10.44 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 filed with the Securities and Exchange Commission on March 31, 2003 (File No. 0-21911)). |
| |
| +*10.34 | | Employment Agreement dated as of July 30, 2003 between the Company and Richard L. Edmonson (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2003 filed with the Securities and Exchange Commission on November 14, 2003 (File No. 0-21911)). |
| |
| +*10.35 | | Indemnification Agreement dated as of April 11, 2003 between the Company and Richard L. Edmonson (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2003 filed with the Securities and Exchange Commission on November 14, 2003 (File No. 0-21911)). |
| |
| +*10.36 | | Separation Agreement dated April 11, 2003 between the Company and Paul Schubert (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2003 filed with the Securities and Exchange Commission on May 14, 2003 (File No. 0-21911)). |
| |
| *10.37 | | Agreement in Principle for GTL Project Development dated June 18, 2003 between the Company and Ivanhoe Energy Inc. (incorporated by reference to Exhibit 10.6 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2003 filed with the Securities and Exchange Commission on August 14, 2003 (File No. 0-21911)). |
| |
| *10.38.1 | | Amended and Restated Letter Agreement dated February 2, 2004 between the Company and Ziad Ghandour (incorporated by reference to Exhibit 10.50 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed with the Securities and Exchange Commission on March 23, 2004 (File No. 0-21911)). |
| |
| *10.38.2 | | Amendment No. 3 dated as of October 25, 2004 to Letter Agreement dated October 3, 2003 between the Company and TI Capital Management (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 28, 2004 (File No. 0-21911)). |
| |
| *10.38.3 | | Amendment No. 4 to Letter Agreement dated October 3, 2003 between the Company and TI Capital Management, effective as of March 21, 2005 (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 28, 2005 (File No. 0-21911)). |
| |
| *10.38.4 | | Amendment No. 5 dated as of February 13, 2006 to Letter Agreement dated October 3, 2003 between the Company and TI Capital Management (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on February 23, 2006 (File No. 0-21911)). |
| |
| +*10.39.1 | | Warrant Agreement, dated as of February 2, 2004, between the Company and Ziad Ghandour (incorporated by reference to Exhibit 10.51 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed with the Securities and Exchange Commission on March 23, 2004 (File No. 0-21911)). |
65
| | |
| |
| *10.39.2 | | Registration Rights Agreement, dated as of October 15, 2003, between the Company and Ziad Ghandour (incorporated by reference to Exhibit 10.52 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed with the Securities and Exchange Commission on March 23, 2004 (File No. 0-21911)). |
| |
| *10.39.3 | | Amendment No. 1 to Registration Rights Agreement, dated as of February 2, 2004, between the Company and Ziad Ghandour (incorporated by reference to Exhibit 10.53 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed with the Securities and Exchange Commission on March 23, 2004 (File No. 0-21911)). |
| |
| *10.40 | | Joint Development Agreement dated March 1, 2004 between Syntroleum International Corporation and Sovereign Oil & Gas Company II, LLC (incorporated by reference to Exhibit 10.54 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed with the Securities and Exchange Commission on March 23, 2004 (File No. 0-21911)). |
| |
| +*10.41 | | Director Stock Option Agreement dated December 20, 2002 between the Company and James R. Seward (incorporated by reference to Annex D to the Company’s proxy statement filed with the Securities and Exchange Commission on March 29, 2004 (File No. 0-21911)). |
| |
| *10.42 | | Heads of Agreement dated as of August 27, 2004 between Syntroleum International Holdings Company and Yinka Folawiyo Petroleum Co Ltd. (portions of this document have been omitted pursuant to a request for confidential treatment and filed separately with the SEC) (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004 filed with the Securities and Exchange Commission on November 15, 2004 (File No. 0-21911)). |
| |
| *10.43 | | Joint Venture Agreement dated as of October 7, 2004 between Syntroleum International Holdings Company and Yinka Folawiyo Petroleum Co Ltd. (portions of this document have been omitted pursuant to a request for confidential treatment and filed separately with the SEC) (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2004 filed with the Securities and Exchange Commission on November 15, 2004 (File No. 0-21911)). |
| |
| *10.44 | | Participation Agreement dated January 12, 2005 among Syntroleum Nigeria Limited, Lundin Petroleum B.V., Palace Exploration Company, Challenger Minerals Inc., Providence Resources p.l.c., Howard Energy Co., Inc. and Yinka Folawiyo Petroleum Company Ltd. (incorporated by reference to Exhibit 10.44 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 16, 2005 (File No. 0-21911)). |
| |
| +*10.45 | | Employment Agreement dated as of July 6, 2004 between the Company and Edward G. Roth (incorporated by reference to Exhibit 10.4 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004 filed with the Securities and Exchange Commission on August 13, 2004 (File No. 0-21911)). |
| |
| +*10.46 | | Indemnification Agreement dated as of July 6, 2004 between the Company and Edward G. Roth (incorporated by reference to Exhibit 10.5 to the Company’s Quarterly Report on Form 10-Q for the period ended June 30, 2004 filed with the Securities and Exchange Commission on August 13, 2004 (File No. 0-21911)). |
66
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| |
| +*10.47 | | Employment Agreement dated as of January 3, 2005 between the Company and Greg G. Jenkins (incorporated by reference to Exhibit 10.47 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 16, 2005 (File No. 0-21911)). |
| |
| +*10.48 | | Indemnification Agreement dated as of January 3, 2005 between the Company and Greg G. Jenkins (incorporated by reference to Exhibit 10.48 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2004 filed with the Securities and Exchange Commission on March 16, 2005 (File No. 0-21911)). |
| |
| *10.49 | | Stock Purchase Agreement dated March 17, 2005 between the Company and Legg Mason Opportunity Trust, a series of Legg Mason Investment Trust, Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on March 21, 2005 (File No. 0-21911)). |
| |
| *10.50 | | Stock Purchase Agreement dated April 11, 2005 between the Company and Dorset Group Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 13, 2005 (File No.0-21911)). |
| |
| *10.51 | | Participation Agreement dated as of April 11, 2005 between Syntroleum International Corporation and Dorset Group Corporation (incorporated by reference to Exhibit 10.8 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2005 filed with the Securities and Exchange Commission on May 10, 2005 (File No. 0- 21911)). |
| |
| *10.52 | | Joinder Agreement dated as of April 20, 2005 between Syntroleum International Corporation and Ernest Williams II Q-TIP TUA dated 01/25/2002 (incorporated by reference to Exhibit 10.9 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2005 filed with the Securities and Exchange Commission on May 10, 2005 (File No. 0-21911)). |
| |
| +*10.53 | | Syntroleum Corporation 2005 Stock Incentive Plan, effective as of April 25, 2005 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 28, 2005 (File No. 0- 21911)). |
| |
| +*10.54 | | Summary of Performance Objectives and Target Payouts under the Syntroleum Corporation Annual Incentive Plan (incorporated by reference to Exhibit 10.12 to the Company’s Quarterly Report on Form 10-Q for the period ended March 31, 2005 filed with the Securities and Exchange Commission on May 10, 2005 (File No. 0-21911)). |
| |
| +*10.55 | | Form of Performance Vested Non-Qualified Option Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 5, 2005 (File No. 0-21911)). |
| |
| +*10.56 | | Form of Stock Option Agreement (incorporated by reference to Exhibit 10.3 to the Company’s Registration Statement on Form S-8 filed with the Securities and Exchange Commission on July 8, 2005 (Registration No. 333-126427)). |
| |
| +*10.57 | | Form of Employee Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.4 to the Company’s Registration Statement on Form S-8 filed with the Securities and Exchange Commission on July 6, 2005 (Registration No. 333-126427)). |
| |
| *10.58 | | Memorandum of Agreement dated as of August 15, 2005 between Syntroleum International Corporation and Linc Energy, Ltd. (portions of this document have been omitted pursuant to a request for confidential treatment and filed with the SEC) (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2005 filed with the Securities and Exchange Commission on November 9, 2005 (File No. 0-21911)). |
67
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| *10.59 | | Joinder Agreement dated as of September 19, 2005 between Syntroleum International Corporation and Selim K. Zilkha Trust (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q for the period ended September 30, 2005 filed with the Securities and Exchange Commission on November 9, 2005 (File No. 0-21911)). |
| |
| +*10.60 | | Form of Service Vested Incentive Stock Option Award Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on January 27, 2006 (File No. 0-21911). |
| |
| *14 | | Code of Ethics (incorporated by reference to Exhibit 14 to the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 filed with the Securities and Exchange Commission on March 23, 2004 (File No. 0-21911)). |
| |
| 21 | | Subsidiaries |
| |
| | Syntroleum International Corporation (a Delaware corporation) |
| | Syntroleum/Sweetwater Company, L.L.C. (a Delaware limited liability company) |
| | Syntroleum Australia Credit Corporation (a Delaware corporation) |
| | Syntroleum Australia Licensing Corporation (a Delaware corporation) |
| | Syntroleum Sweetwater Holdings Corp. (a Delaware corporation) |
| | Syntroleum International Holdings, Ltd. (a Cayman Islands exempted company) |
| | Syntroleum International Holdings Company (a Cayman Islands exempted company) |
| | Syntroleum Sweetwater Holdings, Ltd. (a Cayman Islands exempted company) |
| | Syntroleum Australia, Ltd. (a Cayman Islands exempted company) |
| | Syntroleum Peru Holdings Limited (a Cayman Islands exempted company) |
| | Syntroleum Bolivia Holdings L.L.C. (a Delaware limited liability company) |
| | Syntroleum Gas Development, LLC (a Delaware limited liability company) |
| | Ringneck Resources, LLC (a Delaware limited liability company) Syntroleum Gas Processing, LLC (a Delaware limited liability company) |
| | Syntroleum Gas Resources Corporation (a Delaware corporation) Syntroleum Cameroon, Ltd. (a Cayman Islands exempted company) Syntroleum Nigeria Limited (a Nigeria exempted company) |
| | Scout Development Corporation (a Missouri Corporation) |
| | Carousel Apartment Homes, Inc. (a Georgia Corporation) |
| |
| 23 | | Consent of Grant Thornton LLP |
| |
| 31.1 | | Section 302 Certification of Chief Executive Officer |
| |
| 31.2 | | Section 302 Certification of Chief Financial Officer |
| |
| 32.1 | | Section 906 Certification of Chief Executive Officer |
| |
| 32.2 | | Section 906 Certification of Chief Financial Officer |
| * | Incorporated by reference as indicated. |
| + | Compensatory plan or arrangement. |
68
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.
| | | | | | | | |
| | | | SYNTROLEUM CORPORATION |
| | | |
| Dated: March 7, 2006 | | | | By: | | /s/ John B. Holmes, Jr. |
| | | | | | John B. Holmes, Jr. |
| | | | | | President and Chief Executive Officer |
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 and in the capacities and on the dates indicated.
| | | | |
Name | | Capacity | | Date |
| | |
/s/ John B. Holmes, Jr. John B. Holmes, Jr. | | President, Chief Executive Officer and Director (Principal Executive Officer) | | March 7, 2006 |
| | |
/s/ Greg G. Jenkins Greg G. Jenkins | | Executive Vice President of Finance and Business Development and Chief Financial Officer (Principal Financial Officer) | | March 7, 2006 |
| | |
/s/ Carla S. Covey Carla S. Covey | | Senior Vice President of Finance and Chief Accounting Officer (Principal Accounting Officer) | | March 7, 2006 |
| | |
/s/ Kenneth L. Agee Kenneth L. Agee | | Chairman of the Board and Chief Technology Officer | | March 7, 2006 |
| | |
/s/ Alvin R. Albe, Jr. Alvin R. Albe, Jr. | | Director | | March 7, 2006 |
| | |
/s/ Frank M. Bumstead Frank M. Bumstead | | Director | | March 7, 2006 |
| | |
/s/ Robert A. Day Robert A. Day | | Director | | March 7, 2006 |
| | |
/s/ Ziad Ghandour Ziad Ghandour | | Director | | March 7, 2006 |
| | |
/s/ P. Anthony Jacobs P. Anthony Jacobs | | Director | | March 7, 2006 |
| | |
/s/ Robert B. Rosene, Jr. Robert B. Rosene, Jr. | | Director | | March 7, 2006 |
| | |
/s/ James R. Seward James R. Seward | | Director | | March 7, 2006 |
69
Report of Independent Registered Public Accounting Firm
Board of Directors and Shareholders
Syntroleum Corporation
We have audited the accompanying consolidated balance sheets of Syntroleum Corporation (a Delaware corporation) and subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity (deficit) and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Syntroleum Corporation and subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Syntroleum Corporation’s internal control over financial reporting as of December 31, 2005, based on criteria established inInternal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated March 3, 2006, expressed unqualified opinions that Syntroleum Corporation maintained effective internal control over financial reporting and on management’s assessment thereof.
GRANT THORNTON LLP
Tulsa, Oklahoma
March 3, 2006
F-1
SYNTROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands, except per share data)
| | | | | | | | |
| | | December 31,
2005 | | | December 31,
2004 | |
| ASSETS | |
CURRENT ASSETS: | | | | | | | | |
Cash and cash equivalents | | $ | 69,663 | | | $ | 31,573 | |
Restricted cash | | | 1,684 | | | | 221 | |
Accounts receivable | | | 1,224 | | | | 632 | |
Current maturities of note receivable | | | 1,802 | | | | — | |
Other current assets | | | 3,085 | | | | 1,530 | |
| | | | | | | | |
Total current assets | | | 77,458 | | | | 33,956 | |
OIL AND GAS PROPERTY AND EQUIPMENT HELD FOR SALE | | | 1,927 | | | | 4,488 | |
OIL AND GAS PROPERTIES - at cost, net, using full cost method, including $4,514 and $865 at December 31, 2005 and 2004, excluded from amortization, respectively | | | 4,514 | | | | 865 | |
PROPERTY AND EQUIPMENT – at cost, net | | | 2,959 | | | | 2,380 | |
NOTE RECEIVABLE | | | — | | | | 1,809 | |
OTHER ASSETS, net | | | 2,937 | | | | 1,253 | |
| | | | | | | | |
| | $ | 89,795 | | | $ | 44,751 | |
| | | | | | | | |
| LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT) | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
Accounts payable | | $ | 2,632 | | | $ | 3,257 | |
Accrued liabilities and other | | | 2,806 | | | | 2,201 | |
Current deferred revenue | | | — | | | | 5,873 | |
Current maturities of convertible debt | | | 25,925 | | | | — | |
| | | | | | | | |
Total current liabilities | | | 31,363 | | | | 11,331 | |
LONG-TERM CONVERTIBLE DEBT | | | — | | | | 24,221 | |
OTHER NONCURRENT LIABILITIES | | | 114 | | | | 115 | |
STRANDED GAS VENTURE | | | 4,247 | | | | — | |
DEFERRED REVENUE | | | 20,952 | | | | 21,702 | |
COMMITMENTS AND CONTINGENCIES | | | | | | | | |
MINORITY INTERESTS | | | 706 | | | | 706 | |
STOCKHOLDERS’ EQUITY (DEFICIT): | | | | | | | | |
Preferred stock, $0.01 par value, 5,000 shares authorized, no shares issued | | | — | | | | — | |
Common stock, $0.01 par value, 150,000 shares authorized, 55,568 and 54,482 shares issued and outstanding at December 31, 2005 and 2004, respectively, including shares in treasury | | | 556 | | | | 545 | |
Additional paid-in capital | | | 317,350 | | | | 228,295 | |
Deferred compensation | | | (2,589 | ) | | | (577 | ) |
Accumulated deficit | | | (282,904 | ) | | | (241,510 | ) |
| | | | | | | | |
| | | 32,413 | | | | (13,247 | ) |
Less-treasury stock, 7,675 shares at December 31, 2004 | | | — | | | | (77 | ) |
| | | | | | | | |
Total stockholders’ equity (deficit) | | | 32,413 | | | | (13,324 | ) |
| | | | | | | | |
| | $ | 89,795 | | | $ | 44,751 | |
| | | | | | | | |
The accompanying notes are an integral part of these consolidated balance sheets.
F-2
SYNTROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
| | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | |
REVENUES: | | | | | | | | | | | | |
Joint development revenue | | $ | 7,444 | | | $ | 923 | | | $ | 14,183 | |
Catalyst materials revenue | | | — | | | | 5,674 | | | | 4,966 | |
Other revenues | | | 464 | | | | 9 | | | | 91 | |
| | | | | | | | | | | | |
Total revenues | | | 7,908 | | | | 6,606 | | | | 19,240 | |
| | | | | | | | | | | | |
COSTS AND EXPENSES: | | | | | | | | | | | | |
Cost of catalyst materials sales and impairment | | | — | | | | 3,033 | | | | 7,886 | |
Catoosa Demonstration Facility | | | 10,710 | | | | 12,994 | | | | 21,843 | |
Pilot plant, engineering and research and development | | | 11,734 | | | | 9,260 | | | | 8,135 | |
Depreciation, depletion, amortization and impairment | | | 5,064 | | | | 602 | | | | 639 | |
General, administrative and other (Including non-cash equity compensation of $4,686, $4,341 and $85 for the years ended December 31, 2005, 2004 and 2003, respectively.) | | | 23,071 | | | | 21,184 | | | | 15,390 | |
| | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (42,671 | ) | | | (40,467 | ) | | | (34,653 | ) |
INVESTMENT AND INTEREST INCOME | | | 2,554 | | | | 891 | | | | 1,310 | |
INTEREST EXPENSE | | | (1,869 | ) | | | (1,697 | ) | | | (1,196 | ) |
OTHER INCOME (EXPENSE) | | | 3,729 | | | | (418 | ) | | | 785 | |
FOREIGN CURRENCY EXCHANGE | | | 745 | | | | (367 | ) | | | (2,027 | ) |
| | | | | | | | | | | | |
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | | | (37,512 | ) | | | (42,058 | ) | | | (35,781 | ) |
INCOME TAXES | | | — | | | | (12 | ) | | | (60 | ) |
| | | | | | | | | | | | |
INCOME (LOSS) FROM CONTINUING OPERATIONS | | | (37,512 | ) | | | (42,070 | ) | | | (35,841 | ) |
OPERATIONS OF DISCONTINUED BUSINESSES: | | | | | | | | | | | | |
Loss from discontinued domestic oil and gas operations | | | (3,882 | ) | | | (480 | ) | | | (164 | ) |
Income from discontinued real estate operations | | | — | | | | — | | | | 315 | |
Minority interest of discontinued real estate operations | | | — | | | | — | | | | (99 | ) |
Gain on sale of discontinued real estate operations | | | — | | | | — | | | | 1,151 | |
| | | | | | | | | | | | |
INCOME (LOSS) FROM DISCONTINUED BUSINESSES | | | (3,882 | ) | | | (480 | ) | | | 1,203 | |
| | | | | | | | | | | | |
NET INCOME (LOSS) | | $ | (41,394 | ) | | $ | (42,550 | ) | | $ | (34,638 | ) |
| | | | | | | | | | | | |
BASIC AND DILUTED NET INCOME (LOSS) PER SHARE: | | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | (0.70 | ) | | $ | (0.97 | ) | | $ | (1.04 | ) |
Loss from discontinued domestic oil and gas operations | | | (0.07 | ) | | | (0.01 | ) | | | 0.00 | |
Income from discontinued real estate operations | | | 0.00 | | | | 0.00 | | | | 0.04 | |
| | | | | | | | | | | | |
Net income (loss) | | $ | (0.77 | ) | | $ | (0.98 | ) | | $ | (1.00 | ) |
| | | | | | | | | | | | |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | | | | | | | | | | | | |
Basic and diluted | | | 53,554 | | | | 43,318 | | | | 34,684 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated statements.
F-3
SYNTROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)
(in thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Common Stock | | | Additional
Paid-in
Capital | | | Notes
Receivable
Secured by
Common
Stock | | | Deferred
Compensation | | | Accumulated
Deficit | | | Treasury
Stock | | | Stockholders’ Equity (Deficit) | |
| | Number of
Shares | | | Amount | | | | | | | |
Balance, January 1, 2003 | | 40,435 | | | $ | 404 | | | $ | 161,546 | | | $ | (1,541 | ) | | $ | — | | | $ | (164,322 | ) | | $ | (77 | ) | | $ | (3,990 | ) |
Stock options exercised | | 197 | | | | 2 | | | | 475 | | | | — | | | | — | | | | — | | | | — | | | | 477 | |
Issuance of common stock and warrants | | 6,580 | | | | 66 | | | | 23,729 | | | | — | | | | — | | | | — | | | | — | | | | 23,795 | |
Stock-based compensation for consultants | | — | | | | — | | | | 85 | | | | — | | | | — | | | | — | | | | — | | | | 85 | |
Repayment of officer note receivable | | — | | | | — | | | | — | | | | 1,441 | | | | — | | | | — | | | | — | | | | 1,441 | |
Net income (loss) | | — | | | | — | | | | — | | | | — | | | | — | | | | (34,638 | ) | | | — | | | | (34,638 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2003 | | 47,212 | | | | 472 | | | | 185,835 | | | | (100 | ) | | | — | | | | (198,960 | ) | | | (77 | ) | | | (12,830 | ) |
Stock options exercised | | 265 | | | | 3 | | | | 704 | | | | — | | | | — | | | | — | | | | — | | | | 707 | |
Stock-based compensation for consultants | | — | | | | — | | | | 1,846 | | | | — | | | | — | | | | — | | | | — | | | | 1,846 | |
Issuance of common stock and warrants | | 6,917 | | | | 69 | | | | 37,077 | | | | — | | | | — | | | | — | | | | — | | | | 37,146 | |
Issuance of restricted common stock units | | — | | | | — | | | | 2,305 | | | | — | | | | (2,305 | ) | | | — | | | | — | | | | — | |
Vesting/cancellation of restricted common stock units | | 129 | | | | 1 | | | | (8 | ) | | | — | | | | 1,728 | | | | — | | | | — | | | | 1,721 | |
Purchase and retirement of common stock | | (41 | ) | | | — | | | | (238 | ) | | | — | | | | — | | | | — | | | | — | | | | (238 | ) |
Stock-based bonuses | | — | | | | — | | | | 774 | | | | — | | | | — | | | | — | | | | — | | | | 774 | |
Repayment of notes receivable from sale of common stock | | — | | | | — | | | | — | | | | 100 | | | | — | | | | — | | | | — | | | | 100 | |
Net income (loss) | | — | | | | — | | | | — | | | | — | | | | — | | | | (42,550 | ) | | | — | | | | (42,550 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2004 | | 54,482 | | | | 545 | | | | 228,295 | | | | — | | | | (577 | ) | | | (241,510 | ) | | | (77 | ) | | | (13,324 | ) |
Stock options exercised | | 256 | | | | 3 | | | | 794 | | | | — | | | | — | | | | — | | | | — | | | | 797 | |
Stock warrants exercised | | 233 | | | | 3 | | | | 1,074 | | | | — | | | | — | | | | — | | | | — | | | | 1,077 | |
Stock-based compensation for consultants | | — | | | | — | | | | 4,150 | | | | — | | | | — | | | | — | | | | — | | | | 4,150 | |
Issuance of common stock | | 8,000 | | | | 80 | | | | 79,838 | | | | — | | | | — | | | | — | | | | — | | | | 79,918 | |
Stock-based bonuses | | 330 | | | | 3 | | | | 3,829 | | | | — | | | | (2,850 | ) | | | — | | | | — | | | | 982 | |
Vesting/cancellation of restricted common stock units | | — | | | | — | | | | (31 | ) | | | — | | | | 838 | | | | — | | | | — | | | | 807 | |
Purchase and retirement of treasury stock | | (7,733 | ) | | | (78 | ) | | | (599 | ) | | | — | | | | — | | | | — | | | | 77 | | | | (600 | ) |
Net income (loss) | | — | | | | — | | | | — | | | | — | | | | — | | | | (41,394 | ) | | | — | | | | (41,394 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance, December 31, 2005 | | 55,568 | | | $ | 556 | | | $ | 317,350 | | | $ | — | | | $ | (2,589 | ) | | $ | (282,904 | ) | | $ | — | | | $ | 32,413 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated statements.
F-4
SYNTROLEUM CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| | | | | | | | | | | | |
| | | For the Year Ended December 31, | |
| | | 2005 | | | 2004 | | | 2003 | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | | | | | |
Net income (loss) | | $ | (41,394 | ) | | $ | (42,550 | ) | | $ | (34,638 | ) |
(Income) loss from discontinued businesses | | | 3,882 | | | | 480 | | | | (1,203 | ) |
| | | | | | | | | | | | |
Loss from continuing operations | | | (37,512 | ) | | | (42,070 | ) | | | (35,841 | ) |
Adjustments to reconcile net loss to net cash used in operating activities: | | | | | | | | | | | | |
Release of project equity contributions | | | — | | | | — | | | | (2,000 | ) |
Depreciation depletion, amortization and impairment | | | 5,064 | | | | 602 | | | | 639 | |
Foreign currency exchange | | | (750 | ) | | | 459 | | | | 7,893 | |
Non-cash compensation expense | | | 4,686 | | | | 4,341 | | | | 85 | |
Non-cash interest expense | | | 1,869 | | | | 1,697 | | | | — | |
Gain on sale of assets and interest in projects | | | (3,556 | ) | | | (23 | ) | | | (435 | ) |
Impairment of note receivable | | | — | | | | — | | | | 267 | |
Changes in assets and liabilities: | | | | | | | | | | | | |
Accounts and notes receivable | | | (428 | ) | | | 784 | | | | 3,073 | |
Catalyst materials | | | — | | | | 2,898 | | | | 7,855 | |
Other assets | | | (1,890 | ) | | | (521 | ) | | | (116 | ) |
Accounts payable | | | (250 | ) | | | (1,372 | ) | | | (1,736 | ) |
Accrued liabilities and other | | | 597 | | | | 874 | | | | 45 | |
Deferred revenue | | | (5,873 | ) | | | (11,157 | ) | | | (3,212 | ) |
| | | | | | | | | | | | |
Net cash used in continuing operations | | | (38,043 | ) | | | (43,488 | ) | | | (23,483 | ) |
Net cash provided by (used in) discontinued operations | | | (427 | ) | | | (147 | ) | | | 1,464 | |
| | | | | | | | | | | | |
Net cash used in operating activities | | | (38,470 | ) | | | (43,635 | ) | | | (22,019 | ) |
| | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | |
Purchase of property and equipment | | | (1,167 | ) | | | (907 | ) | | | (822 | ) |
Purchase of oil and gas assets | | | (13,669 | ) | | | (887 | ) | | | — | |
Proceeds from disposal or conveyance of property | | | 9,607 | | | | — | | | | 621 | |
Proceeds from note receivable | | | 7 | | | | — | | | | 93 | |
Decrease (increase) in restricted cash | | | (1,482 | ) | | | 25,428 | | | | (18 | ) |
Proceeds from sale of and changes in investments | | | — | | | | 121 | | | | 92 | |
| | | | | | | | | | | | |
Net cash provided by (used in) continuing operations | | | (6,704 | ) | | | 23,755 | | | | (34 | ) |
Net cash provided by (used in) discontinued operations | | | (1,238 | ) | | | (4,476 | ) | | | 2,974 | |
| | | | | | | | | | | | |
Net cash provided by (used in) investing activities | | | (7,942 | ) | | | 19,279 | | | | 2,940 | |
| | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | |
Proceeds from sale of common stock, warrants and option exercises | | | 81,792 | | | | 37,853 | | | | 24,272 | |
Stranded gas venture financing costs | | | (600 | ) | | | — | | | | — | |
Proceeds from stranded gas venture | | | 3,915 | | | | — | | | | — | |
Payment of debt and deferred credit | | | — | | | | (13,546 | ) | | | — | |
Proceeds from issuance of convertible debt | | | — | | | | 682 | | | | 17,376 | |
Settlement of Australia liability | | | — | | | | (1,397 | ) | | | — | |
Notes receivable from officers secured by common stock | | | — | | | | 100 | | | | 1,441 | |
Purchase and retirement of treasury stock | | | (600 | ) | | | (238 | ) | | | — | |
| | | | | | | | | | | | |
Net cash provided by continuing operations | | | 84,507 | | | | 23,454 | | | | 43,089 | |
Net cash used in discontinued operations | | | — | | | | — | | | | (60 | ) |
| | | | | | | | | | | | |
Net cash provided by financing activities | | | 84,507 | | | | 23,454 | | | | 43,029 | |
| | | | | | | | | | | | |
FOREIGN EXCHANGE EFFECT ON CASH | | | (5 | ) | | | (220 | ) | | | (5,866 | ) |
| | | | | | | | | | | | |
NET CHANGE IN CASH AND CASH EQUIVALENTS | | | 38,090 | | | | (1,122 | ) | | | 18,084 | |
CASH AND CASH EQUIVALENTS, beginning of period | | | 31,573 | | | | 32,695 | | | | 14,611 | |
| | | | | | | | | | | | |
CASH AND CASH EQUIVALENTS, end of period | | $ | 69,663 | | | $ | 31,573 | | | $ | 32,695 | |
| | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated statements.
F-5
SYNTROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 1. | SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: |
Nature of Operations
The primary operations of Syntroleum Corporation and subsidiaries (the “Company” or “Syntroleum”) to date have consisted of the research and development of a proprietary process (the “Syntroleum Process”) designed to convert natural gas or synthesis gas into synthetic liquid hydrocarbons (“gas-to-liquids” or “GTL”) and activities related to the commercialization of the Syntroleum Process. Synthetic liquid hydrocarbons produced by the Syntroleum Process can be further processed using the Syntroleum Synfining Process into high quality liquid fuels such as diesel, jet fuel, kerosene and naphtha, high quality specialty products such as synthetic lubricants, synthetic drilling fluid, waxes, liquid normal paraffin solvents and certain chemical feedstocks. The Company is also developing methods of applying its technology to convert synthesis gas derived from coal into these same high quality products (“coal-to-liquids” or “CTL”).
The Company’s current focus is to commercialize the Syntroleum Process and the Synfining Process through participation in projects that would utilize the Company’s technologies in the production of hydrocarbons. The Company is also focused on being a recognized provider of GTL and CTL technology to the energy industry through strategic partnerships and licensing of its technology. Syntroleum’s particular interests include projects in which the Company would be involved in the upstream field development of the feedstock for these plants.
The Company participated in the design and operation of a demonstration GTL plant located at ARCO’s Cherry Point refinery in Washington State. This demonstration plant was relocated to the Tulsa Port of Catoosa and is the basis for the Company’s Catoosa Demonstration Facility. This new GTL facility is designed to produce up to approximately 70 barrels per day (“b/d”) of synthetic products. As part of the U.S. Department of Energy (“DOE”) Ultra-Clean Fuels Project (“DOE Catoosa Project”), the fuels from this facility have been tested in bus fleets by the Washington Metropolitan Area Transit Authority and the U.S. National Park Service at Denali National Park in Alaska and by other project participants together with advanced power train and emission control technologies. The Company also owns and operates a two b/d pilot plant (“Tulsa Pilot Plant”) and various laboratory facilities in Tulsa, Oklahoma, which are used in demonstrating process performance and conducting various studies.
Consolidation
The consolidated financial statements include the accounts of the Company and its majority-owned subsidiaries. All significant inter-company accounts and transactions have been eliminated. Investments in affiliated companies of 20 percent to 50 percent in which Syntroleum does not have a controlling interest are accounted for by the equity method. The Company had no investments in affiliated companies of 20 percent to 50 percent as of December 31, 2005 or 2004. Investments in affiliated companies of less than 20 percent are accounted for by the cost method.
Revenue Recognition
The Company recognizes revenues from joint development activities as the related expenses are incurred because the contracts provide that revenue is earned as the expenses under the contract are incurred. Substantially all of the Company’s joint development revenues during the periods presented have been from joint development activities with several major oil companies (see Note 13), the DOE and the U.S. Department of Defense. All such joint development activities were pursuant to joint research and development agreements where the Company expenses its research and development costs as incurred.
License fee deposits received as cash upon the sale of master volume or regional license agreements are recorded as deferred revenue in the consolidated balance sheets until recognized as revenue in the consolidated statements of operations. The Company recognizes revenue on the sale of license agreements by recording 50 percent of the license fee deposit as revenue when: (1) a site license agreement has been formally executed, (2) the license fee deposit has been paid in cash and (3) the Company has delivered to the licensee the process design package for the licensee’s initial licensed plant. Since 50 percent of the license fee deposit is subject to the Company’s indemnity obligation with respect to the performance guarantee on the related plant, the remaining license fee deposit will be recognized as revenue in the consolidated statements of operations after the related plant
F-6
has passed certain performance tests. Option fees, which provide licensees the right to include additional geographic areas in its license agreement territory, are deferred until the earlier of the option being exercised or lapsing. The license agreements currently allow the Company to work with outside engineering contractors to develop a site-specific plant design in accordance with licensee specifications; this design package is called the Process Design Package, or “PDP,” and allows for a 100 percent cost recovery plus a 10 percent mark-up from the licensee. To date, the Company has not delivered any PDP’s for initial licensed plants. The Company is under no obligation to return these deferred revenues except in the case when a licensee builds a plant and the plant does not pass certain performance tests. In this situation, the licensee would be able to receive a refund of 50 percent of the license fees paid. The license agreements have a 15-year life and, after this time, the deferred revenue will be recorded as license revenue in the statements of operations unless a site license has been executed. The Company’s current licenses generally begin to expire in 2011 and the initial deposits will be recognized as licensing revenue as the licenses expire should a licensee not purchase a site license and begin construction of a plant prior to expiration of the license.
The Company sold a certain amount of the catalyst materials it had on-hand during the years ended December 31, 2004 and 2003. The revenues and costs of sales related to the sale of these materials were recorded in the statement of operations in the period in which the materials were sold. These catalyst materials were fully liquidated during the year ended December 31, 2004.
The Company expects to earn revenue from the sale of proprietary catalysts to licensees. The Company’s license agreements currently require catalyst to be used in the initial loading of the catalyst into the Fischer-Tropsch reactor for the licensee to receive a process guarantee. After the initial fill, the licensee may use other catalyst vendors if appropriate catalysts are available. The price for catalysts purchased from the Company pursuant to license agreements is equal to cost plus a specified margin. The Company will receive revenue from catalyst sales if and when the licensees purchase catalysts. The Company expects that catalysts will need to be replaced every three to five years. Revenues and costs of sales related to the sale of these materials will be recorded in the statement of operations in the period in which the materials are sold.
The Company has pursued and is pursuing projects in which the Company is directly involved in oil and gas field development and the processing of natural gas using various gas processing technologies. These include projects in which the Company would process developed gas on a fee basis and projects that may later evolve into integrated projects including development, production and processing of hydrocarbons using GTL and other technologies. Revenue from these projects will be recognized based on actual volumes processed for customers and sold to purchasers. The Company expects these projects will be pursued by the Company and with co-venturers through various arrangements. The Company anticipates receiving revenues from these projects, including sales of oil and gas from properties owned by the Company or jointly with another party, as well as processing and gathering fees from facilities in which the Company owns an interest.
The Company provides synthetic ultra-clean diesel fuel, such as our S-2 diesel fuel, produced from natural gas and FC-1 naphtha fuels to various customers for their use in further research and testing upon their request. The ultra-clean S-2 diesel fuel is a paraffinic, high-cetane distillate fuel that is essentially free of sulfur, olefins, metals, aromatics or alcohols. The fuels are currently produced at the Catoosa Demonstration Facility. Revenues are recognized upon delivery of the requested fuels and are recorded as other revenue.
Cash and Cash Equivalents and Restricted Cash
Cash and cash equivalents consist of cash and highly liquid investments with an original maturity of three months or less, primarily in the form of money market instruments. The Company’s cash and cash equivalents are held in a few financial institutions; however, management believes that the Company’s counter-party risks are minimal based on the reputation and history of the institutions selected.
The Company has restricted cash held in escrow at December 31, 2005 and December 31, 2004 related to its agreement with Sovereign Oil and Gas Company II, LLC (“Sovereign”), a consulting firm that has assisted the Company in acquiring oil and natural gas fields worldwide, in the amount of $1,684,000 and $202,000, respectively. The Company also had restricted cash held for lease acquisition purchases in the amount of $19,000 for the year ended December 31, 2004.
Accounts Receivable
The majority of the Company’s accounts receivable are due from joint development agreements with licensees or from government contracts. Accounts receivable are typically due within 30 days and are stated as
F-7
amounts due from customers. Accounts outstanding longer than the contractual payment terms are considered past due. The Company writes off accounts receivable when they become uncollectible. Management determines accounts to be uncollectible when the Company has used all reasonable means of collection and settlement. Management believes that all amounts included in accounts receivable at December 31, 2005 will be collected and therefore no allowance for uncollectible accounts has been recorded. There was also no allowance at December 31, 2004 and all outstanding receivables were collected.
Real Estate
On May 29, 2003, the Company entered into a formal agreement to sell its 75 percent ownership interest in undeveloped land and residential lots in Houston, Texas known as the “Houston Project” for total proceeds of $3,450,000 less a purchase price adjustment for lot sales from May 1 through closing. The Company’s interest was sold to Anthony L. Levinson, the owner of the remaining 25 percent interest in the project. As part of this agreement, the Company also retained the right to receive 75 percent of the Municipal Utility District Bond distribution that was expected to be received by the Houston Project, regardless of the time of distribution. On June 25, 2003, the Houston Project received approximately $860,000 from the Municipal Utility District Bond, of which $645,000 was paid to the Company.
On July 21, 2003, the Company completed the sale of its interest in the Houston Project and received approximately $3,049,000 in net proceeds. The Company received additional proceeds for the lot sales from May 1 to July 21 totaling $237,000. The proceeds from these sales were recorded as discontinued operations. The total amount received by the Company for the sale of its 75 percent ownership interest was $3,931,000, with a gain recognized from this sale of approximately $1,151,000. As a result of this sale, the Company no longer has any real estate inventory and will no longer have revenues from sales of real estate. The Company has recorded the impact of this business and the corresponding sale as operations of discontinued real estate business in the consolidated statements of operations for the year ended December 31, 2003. Revenue from the Houston Project totaled $1,068,000 for the year ended December 31, 2003.
Research and Development
The Company incurs significant costs for research, development and engineering programs. Expenses classified as research and development include salaries and wages, rent, utilities, equipment, engineering and outside testing and analytical work associated with our research, development and engineering programs. Since these costs are for research and development purposes, and not commercial or revenue producing, they are charged to expense when incurred in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 2,Accounting for Research and Development Costs. The total cost of research and development activities, including the operation and construction of the Catoosa Demonstration Facility totaled $22,444,000, $22,254,000, and $29,978,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
Property and Equipment
Property and equipment is stated at cost less accumulated depreciation. Maintenance, repairs and replacement of minor items are expensed and major additions, expansions and betterments to physical properties are capitalized, except those related to research and development activities, including the Catoosa Demonstration Facility and the Tulsa Pilot Plant, which are expensed. When assets are sold or retired, the cost and accumulated depreciation related to those assets are removed from the accounts and any gain or loss is recognized. Depreciation of property and equipment is computed on the straight-line method over the estimated useful lives of three to thirty-nine years. Property and equipment consists of the following (in thousands):
| | | | | | | | |
| | | December 31,
2005 | | | December 31,
2004 | |
Furniture and office equipment | | $ | 5,650 | | | $ | 4,865 | |
Buildings | | | 1,848 | | | | 1,518 | |
Land | | | 31 | | | | 31 | |
Leasehold improvements | | | 394 | | | | 373 | |
| | | | | | | | |
| | | 7,923 | | | | 6,787 | |
Less - accumulated depreciation | | | (4,964 | ) | | | (4,407 | ) |
| | | | | | | | |
| | $ | 2,959 | | | $ | 2,380 | |
| | | | | | | | |
F-8
Oil and Gas Properties
The Company follows the full cost method of accounting for exploration, development, and acquisition of oil and gas reserves. Under this method, all such costs (productive and nonproductive) including salaries, benefits, and other internal costs directly attributable to these activities are capitalized. These costs plus future development costs of undeveloped properties are amortized on an aggregate basis over the estimated lives of the properties using the units-of-production method on a country-by-country basis. The Company excludes all costs of unevaluated properties from immediate amortization. All of the costs that were unevaluated for the year ended December 31, 2005 related to either leasehold, geological and geophysical or acquisition-type costs. The Company will evaluate these costs at least quarterly, or when circumstances warrant, to determine if any of the costs should be included in the amortization computation. In accordance with SEC Staff Accounting Bulletin (“SAB”) No. 106, the Company excludes the future cash outflows associated with asset retirement obligations accrued on the balance sheets, if any, from the present value of future net revenues used in the ceiling limitation calculation. For purpose of computing depreciation, depletion and amortization the Company includes the estimated future expenditures for dismantlement and abandonment costs, net of salvage values, of proved undeveloped properties, if any, in the costs to be amortized. For each cost center, the Company’s unamortized costs of oil and gas properties are limited to the sum of the future net revenues attributable to proved oil and gas reserves discounted at 10 percent plus the lower of cost or market value of any unproved properties. If the Company’s unamortized costs in oil and gas properties exceed this ceiling amount, a provision for additional depreciation, depletion, amortization and impairment is required.
The Company’s investment in oil and gas activities consisted of the following, excluding activities in the United States, which are included in discontinued operations (in thousands):
| | | | | | | | | | | | |
| | | December 31, 2005 | |
| | | Nigeria | | | Other | | | Total | |
Evaluated properties | | $ | 4,365 | | | $ | 10 | | | $ | 4,375 | |
Unevaluated properties | | | 3,505 | | | | 1,009 | | | | 4,514 | |
| | | | | | | | | | | | |
Gross oil and gas properties | | | 7,870 | | | | 1,019 | | | | 8,889 | |
Accumulated depreciation, depletion, amortization, and Impairment | | | (4,365 | ) | | | (10 | ) | | | (4,375 | ) |
| | | | | | | | | | | | |
Net oil and gas properties | | $ | 3,505 | | | $ | 1,009 | | | $ | 4,514 | |
| | | | | | | | | | | | |
| |
| | | December 31, 2004 | |
| | | Nigeria | | | Other | | | Total | |
Evaluated properties | | $ | — | | | $ | — | | | $ | — | |
Unevaluated properties | | | 865 | | | | — | | | | 865 | |
| | | | | | | | | | | | |
Gross oil and gas properties | | | 865 | | | | — | | | | 865 | |
Accumulated depreciation, depletion, amortization, and Impairment | | | — | | | | — | | | | — | |
| | | | | | | | | | | | |
Net oil and gas properties | | $ | 865 | | | $ | — | | | $ | 865 | |
| | | | | | | | | | | | |
Nigeria. The Company’s Nigerian oil and gas activities have included leasehold acquisition, geological and geophysical work over various areas in Nigeria, and drilling costs for the Aje-3 Discovery Field (“Aje-3”) well in Oil Mining Lease (“OML”) 113 offshore Nigeria. All of the capitalized costs for Nigerian oil and gas activities have been for exploration purposes. Certain leasehold costs are considered to be unevaluated and are therefore excluded from amortization. No production from these properties has occurred as of December 31, 2005.
The Company’s Nigerian oil and gas activities include the acquisition of OML 113 offshore Nigeria. All costs associated with the acquisition of OML 113 were capitalized under the full cost accounting policy described above. The Company and Participants finalized various agreements in January 2005, to begin the delineation of the Aje Field discovery located in OML 113 offshore Nigeria. The Participants in OML 113 agreed to pay promoted costs to drill and test one delineation well in the Aje Field discovery and one option well in order to earn a participating interest in OML 113. The Company is required to pay 10 percent of the cost to drill and log the first two wells to retain a 32.5 percent cost-bearing working interest in the project. The Company also was granted an overriding royalty interest.
As a result of the approval of assignment and the drilling permit by the Nigerian government in April 2005, the Company received a cash bonus in the amount of $9,438,000 from certain Participants in the project as consideration for the conveyance of interests. The Company then made a bonus payment to Sovereign, one of the Company’s geological and geophysical consultants, in the amount of $3,719,000 in accordance with the Joint
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Development Agreement with Sovereign. The resulting net proceeds to the Company totaled $5,719,000. The Company also issued warrants to purchase 25,000 shares of the Company’s common stock to Sovereign. These warrants had a value of $157,000 on the date of grant using a Black-Scholes valuation. The bonus paid and warrants issued to Sovereign were initially capitalized to the Nigerian full cost pool as they are directly related to the acquisition of OML 113. The total acquisition costs related to OML 113 offshore Nigeria totaled $5,882,000, including the bonus payment made and warrants issued to Sovereign. The proceeds from the conveyance of interests to certain participants in the project was accounted for as an adjustment to the Nigerian full cost pool for costs incurred by the Company prior to the assignment. The Nigerian full cost pool was completely eliminated and a gain on conveyance of interest of $3,556,000 was recognized as other income during the year ended December 31, 2005.
The Participants in OML 113 agreed to pay promoted costs to drill and test one delineation well (Aje-3) in the Aje Field discovery and one option well in order to earn a participating interest in OML 113 as noted above. The first well, Aje-3, was drilled in 2005 to help further delineate the Aje Field in OML 113. The well reached its reservoir objectives as anticipated and a detailed logging program was acquired and interpreted. Test results were evaluated after drilling for consideration of commercial completion. The Participants found the economics for commercial completion to be unfavorable and the well was subsequently plugged and abandoned. The Company’s total drilling, logging, and dry hole costs of Aje-3 were $3,331,000 for the year ended December 31, 2005. The Company has recognized depletion, depreciation, amortization and impairment expense for the costs of drilling and testing this well in the year ended December 31, 2005. The Participants must decide on the drilling of the second well by September 30, 2006. Management plans to further explore within OML 113 in accordance with its agreement on OML 113.
The Company has participated in other activities in Nigeria, including geological and geophysical work within other areas of OML 113 and other areas of Nigeria. Management has reviewed its portfolio of projects and determined that no further development will occur on some of these properties. The amount of capitalized costs for these activities totaled $1,034,000 at December 31, 2005 and is considered to be evaluated. The Company has charged these costs for geological and geophysical work to depletion, depreciation, amortization and impairment expense for the year ended December 31, 2005. The amount of capitalized cost considered to be unevaluated as of December 31, 2005 totaled $3,505,000.
Other.The Company is participating in other international oil and gas activities. These activities primarily include geological and geophysical work in Indonesia, Malaysia, Sudan, Bangladesh, Singapore, and the United Arab Emirates. The total of capitalized costs associated with these activities totaled $1,019,000, of which $1,009,000 is considered to be unevaluated as of December 31, 2005.
Asset Retirement Obligations
The Company follows SFAS No. 143,Accounting for Asset Retirement Obligations, which requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The standard requires that the Company record the discounted fair value of the retirement obligation as a liability at the time a well is drilled or acquired. The asset retirement obligations consist primarily of costs associated with the future plugging and abandonment of oil and gas wells, site reclamation and facilities dismantlement. A corresponding amount is capitalized as part of the related property’s carrying amount. The discounted capitalized asset retirement cost is amortized to expense through the depreciation, depletion, and amortization calculation over the life of the asset. The liability accretes over time with a charge to accretion expense. The Company recognized an asset retirement obligation of approximately $11,000 related to total oil and gas properties using a 10 percent discount rate over the estimated life of the properties at December 31, 2004. This obligation was settled when these properties were abandoned or sold during the year ended December 31, 2005. There is no asset retirement obligation as of December 31, 2005.
Other Assets
Other assets consist primarily of costs associated with patents and are amortized using the straight-line method over their estimated period of benefit, ranging from fifteen to seventeen years. All costs are capitalized and amortization begins in the period in which the patent is approved. The Company periodically evaluates the recoverability of intangible assets and takes into account events or circumstances that warrant revised estimates of useful lives or that indicate that impairment exists. Future amortization expense for patents as of December 31, 2005 is estimated to be $100,000 per year through 2010. Other long-term assets include deposits and costs associated with the formation of the Stranded Gas Venture discussed in Note 14. These costs are amortized over the life of the Stranded Gas Venture, or six
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years, to interest expense. Other assets consist of the following (in thousands):
| | | | | | | | |
| | | December 31,
2005 | | | December 31,
2004 | |
Patents | | $ | 1,716 | | | $ | 1,576 | |
Investments – at cost | | | 27 | | | | 27 | |
Other long-term assets | | | 1,656 | | | | — | |
| | | | | | | | |
| | | 3,399 | | | | 1,603 | |
Less - accumulated amortization | | | (462 | ) | | | (350 | ) |
| | | | | | | | |
| | $ | 2,937 | | | $ | 1,253 | |
| | | | | | | | |
Income Taxes
Income taxes are accounted for using the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and of net operating loss carry-forwards. Deferred tax assets and liabilities are measured using the enacted tax rates and laws in effect or that will be in effect when the differences are expected to reverse. The Company records a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized.
Impairment of Assets
The Company follows the provisions of SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”),for assets other than its oil and gas properties. The Company makes assessments of impairment on a project-by-project basis. Management reviews assets for impairment when certain events have occurred that indicate that the asset may be impaired. An asset is considered to be impaired when the estimated undiscounted future cash flows are less than the carrying value of the asset. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future cash flows of a project.
During 2004 and 2003, the Company sold catalyst materials at the current market price at the time of each sale. In 2003, the Company recorded an impairment of its remaining catalyst materials as a result of a decline in the market value of these materials of $2,931,000, which is included in catalyst materials cost of sales in the accompanying consolidated statement of operations for the year ended December 31, 2003. As of December 31, 2005 and 2004 there were no catalyst materials for sale.
Stranded Gas Venture
The Company is a participant in the Stranded Gas Venture discussed in Note 14. The other participants of the Stranded Gas Venture provide funding for the evaluation and acquisition of oil and gas properties. The proceeds received from the other participants have been recognized as a Stranded Gas Venture liability in the accompanying consolidated balance sheet as of December 31, 2005. Interest is allocated to a portion of principal at an annual rate of 10 percent, compounded annually, in accordance with the Participation Agreement and is also included in the Stranded Gas Venture liability. Net cash proceeds received from the Company’s share of any project, including bonuses, or net revenues from the sale of production attributable to the Company’s working interest or overriding royalty interests in a project, less the payment of any operating expenses and maintenance capital expenditures, taxes, royalties or other required payments to a governmental entity, will be paid in certain percentages, as described in Note 14, to the participants reducing the Stranded Gas Venture liability.
Accounting for Guarantees
The Company follows the provisions of Financial Accounting Standards Board (“FASB”) Interpretation 45, Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (“FIN 45”) for any guarantees entered into after December 2002.Under FIN 45, the Company is required to record a liability for the fair value of the obligation undertaken in issuing the guarantees. No liabilities have been recognized for any of the guarantees described in Note 10 under FIN 45, because all of these items were entered into prior to December 2002.
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Earnings Per Share
Basic and diluted earnings (losses) per common share were computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the reporting period. Options and warrants to purchase 11,277,054, 8,439,649 and 7,231,838 shares of common stock at an average exercise price of $6.88, $5.68 and $5.31 per share were not included in the computation of diluted earnings (loss) per share for the years ended December 31, 2005, 2004 and 2003, respectively, as inclusion of these items would be anti-dilutive. Unvested restricted common stock units totaling 409,654 and 268,480 were also not included in the computation of diluted earnings (loss) per share for the years ended December 31, 2005 and 2004 as inclusion of these units would be anti-dilutive. There were no unvested restricted common stock units outstanding for the year ended December 31, 2003.
The number of shares that could be issued as a result of the convertible debt outstanding at December 31, 2005 and 2004 totals 4,320,794 and 4,036,794 shares of common stock, respectively, based on the minimum conversion rate of $6.00 per common share. These shares are excluded from this computation as they are anti-dilutive.
Stock-Based Compensation
Employee Stock-Based Compensation.The Company has stock-based compensation plans for employees, which are described more fully in Note 12. The Company has elected to follow the intrinsic-value method of accounting for stock-based compensation as prescribed by Accounting Principles Board Opinion (“APB”) No. 25,Accounting for Stock Issued to Employees.Additionally, the Company applies the disclosure-only provisions of SFAS No. 123,Accounting for Stock-Based Compensation (“SFAS 123”) as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure(“SFAS 148”), for options granted to employees.
No compensation cost has been recognized for stock options issued to employees under the stock option plans that qualify for “fixed” plan accounting. Compensation expense has been recognized for stock options that qualify for “variable” plan accounting because these options vest upon the achievement of certain performance criteria. The exercise price of all options granted to employees is greater than or equal to the market price of the Company’s stock on the date of grant.
Pursuant to the requirements of SFAS 123 and SFAS 148, the following disclosures are presented to reflect the Company’s pro forma net income (loss) for the three years in the period ended December 31, 2005 as if the fair value method of accounting prescribed by SFAS 123 had been used. Had compensation cost for options granted to employees under the Company’s stock option plans been determined consistent with the provisions of SFAS 123, the Company’s net income (loss) and income (loss) per share would have changed to the pro forma amounts indicated below, using the assumptions described below:
| | | | | | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | | | 2003 | |
| | | (in thousands, except per share data) | |
Net income (loss), as reported | | $ | (41,394 | ) | | $ | (42,550 | ) | | $ | (34,638 | ) |
Deduct: Total stock-based employee compensation expense determined under fair value based method for awards granted, modified, or settled | | | (3,534 | ) | | | (1,881 | ) | | | (2,835 | ) |
| | | | | | | | | | | | |
Pro forma net income (loss) | | $ | (44,928 | ) | | $ | (44,431 | ) | | $ | (37,473 | ) |
| | | | | | | | | | | | |
Earnings (loss) per share: | | | | | | | | | | | | |
Basic and diluted-as reported | | $ | (0.77 | ) | | $ | (0.98 | ) | | $ | (1.00 | ) |
Basic and diluted-pro forma | | $ | (0.84 | ) | | $ | (1.03 | ) | | $ | (1.08 | ) |
The fair values of options have been estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions:
| | | | | | | | | |
| | | 2005 | | | 2004 | | | 2003 | |
Expected dividend yield | | 0 | % | | 0 | % | | 0 | % |
Expected volatility | | 52 | % | | 54 | % | | 120 | % |
Risk-free interest rate | | 3.84 | % | | 3.57 | % | | 2.99 | % |
Expected life | | 5 yrs. | | | 5 yrs. | | | 7 yrs. | |
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The weighted average per share fair value at date of grant for options granted during 2005, 2004 and 2003 was $5.29, $3.12, and $2.11 per share, respectively.
Non-Employee Stock-Based Compensation. The Company also grants stock-based incentives to certain non-employees. These stock-based incentives are accounted for in accordance with SFAS No. 123, as amended, because the individuals receiving these instruments are not considered employees of the Company. These stock-based incentives have various vesting requirements, exercise prices and expiration dates. Certain stock-based incentives vest upon the achievement of certain performance goals associated with the consulting agreement. These stock-based incentives will be measured and expense will be recorded at the time these performance goals are met in accordance with Emerging Issues Task Forces Issue 96-18,Accounting for Equity Instruments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling, Goods or Services. Any stock options granted to non-employees that are not related to specific performance criteria are expensed over the period of vesting based on the assumptions described above. Compensation expense related to stock-based incentives granted to non-employees totaled $2,897,000, $1,846,000, and $85,000 for the years ended December 31, 2005, 2004 and 2003, respectively.
Defined Contribution Plan - 401(k)
The Company sponsors a defined contribution plan, named the Syntroleum 401(k) Plan (the “401(k) Plan”), covering virtually all employees of Syntroleum Corporation and its wholly-owned subsidiaries who have met the eligibility requirements. Employees of the Company may participate in the 401(k) Plan upon employment with the Company. Participants become eligible for Company matching and profit sharing contributions upon completion of more than 500 hours of service in the 401(k) Plan year. The 401(k) Plan is subject to the provisions of the Employee Retirement Income Security Act of 1974 (“ERISA”). The Company elected not to make any contributions to the 401(k) Plan for the years ended December 31, 2005, 2004 and 2003. Total administrative expenses paid by the Company for the years ended December 31, 2005, 2004 and 2003 were $2,000, $2,700 and $2,000, respectively.
Use of Estimates
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Some of the more significant estimates made by management include, but are not limited to, realization of notes receivable, impairment of catalyst materials, valuation of stock-based compensation and impairment of property and equipment. Actual results could differ from these estimates.
Foreign Currency Transactions
All of the Company’s subsidiaries use the U.S. dollar for their functional currency. Assets and liabilities denominated in other currencies are translated into U.S. dollars at the rate of exchange in effect at the balance sheet date. Transaction gains and losses that arise from exchange rate fluctuations applicable to transactions denominated in a currency other than the U.S. dollar are included in the results of operations as incurred.
New Accounting Pronouncements
On December 16, 2004, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 123 (revised 2004),Share-Based Payment (“SFAS 123(R)”), which amends SFAS 123 and SFAS 95Statement of Cash Flows. SFAS 123(R) requires companies to measure all employee stock-based compensation awards using a fair value method and record such expense in its consolidated financial statements. In addition, the adoption of SFAS 123(R) requires additional accounting and disclosure related to the income tax and cash flow effects resulting from share-based payment arrangements. SFAS 123(R) is effective for the Company as of January 1, 2006, the first day of the 2006 fiscal year. The Company will adopt SFAS 123(R) on the modified prospective basis as defined in the statement. Under this adoption method, the Company will record expense relating to employee stock-based compensation awards in the periods subsequent to adoption. This expense will be based on all unvested options as of the adoption date as well as all future stock-based compensation awards. Based on the current options outstanding, the Company’s 2006 pretax expense for those options is expected to be between $4,100,000 and $4,500,000. This amount may increase to the extent any options are granted in 2006.
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In December 2003, the FASB issued FASB Interpretation No. 46 (R), aConsolidation of Variable Interest Entities(“FIN 46R”), a revision of FASB Interpretation No. 46 and clarifies the application of Accounting Research Bulletin No. 51,Consolidated Financial Statements, to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have a sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. Application of this Interpretation is required for fiscal years ending after March 15, 2004. The Company has adopted FIN 46R as of December 31, 2005. Management has determined that the adoption of FIN 46R does not affect the financial statements as of December 31, 2005, as the Company does not have any variable interest entities to include in consolidation.
In March 2005, the FASB issued FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations (“FIN 47”), and interpretation of SFAS No. 143,Accounting for Asset Retirement Obligation. FIN 47 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. The interpretation is effective for fiscal years ending on or after December 15, 2005. The Company has adopted FIN 47 as of December 31, 2005. Management has determined that no liability exists for conditional asset retirement obligations as of December 31, 2005 and therefore there is no impact to the Company’s financial statements resulting from the adoption of FIN 47.
In May 2005, the FASB issued SFAS No. 154,Accounting for Changes and Error Corrections (“SFAS No. 154”), a replacement of APB Opinion No. 20,Accounting Changes, and FASB Statement No. 3,Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 requires that a voluntary change in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to do so. The new standard is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The Company adopted SFAS No. 154 as of September 30, 2005. There is no impact to the Company’s financial statements from the adoption of SFAS No. 154.
Reclassifications
Certain reclassifications have been made to the 2004 balance sheet and the 2004 and 2003 statements of operations and cash flows to conform to the 2005 presentation. These reclassifications had no impact on net income (loss).
| 2. | OPERATIONS AND LIQUIDITY: |
Construction of GTL and CTL plants and other activities, including exploration and production of energy assets and research and development programs in which the Company participates, will require significant capital expenditures by the Company. The Company may obtain funding through joint ventures, license agreements and other strategic alliances, as well as various other financing arrangements. The Company may also seek debt or equity financing in the capital markets. The Company has an effective registration statement for the proposed offering from time to time of shares of its common stock, preferred stock, debt securities, depositary shares or warrants for a remaining aggregate offering price of approximately $102,000,000. In the event such capital resources are not available to the Company, its GTL and CTL plant development and other activities may be curtailed.
If adequate funds are not available, the Company may be required to reduce, delay or eliminate expenditures for these capital projects, as well as its research and development and other activities, or seek to enter into a business combination transaction with or sell assets to another company. The Company could also be forced to license to third parties the rights to commercialize additional products or technologies that it would otherwise seek to develop itself. If the Company obtains additional funds by issuing equity securities, dilution to stockholders may occur. In addition, preferred stock could be issued in the future without stockholder approval and the terms of the preferred stock could include dividend, liquidation, conversion, voting and other rights that are more favorable than the rights of the holders of the Company’s common stock. The transactions outlined above may not be available to the Company when needed or on terms acceptable or favorable to the Company.
| 3. | DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE |
The Company’s oil and gas activities in the United States have included the acquisition of oil and gas leases in the Central Kansas Uplift, geological and geophysical work, drilling and completion of eight wells and the re-entry of three wells. The Company also acquired gas processing equipment, including a gas processing plant that was intended to be used in the Central Kansas Uplift. In October 2005, management completed an evaluation of the potential
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reserves and the economics related to these properties and decided to focus its efforts on aligning the Company with specific goals and projects that have GTL and CTL potential. As a result, management decided to discontinue further expenditures in the Central Kansas Uplift area and began disposing of these properties. The net effect of the United States oil and gas activities, including the related gas processing plant and equipment, is presented as discontinued operations in the financial statements for the years ended December 31, 2005, 2004, and 2003 in accordance with SFAS No. 144.
Oil and Gas Properties. Certain leasehold acres in the area were sold in November 2005 for $1,000,000. The proceeds from this sale were accounted for as a reduction in the full cost pool. The remaining leasehold acreage, including the wells and well equipment, was sold for $522,000 subsequent to December 31, 2005. The assets related to the domestic oil and gas operations have been accounted for as assets held for sale in the consolidated balance sheets. The December 31, 2004 consolidated balance sheet has been reclassified accordingly. The Company no longer has any oil and gas properties in the United States subsequent to the year ended December 31, 2005.
The Company had recognized depreciation, depletion, amortization and impairment expense of $3,045,000 related to these properties during the year ended December 31, 2005 based on the limited production during the year and the potential reserves using the units-of-production method and impairment evaluation under the full cost method of accounting. This is included in loss from discontinued domestic oil and gas operations in the consolidated statement of operations.
Gas Processing Equipment. The Company recorded an impairment of approximately $692,000 related to its gas processing plant and equipment during the year ended December 31, 2005 which is reflected in loss from discontinued domestic oil and gas operations. The write down included costs associated with engineering, design, the gas processing plant and other gas processing equipment. The processing plant and equipment is considered held for sale as of December 31, 2005 at an estimated fair value of $1,359,000. Management is actively seeking interested parties for the sale of this plant and related equipment. Management expects to finalize the sale of these assets in 2006.
| 4. | NOTES RECEIVABLE RELATED TO COMMON STOCK: |
The Company loaned Kenneth L. Agee, the Company’s Chairman and former Chief Executive Officer, a total of $1,441,000 under a promissory note at various times prior to January 1, 2003. This promissory note was full recourse, bore interest at the rate of 6 percent and was secured by shares of the Company’s common stock owned by Mr. Agee. At the maturity of the promissory note on June 25, 2003, Mr. Agee paid the Company for the entire outstanding balance of the loans, including accrued interest. As a result of this transaction, the Company has no additional loans outstanding with Mr. Agee.
The Company loaned Larry J. Weick, the Company’s Senior Vice President of Business Development, a total of $100,000 under a promissory note which was full recourse, bore interest at the rate of 6.1 percent and was secured by shares of the Company’s common stock owned by Mr. Weick. In May 2004, Mr. Weick paid the Company for the entire outstanding balance of the loan, including accrued interest. As a result of this transaction, the Company has no additional loans outstanding with any directors or officers of the Company.
In February 2000, the Company sold its parking garage in Reno, Nevada to Fitzgerald’s Reno, Inc. (“FRI”), a Nevada corporation doing business as Fitzgerald’s Hotel & Casino Reno, for $3,000,000. FRI paid $750,000 in cash and executed a promissory note in the original principal amount of $2,250,000 and interest rate of 10 percent per year (based on a twenty-year amortization). The note was payable in monthly installments of principal and interest, with the entire unpaid balance due on February 1, 2010. The note was secured by a deed of trust, assignment of rents and security interest in favor of the Company on the parking garage. FRI also executed an Assumption and Assignment of Ground Lease dated February 1, 2000, under which FRI agreed to make the lease payments due under the ground lease. FRI’s obligations under the Assumption and Assignment of Ground Lease are secured by the deed of trust, assignment of rents and security interest in the parking garage and the ground lease.
In December 2000, FRI, along with several affiliates, filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court, District of Nevada. Since the date of its bankruptcy petition, FRI has continued to make the monthly payments due on the note and the payment obligations due under the ground lease.
On August 28, 2003, the bankruptcy plan filed by FRI went into effect and FRI agreed to pay the Company $50,000 to be applied towards the outstanding principal balance of the promissory note. FRI then issued a new note
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in the amount of $2,068,000, which was the balance outstanding on the original note at that time, under the same terms and conditions as the original promissory note, except that the maturity date was accelerated to August 28, 2006 and the interest rate was reduced to 5 percent, with principal payments prior to maturity based on a 16-year amortization schedule. The remaining unpaid balance is due August 28, 2006. As a result of the restructuring of this note, and in accordance with SFAS No. 114,Accounting by Creditors for Impairment of a Loan - an Amendment of FASB Statements No. 5 and 15, the Company recorded an impairment of $267,000 in 2003. FRI executed an amended and restated deed of trust under the same terms and conditions as the previous deed of trust. FRI is required to continue to make the lease payments due under the ground lease under the same terms as originally agreed in the Assumption and Assignment of Ground Lease dated February 1, 2000.
The Company will continue to closely monitor the payments made by FRI under the note and the ground lease to ensure that, should a default occur, notice of default will be properly provided and the note would be reviewed for impairment. Management believes that the Company will ultimately collect the balance of the note receivable, and accordingly, the Company has not recorded an additional reserve for uncollectible amounts as of December 31, 2005.
In May 2002, the Company signed a Participation Agreement with Marathon Oil Company (“Marathon”) in connection with the DOE Catoosa Project. This agreement requires Marathon to reimburse the Company for up to $5 million in project costs and to provide up to $3 million in Marathon personnel contributions. Marathon is entitled to credit these contributions against future license fees in specified circumstances. As of December 31, 2005, the Company had received reimbursement of $5 million of project costs ($1 million of which is included in deferred revenue as a fuel delivery commitment) and $3 million in personnel contributions.
Marathon also agreed to provide project funding pursuant to advances under a $21.3 million secured promissory note with the Company. The promissory note bears interest at a rate of eight percent per year and the maturity date was extended in March 2005 to June 30, 2006. The current balance of $25.9 million, which includes accrued interest, has been included in current liabilities in the accompanying consolidated balance sheet as of December 31, 2005. If the Company obtains capital for the project from a third party, these capital contributions will be required to be applied towards the outstanding principal and interest of the note. The only other form of repayment to Marathon is its right to convert the promissory note into credits against future license fees or into the Company’s common stock at no less than $6.00 per share and no more than $8.50 per share. Under certain circumstances, the Company may also elect to repay the note in cash. The promissory note is secured by a mortgage on the assets of the project that would allow Marathon to complete the project in the event of a default by the Company. Events of default under the promissory note include failure by the Company to comply with the terms of the promissory note, events of bankruptcy of the Company, a material adverse effect on the Company, a change of control of the Company and the Company’s current assets minus current liabilities falling below $10 million, excluding amounts due under the promissory note and liabilities associated with prepaid license fees. The Company was in compliance with the provisions of the note as of December 31, 2005.
In August 2000, the Company signed a non-exclusive license agreement with the Commonwealth of Australia, granting the Commonwealth the right to utilize the Syntroleum Process. Under the license agreement, the Commonwealth has paid the Company a license fee in the amount of AUD $30 million, half of which was being held in escrow and would be distributed to the Company upon satisfaction of certain conditions relating to the development of GTL technologies in Australia. As satisfaction of certain conditions did not occur (see Note 15), all of the funds that were held in escrow accounts in Australia related to advances on the loan and the license agreement, plus all interest earned on these funds since the suspension of the project and other associated costs, were returned to the Commonwealth of Australia in September 2004. As of December 31, 2005 and 2004, the Company has a remaining license agreement with the Commonwealth of Australia that includes credits against future license fees in the amount of AUD $15 million. This license has been recorded as deferred revenue of $11.0 million and $11.7 million as of December 31, 2005 and 2004, respectively. The license agreement is denominated in Australian dollars and is subject to changes in foreign currency. During the years ended December 31, 2005, 2004 and 2003, the foreign currency effect on the Company’s deferred revenues was a change of ($750,000), $522,000 and $5,610,000 respectively, as a result of changes in the exchange rate between the United States and Australian dollars.
On June 18, 2003, the Company entered into an Agreement in Principle for GTL Project Development with one of its licensees, Ivanhoe Energy, Inc. (“Ivanhoe”), which modified certain terms included in the Master License
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Agreement dated April 26, 2000, and amended October 11, 2000 and June 1, 2002, between the Company and the licensee. The licensee had previously paid $10 million as license fee deposits, which were recorded as deferred revenue in accordance with the Company’s revenue recognition policy. Under this modification, the licensee will retain its rights under the Master License Agreement to use the Syntroleum Process and other technology developed by the Company. However, the licensee’s rights to receive a credit against future license fees and the related indemnifications as it relates to the $10 million deposit have been terminated. The licensee also agreed to the release of equity contributions for certain projects totaling $2 million. These items were forfeited as reimbursement to the Company for certain research and development projects completed on the licensee’s behalf. As a result of this agreement and in accordance with the Company’s revenue recognition policies, the Company recognized $10 million previously recorded in deferred revenue and $2 million previously recorded in minority interests in projects as joint development revenue during 2003.
The Company recognized joint development revenues previously recorded in deferred revenue related to the completion of the fuel production and delivery commitments in connection with the DOE Catoosa Project in the amount of $5,798,000 during the year ended December 31, 2005. The Company has recorded deferred revenue of $1,000,000 as of December 31, 2005 related to its agreement with Marathon as discussed in Note 6.
Private Placements and Public Offerings.On February 10, 2003, the Company sold in a private placement one million shares of its common stock and warrants to purchase additional shares of common stock for a total of $3 million. The warrants had a fair market value of approximately $961,000 at the date of issuance and were recorded as additional paid-in capital in the accompanying financial statements. The warrants allowed for the purchase of an additional one million shares of the Company’s common stock at an exercise price of $6.00 per share and were exercised on December 29, 2004. Additionally, in October 2003, the Company sold in a private placement 400,000 shares of its common stock to a consultant of the Company and received net proceeds of $1.8 million.
On November 4, 2003, the Company completed the sale of 5,180,000 shares of common stock and warrants to purchase 1,554,000 shares of common stock pursuant to a public offering at a price to the public of $3.95 per share and 30 percent of a warrant. Each warrant is exercisable at a price of $5.00 per share of common stock beginning on the date of issuance and expiring November 4, 2007. The warrants were deemed to have a fair market value of approximately $2.6 million at the date of issuance and were recorded as additional paid-in capital. The Company received net proceeds of approximately $19.0 million after the underwriting discount and offering expenses.
On May 26, 2004, the Company completed the sale of 5,916,000 shares of common stock and warrants to purchase 887,400 shares of common stock pursuant to a public offering at a price to the public of $5.60 per share and 15 percent of a warrant. Each warrant is exercisable initially at a price of $7.60 per share of common stock beginning on the date of issuance and ending on May 26, 2008. The warrants were deemed to have a fair market value of approximately $1.9 million at the date of issuance and were recorded as additional paid-in capital. The Company received net proceeds of approximately $31.1 million after underwriting discount and offering expenses.
On March 17, 2005, the Company completed the sale of 7,000,000 shares of common stock at a price of $10.00 per share. The Company sold all of these shares directly to Legg Mason Opportunity Trust, a series of Legg Mason Investment Trust, Inc., a registered investment company. The sale resulted in net proceeds to the Company of approximately $69,950,000.
On April 14, 2005, the Company completed the sale of 1,000,000 shares of common stock at a price of $10.00 per share. The Company sold all of these shares directly to Dorset Group Corporation (“Dorset”). The sales resulted in net proceeds to the Company of approximately $9,968,000.
TI Capital Management.The Company has issued warrants to purchase up to 2,170,000 shares of the Company’s common stock to TI Capital Management, a firm owned by Mr. Ziad Ghandour, a director of and consultant to the Company, pursuant to an amended and restated consulting agreement. In October 2005, Mr. Ziad Ghandour became a full time employee of the Company. This has no effect on the treatment of warrants issued or stock granted to TI Capital Management prior to his employment. These warrants vest upon the achievement of various criteria in the agreement. All warrants associated with the consulting agreement will expire on November 4, 2007.
In October 2004, the Company amended its consulting agreement with TI Capital Management to provide that in connection with the closing of a financing with a company introduced to Syntroleum by TI Capital
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Management, the Company will pay, assuming stockholder approval in accordance with the requirements of the Nasdaq National Market, a number of shares of the Company’s common stock equal to 1 percent of the net proceeds that the Company receives in connection with such financing divided by $5.79 per share. If stockholder approval is not received, the Company will pay an amount of cash equal to the market value on the date of such closing of the number of shares that he would have received had the stockholders approved the issuance of common stock, provided that the closing occurs by a later date as the Company, in its sole discretion, may designate. The cash payment will be made promptly after the meeting of stockholders at which the proposal to approve the issuance of the shares is submitted. The Company will apply the provisions of SFAS 123 in recording compensation expense for any shares of the Company’s common stock issued under this agreement at the time those shares are issued.
On April 25, 2005, the Company’s stockholders approved an amendment to the Company’s consulting agreement with TI Capital Management, which provides for the issuance of cash, common stock and warrants to purchase common stock as compensation upon the achievement of various goals set forth in the agreement. The payment of compensation under the agreement is subject to the satisfaction of specific criteria.
In February 2006, the Company amended its consulting agreement with TI Capital Management to provide that in connection with the closing of a financing of a Syntroleum GTL Plant involving capital provided by a company introduced to Syntroleum by TI Capital Management, the Company will pay TI Capital Management an amount equal to 1.5 percent of the total equity and debt financing provided by parties introduced to the transaction by TI Capital Management for each of the first two GTL units, provided that the cumulative amount of the two payments does not exceed $50,000,000. Capital provided by the Syntroleum is specifically excluded from the compensation to TI Capital Management.
TI Capital Management earned warrants to purchase 500,000 shares of the Company’s common stock as a result of the Company’s agreements with Dragados Industrial S.A. in September 2004 and warrants to purchase an additional 500,000 shares of common stock as a result of the Company’s agreement with Bluewater Energy Services B.V. in February 2005. Warrants to purchase 170,000 shares of common stock vested upon approval of TI Capital Management’s consulting agreement by shareholders in April 2004. Other compensation paid to TI Capital Management includes cash paid and shares of common stock issued in connection with the formation of the Stranded Gas Venture discussed in Note 14.
The following tables summarize the equity-based and other compensation related to the Company’s agreements with TI Capital Management:
| | | | | | | | | | | | | | | |
| Warrants |
| Granted | | Exercised |
Date of Grant | | Warrants
Granted | | Exercise
Price | | Valuation at
Grant | | Date
Exercised | | Warrants
Exercised | | Proceeds |
| 2/23/2005 | | 500,000 | | $ | 5.25 | | $ | 2,759,000 | | — | | — | | $ | — |
| 9/7/2004 | | 500,000 | | $ | 4.50 | | | 969,000 | | 1/24/2005 | | 200,000 | | | 900,000 |
| 4/26/2004 | | 170,000 | | $ | 5.00 | | | 636,000 | | — | | — | | | — |
| | | | | | | | | | | | | | | |
| Total | | 1,170,000 | | | | | $ | 4,364,000 | | | | 200,000 | | $ | 900,000 |
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
|
| Other Compensation |
| Shares of Common Stock Granted | | Cash Bonuses Paid |
Date of Grant | | Shares
Granted | | Value Per
Share | | Valuation | | Date Paid | | Amount |
| 10/3/2005 | | 17,271 | | $ | 7.87 | | $ | 136,000 | | 10/24/2005 | | $ | 100,000 |
| 4/25/2005 | | 86,356 | | $ | 10.26 | | | 886,000 | | 5/3/2005 | | | 500,000 |
| | | | | | | | | | | | | |
| Total | | 103,627 | | | | | $ | 1,022,000 | | | | $ | 600,000 |
| | | | | | | | | | | | | |
Sovereign Oil & Gas Company II, LLC.In March 2004, the Company entered into a joint development agreement with Sovereign Oil & Gas Company II, LLC (“Sovereign”), a geological and reservoir engineering firm that the Company has retained to assist it in acquiring rights to previously discovered oil and natural gas that may lead to commercial production, including the potential deployment of Syntroleum GTL Technology.
Under the agreement, the Company agreed, under certain circumstances, to issue Sovereign warrants to purchase shares of the Company’s common stock. These warrants are exercisable for five years beginning on the
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date of stockholder approval, which was received on April 26, 2004. In addition, under the agreement, the Company is required to issue warrants to purchase 25,000 shares upon the acquisition of an interest in a property proposed by Sovereign, the acquisition from the Company by another company of such property or the execution of an agreement by the Company and another company regarding joint participation in the project involving such a property, exercisable five years from the acquisition or agreement date. If the Company and Sovereign do not receive a cash bonus or overriding royalty interest in connection with the acquisition from the Company by another company of such property or the execution of an agreement by the Company and another company regarding the Company’s joint participation in the project involving such a property, the Company will issue an additional 25,000 warrants exercisable for five years from the acquisition or agreement date plus an additional 50,000 warrants exercisable for five years from the date of first production of hydrocarbons from the property. The Company is required under the agreement to issue warrants to Sovereign to purchase 12,500 shares upon the Company’s acquisition of an interest in a property proposed by the Company and accepted by Sovereign or for which the Company initiated negotiations, the acquisition from the Company by another company of such property or the execution of an agreement by the Company and another company regarding participation in the project involving such a property, exercisable for five years from the acquisition or agreement date.
The Company has agreed to amend, subject to shareholder approval, the joint development agreement with Sovereign to change the exercise price of warrants issued to the closing per share sale price of our common stock as of December 1 prior to a contract year in which warrants are issued. This amendment was made because this is the day that Syntroleum must give notice to Sovereign of continuation or termination of the joint development agreement for the next contract year. This amendment is subject to shareholder approval at the Company’s annual meeting in April 2006. For the 2005 and 2006 contract years, the exercise price is $6.94 and $7.98 per share, respectively. Assuming shareholder approval, the exercise price for the 25,000 warrants to purchase shares of common stock granted in November 2005 noted in the table below will change from $11.16 to $6.94 per share. This would result in a change in the valuation for these warrants of approximately $26,000.
No more than 2,000,000 shares of the Company’s common stock are issuable upon exercise of the warrants issued pursuant to the agreement. Sovereign has assisted in acquiring interest in properties, resulting in a certain number of warrants to be granted.
Sovereign was been granted warrants to purchase 25,000 shares of the Company’s common stock in September 2004 and an additional 25,000 warrants to purchase shares of common stock in April 2005 for work completed on OML 113 offshore Nigeria. Sovereign was granted warrants to purchase 25,000 shares of common stock in November 2005 in connection with the signing of a Heads of Agreement on OML 90 offshore Nigeria. Upon approval of the joint development agreement with Sovereign in April 2004, the Company issued Sovereign warrants to purchase 50,000 shares of common stock.
The following tables summarize the equity-based compensation related to the Company’s agreements with Sovereign.
| | | | | | | | | | | | | | | |
| Warrants Granted | | Warrants Exercised |
Date of Grant | | Warrants Granted | | Exercise Price | | Valuation at
Grant | | Date Exercised | | Warrants Exercised | | Proceeds |
| 11/28/2005 | | 25,000 | | $ | 11.16 | | $ | 75,000 | | | | — | | $ | — |
| 4/14/2005 | | 25,000 | | $ | 6.40 | | | 157,000 | | | | — | | | — |
| 9/7/2004 | | 25,000 | | $ | 6.40 | | | 75,000 | | | | — | | | — |
| 4/26/2004 | | 50,000 | | $ | 6.40 | | | 165,000 | | 1/28/2005 | | 8,750 | | | 56,000 |
| | | | | | | | | | | | | | | |
| Total | | 125,000 | | | | | $ | 472,000 | | | | 8,750 | | $ | 56,000 |
| | | | | | | | | | | | | | | |
Retirement of Treasury Stock.The Company offers its employees the option to swap shares of common stock issued for compensation to settle the employees’ tax liability. The shares that are traded are subsequently cancelled by the Company. The Company repurchased and cancelled approximately 58,036 shares for $600,000 during the year ended December 31, 2005 and 41,162 shares for $238,000 during the year ended December 31, 2004. No shares were repurchased or cancelled during the year ended December 31, 2003.
The Company held 7,675,000 shares in treasury as of December 31, 2004. These shares were held by BMA Resources, a subsidiary of SLH Corporation, and became the property of Syntroleum as a result of the merger between Syntroleum Corporation and SLH Corporation. SLH Corporation was the surviving entity of the merger and was renamed Syntroleum Corporation. These shares were cancelled during the year ended December 31, 2005.
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The Company has federal income tax net operating loss (NOL) carry-forwards of approximately $274 million at December 31, 2005. The Company’s NOLs generally begin to expire as follows:
| | | |
Year | | Amount |
| | | (in thousands) |
2006 | | $ | 340 |
2007 | | | 864 |
2008 | | | 267 |
2009 | | | 320 |
2010 | | | 1,026 |
Thereafter | | | 271,256 |
The Company recognizes the tax benefit of NOL carry-forwards as assets to the extent that management concludes that the realization of the NOL carry-forwards is “more likely than not.” Realization of the future tax benefits is dependent on the Company’s ability to generate taxable income within the carry-forward period. The Company’s management has concluded that, based on the historical results of the Company, a valuation allowance should be provided for the entire balance of the net deferred tax asset.
The Company has not recorded an income tax provision or benefit for the years ended December 31, 2005, 2004 and 2003. This differs from the amount of income tax benefit that would result from applying the 35 percent statutory federal income tax rate to the pretax loss due to the increase in the valuation allowance in each period. The valuation allowance increased by approximately $19,206,000, $17,326,000, and $13,151,000 for the years ended December 31, 2005, 2004 and 2003, respectively. Deferred taxes arise primarily from NOL carry-forwards and the recognition of revenues and expenses in different periods for financial and tax purposes.
Deferred taxes consist of the following (in thousands):
| | | | | | | | |
| | | December 31, | |
| | | 2005 | | | 2004 | |
Deferred tax assets: | | | | | | | | |
NOL carry-forwards | | $ | 104,120 | | | $ | 89,127 | |
Capital loss carry-forwards | | | 1,626 | | | | 1,650 | |
Research and development credit | | | 7,758 | | | | 6,146 | |
Deferred revenue | | | 5,081 | | | | 7,312 | |
Investments | | | 326 | | | | 329 | |
Oil and gas properties | | | 3,391 | | | | — | |
Stranded gas venture | | | 1,488 | | | | — | |
Stock-based compensation | | | 2,147 | | | | 1,397 | |
Other | | | 484 | | | | 841 | |
| | | | | | | | |
| | | 126,421 | | | | 106,802 | |
Deferred tax liabilities: | | | | | | | | |
Other | | | (871 | ) | | | (458 | ) |
| | | | | | | | |
Net deferred tax asset before valuation allowance | | | 125,550 | | | | 106,344 | |
Valuation allowance | | | (125,550 | ) | | | (106,344 | ) |
| | | | | | | | |
Net deferred tax assets | | $ | — | | | $ | — | |
| | | | | | | | |
The Company’s capital loss carry-forwards generally begin to expire in 2008.
During 2004 and 2003, the Company made Australian withholding tax payments in the amount of $12,000 and $60,000, respectively, for Australian sourced income. These taxes were withheld by the Commonwealth of Australia upon the Commonwealth’s payment of advances under the loan agreement and by the Australian bank upon payments of interest on these monies. Under the Australian tax treaty with the U.S., the payor is required to
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withhold 10 percent on Australian sourced revenue and to remit it to the Australian tax authorities. No Australian withholding tax payments were made in 2005.
| 10. | COMMITMENTS AND CONTINGENCIES: |
The Company has entered into various, non-cancelable operating leases for office space, equipment, land and buildings that expire between 2006 and 2023. Rental expense was $836,000 in 2005, $1,331,000 in 2004, and $1,300,000 in 2003. Total future minimum lease payments under these agreements as of December 31, 2005 are as follows:
| | | |
Year | | Amount |
| | | (in thousands) |
2006 | | $ | 972 |
2007 | | | 857 |
2008 | | | 530 |
2009 | | | 422 |
2010 | | | 388 |
Thereafter | | | 4,249 |
The Company has entered into employment agreements, which provide severance benefits to several key employees. Commitments under these agreements totaled approximately $5,449,000 at December 31, 2005.
Subsequent to December 31, 2005, the Company entered into an agreement with a third party regarding the potential development of an oil and gas discovery. The Company was required to provide a letter of credit equaling $2.5 million. The letter of credit was put into place in January 2006 and is secured by cash.
The Company is subject to contingent obligations under leases and other agreements incurred in connection with real estate activities and other operations conducted by SLH Corporation (“SLH”) prior to its merger with Syntroleum. Through its merger with SLH, the Company acquired Scout Development Corporation (“Scout”). Scout is a successor guarantor on two sets of leases; a land lease and subleases in Hawaii and a land lease in Reno, Nevada.
The Hawaii obligations arise out of certain land leases and subleases that were entered into by Business Men’s Assurance Company of America (“BMAA”) and Bankers Life of Nebraska (now known as “Ameritas Life”) in connection with the development of the Hyatt Regency Waikiki Hotel (“Hyatt Hotel”). The Hyatt Hotel was subsequently sold and the land was subleased to the purchasing party. During 1990, in connection with the sale of BMAA, Lab Holdings, Inc. (“Lab Holdings”) gave an indemnity to the purchaser against liabilities that may arise from the subject leases. Also during 1990, Lab Holdings transferred its right title and interest to the subject leases to Scout. If the Hyatt Hotel were to default on the leases, Scout could be liable for the lease obligations.
The current rent payments for the subject leases are $826,000 per year. The lease amount is fixed until 2006, when the payments will be renegotiated and increased based upon a stipulated formula, the product of which is the fair market value of the land, times a minimum market rate of return of seven percent. The Company projects that beginning in 2008 (the first full year following the renegotiation); rent payments will be $4,524,000 per year. This projection was based on assessed property values and certain clauses in the lease agreement. Subsequent renegotiations will occur in 2017, 2027 and 2037, subject to the same formula. This lease expires in 2047. The total lease payments through 2047, based on estimated increases, are $269,151,000. In the event of default by the property owner, the risk of these lease obligations would be shared with others. In addition to Scout, Ameritas Life shares equally in the lease obligations. LabOne Corporation (formerly known as Home Office Reference Laboratory), as a result of its merger with Lab Holdings, may also be liable for the lease obligations.
The Hyatt Hotel has an estimated market value, based on a 1998 appraisal, of $396,000,000. The property tax records indicate a fair market value for the hotel and the land of $244,143,000. The Hyatt Hotel had gross revenues of $92,800,000 subject to the lease agreement for the year ended May 31, 2005.
In December 2005, management learned through the Steiner Trust and Hawaii counsel that the owner of the Hyatt Hotel, Azabu Buildings Co., Ltd. (“Azabu”) has been petitioned for an involuntary Chapter 11 bankruptcy by Beecher Limited and others, creditors of Azabu in various business ventures. Subsequent to December 31, 2005, Azabu filed for Chapter 11 bankruptcy. Management believes that based on the performance of this asset, that the bankruptcy court would more than likely require Azabu to continue to make all required rent payments in order for
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the hotel to continue operations. Based on the appraised value of the Hyatt Hotel and management’s evaluation of this contingency, management considers the risk or default by the Hyatt Hotel on the lease obligations to be remote and accordingly, has not recorded any liability in its consolidated balance sheets at December 31, 2005 or 2004.
Scout is also subject to lease obligations under a land lease for the Reno parking garage. This property was sold in 2000; however, Scout was not released from the land lease by the landowner (see Note 5). This lease requires total remaining lease payments of $5,784,000 and will expire in August 2023. The property is currently owned by FRI and they continue to make the ground lease payments monthly. Should FRI default on its obligations, then Scout would have rights to claim the parking garage and sell the asset. Management believes that the sale of the asset and the assignment of the ground lease to the buyer would cover the contingent liability exposure for this lease. Management considers the likelihood of default by FRI under the lease obligations to be remote, and accordingly has not recorded any liability in its consolidated balance sheets at December 31, 2005 or 2004.
The Company’s license agreements require it to indemnify its licensees, subject to a cap of 50 percent of the related license fees, against specified losses. Specified losses include the use of patent rights and technical information relating to the Syntroleum Process, acts or omissions by the Company in connection with the preparation of PDPs for licensee plants and performance guarantees related to plants constructed by licensees. Consistent with the Company’s revenue recognition policy disclosed in Note 1, all amounts received for license fees have been recorded as deferred revenue in the December 31, 2005 and 2004 consolidated balance sheets.
In October 2002, Mr. Randall Thompson, the Company’s former Chief Financial Officer, filed a lawsuit against the Company alleging breach of employment contract regarding severance pay. In November 2002, the case was removed to federal district court in Houston, which granted summary judgment in favor of the Company. The plaintiff appealed the case to the Fifth Circuit of Appeals, which reversed the trial court in September 2004. On November 1, 2004, the Company and Mr. Thompson reached a settlement through mediation pursuant to which, the Company paid $200,000 on November 3, 2004. The Company has recognized this settlement as other expense in the statement of operations for the year ended December 31, 2004.
The Company and its subsidiaries are involved in other lawsuits that have arisen in the ordinary course of business. The Company does not believe that ultimate liability, if any; resulting from any such other pending litigation will have a material adverse effect on the Company’s business or consolidated financial position. The Company cannot predict with certainty the outcome or effect of the litigation specifically described above or of any such other pending litigation. There can be no assurance that the Company’s belief or expectations as to the outcome or effect of any lawsuit or other litigation matter will prove correct and the eventual outcome of these matters could materially differ from management’s current estimates.
The Company has settled a dispute with a vendor that resulted in the reversal of a $680,000 contingency accrual. This amount is reflected in general, administrative and other expenses in the consolidated statement of operations for the year ended December 31, 2005.
| 11. | FAIR VALUE OF FINANCIAL INSTRUMENTS: |
The estimated fair values of the Company’s financial instruments at December 31, 2005 and 2004 are summarized as follows:
| | | | | | | | | | | | |
| | | 2005 | | 2004 |
| | | Carrying
Amount | | Estimated
Fair Value | | Carrying
Amount | | Estimated
Fair Value |
| | | (in thousands) |
Assets: | | | | | | | | | | | | |
Cash and cash equivalents | | $ | 69,663 | | $ | 69,663 | | $ | 31,573 | | $ | 31,573 |
Accounts receivable | | | 1,224 | | | 1,224 | | | 632 | | | 632 |
Restricted cash - current | | | 1,684 | | | 1,684 | | | 221 | | | 221 |
Note receivable | | | 1,802 | | | 2,025 | | | 1,809 | | | 1,918 |
Liabilities: | | | | | | | | | | | | |
Convertible debt | | | 25,925 | | | 25,925 | | | 24,221 | | | 24,221 |
The fair value of the cash and cash equivalents, restricted cash and accounts receivable approximates carrying value because of the short-term maturity of these financial instruments. The estimated fair values of the note receivable and convertible debt were calculated by discounting scheduled cash flows using estimated market discount rates.
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| 12. | STOCK-BASED COMPENSATION: |
On April 25, 2005, the stockholders of the Company approved the adoption of an incentive compensation plan, the Syntroleum Corporation 2005 Stock Incentive Plan (the “2005 Plan”), which provides for the issuance of up to 6,600,000 shares of the Company’s common stock pursuant to the grant of stock options, stock appreciation rights, stock awards (including restricted stock and stock units) and performance awards. Awards will be available for grant to employees, independent contractors and non-employee directors of the Company, except that non-employee directors may only be granted awards of stock appreciation rights, stock options or restricted stock under the Plan. The Company had previously maintained various stock option and incentive plans for employees, consultants and directors. Upon the approval of the 2005 Plan, no additional shares may be issued from the previous plans. There were 3,334,234 shares available for granting future options or shares at December 31, 2005. The Company has granted various types of awards under these plans, which are summarized below.
Stock Options
The number and exercise price of stock options granted are as follows:
| | | | | | |
| | | Shares
Under
Option | | | Weighted
Average Price
Per Share |
OUTSTANDING AT JANUARY 1, 2003 | | 5,005,445 | | | $ | 5.75 |
Granted at market price | | 566,828 | | | | 2.36 |
Granted at price exceeding market | | 100,000 | | | | 3.00 |
Exercised | | (196,608 | ) | | | 2.43 |
Expired | | (797,827 | ) | | | 6.63 |
| | | | | | |
OUTSTANDING AT DECEMBER 31, 2003 | | 4,677,838 | | | | 5.27 |
Granted at market price | | 777,891 | | | | 6.52 |
Granted at price exceeding market | | 275,000 | | | | 6.68 |
Exercised | | (265,790 | ) | | | 2.66 |
Expired | | (211,690 | ) | | | 4.98 |
| | | | | | |
OUTSTANDING AT DECEMBER 31, 2004 | | 5,253,249 | | | | 5.68 |
Granted at market price | | 2,881,045 | | | | 10.37 |
Exercised | | (255,715 | ) | | | 3.11 |
Expired | | (104,165 | ) | | | 13.07 |
| | | | | | |
OUTSTANDING AT DECEMBER 31, 2005 | | 7,774,414 | | | $ | 7.40 |
| | | | | | |
The following is a summary of stock options outstanding as of December 31, 2005:
| | | | | | | | | | | | | |
| Options Outstanding | | Options Exercisable |
Range of Exercise Price | | Options Outstanding | | Weighted Average Exercise Price | | Weighted Average Remaining Contractual Life | | Options Exercisable | | Weighted Average Exercise
Price Per
Share |
| $ | 1.49 - $ 1.55 | | 1,335,581 | | $ | 1.55 | | 5.68 | | 1,335,581 | | $ | 1.55 |
| $ | 1.62 - $ 5.30 | | 1,311,048 | | | 2.83 | | 6.90 | | 1,128,721 | | | 2.81 |
| $ | 5.72 - $ 6.88 | | 1,305,448 | | | 6.64 | | 7.27 | | 682,127 | | | 6.59 |
| $ | 6.90 - $10.51 | | 1,094,104 | | | 9.64 | | 7.93 | | 242,971 | | | 8.66 |
| $ | 10.52 - $10.52 | | 2,000,000 | | | 10.52 | | 9.48 | | — | | | — |
| $ | 10.70 - $19.88 | | 728,233 | | | 15.75 | | 4.41 | | 698,233 | | | 15.96 |
| | | | | | | | | | | | | |
| | | 7,774,414 | | $ | 7.40 | | | | 4,087,633 | | $ | 5.62 |
| | | | | | | | | | | | | |
Employee Stock Options. The Company has granted incentive and non-qualifying stock options to employees. These stock options have various terms, including vesting periods, exercise prices and lives. Under the terms of the plans, incentive stock options may be issued with an exercise price of not less than 100 percent of fair market value of the common stock at the date of grant. All options granted vest at a rate determined by the Nominating and Compensation Committee of the Company’s Board of Directors and are exercisable for varying periods, not to exceed ten years.
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Long-Term Incentive Compensation Plan. In June 2005, the Company entered into stock option award agreements under the Plan with certain of its officers. The agreements granted the officers options to purchase up to 2,000,000 of its shares of the Company’s common stock at an exercise price of $10.52 per share. Depending on either the sustained stock price (as defined below) of the Company’s common stock or the net present value of future cash flows (as defined below), a percentage of the options will vest as determined in a performance vesting schedule with respect to the period commencing on the date of grant and ending on December 31, 2010 (the “Performance Period”). The performance vesting schedule is defined below.
In July 2005, the Company entered into similar stock option award agreements under the Plan with certain of its officers. The agreements granted the officers options to purchase up to 600,000 shares of the Company’s common stock at an exercise price of $10.14 per share. Depending on the sustained stock prices of the Company’s common stock or the net present value of future cash flows, a percentage of options will vest as according to the Performance Period. The performance vesting schedule is as follows:
| | | | | | | | | | | | | | | |
| | | Net Present Value of Future Cash Flows | |
Sustained Stock Price | | Less than
$1,375
million | | | $1,375 million
but less than
$1,650 million | | | $1,650 million
but less than
$1,925 million | | | $1,925 million
but less than
$2,200 million | | | $2,200 million or
more | |
$40 or more | | 100 | % | | 100 | % | | 100 | % | | 100 | % | | 100 | % |
$35 but less than $40 | | 75 | % | | 75 | % | | 75 | % | | 75 | % | | 100 | % |
$30 but less than $35 | | 50 | % | | 50 | % | | 50 | % | | 75 | % | | 100 | % |
$25 but less than $30 | | 25 | % | | 25 | % | | 50 | % | | 75 | % | | 100 | % |
Less than $25 | | 0 | % | | 25 | % | | 50 | % | | 75 | % | | 100 | % |
“Sustained stock price” means the average fair market value of a share of the Company’s common stock during any six-month period commencing on or after the first day of the Performance Period and ending on or before the last day of the Performance Period. “Net present value of future cash flows” means the net present value of estimated future cash flows from executed agreements (such as a contract to supply natural gas), proven reserves or any other source of future cash flows with analogous certainty to the aforementioned sources as estimated by an independent auditor designated by the Company’s Board of Directors. For this purpose, an annual discount rate of 10% is used to calculate net present value.
The term of each option is ten years from the date of grant. The Company follows APBO No. 25, which requires the Company to treat the plan as a variable plan for accounting purposes and causes the recognition of compensation expense or income related to changes in the intrinsic value in the options. As intrinsic value did not exist for both option award agreements on December 31, 2005, no compensation expense was recognized for the June 2005 stock option award agreement and the July 2005 stock option award agreements for the year ended December 31, 2005.
Other Stock-Based Compensation
Restricted Stock Unit Grants. The Company has granted an aggregate of 678,500 restricted common stock units to certain employees of the Company under the Company’s existing stock option and incentive plans. These restricted common stock units vest over various periods through 2008. The Company expects to recognize $780,000, $638,000 and $592,000 in compensation expense for the years ended December 31, 2006, 2007 and 2008, respectively, relating to the vesting of these restricted common stock units. Refer to the tables below for grants, valuation and vesting of restricted common stock units for the years ended December 31, 2005 and 2004. There were no restricted stock units granted for the year ended December 31, 2003.
| | | | | | | | |
| | | Restricted Common Stock Unit Grants |
| | | Units
Granted | | Weighted Average
Share Price | | Valuation |
2005 | | 280,000 | | $ | 10.18 | | $ | 2,850,000 |
2004 | | 398,500 | | $ | 5.78 | | | 2,305,000 |
| | | | | | | | |
Total | | 678,500 | | | | | $ | 5,155,000 |
| | | | | | | | |
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| | | | | | |
| | | Restricted Common Stock Units Vested |
| | | Units
Vested | | Shares Cancelled,
Retired or
Exchanged | | Net Shares
Issued |
2005 | | 133,993 | | 39,620 | | 94,373 |
2004 | | 128,688 | | 41,162 | | 87,526 |
| | | | | | |
Total | | 262,681 | | 80,782 | | 181,899 |
| | | | | | |
Stock Incentive Plan. Employees of the Company may receive a certain number of shares of common stock based on the achievement of certain goals and objectives by the individual employee and by the Company. The Board of Directors establishes the annual objectives on which the Company will be measured and determines the number of shares to be issued based on a rating system. Individual objectives are measured by management based on a similar rating system. Stock-based compensation totaling 91,707 shares with a value of $877,000 were granted subsequent to the year ended December 31, 2005 relating to performance objectives achieved in 2005 and have been included as a non-cash expense in the statement of operations for the year ended December 31, 2005. Refer to the table below for compensation expense and stock awards granted during the year ended December 31, 2005. There were no shares of common stock granted in 2004 or 2003.
| | | | | | | | | | | | |
| | | Common Stock Grants for Performance |
| | | Shares
Granted | | Price ($) | | Shares
Cancelled,
Retired or
Exchanged | | Net Shares
Issued | | Valuation |
2005 | | 91,925 | | $ | 9.27 | | 18,416 | | 73,509 | | $ | 852,000 |
| 13. | SIGNIFICANT CUSTOMERS: |
Substantially all of the Company’s joint development revenue for the three years ended December 31, 2005, was from the Department of Energy, Department of Defense and several major oil companies for joint research and development work and feasibility studies. This work has been conducted in the Company’s various facilities, including the Company’s technology center, Tulsa pilot plant, the pilot plant located at ARCO’s (now BP) Cherry Point Refinery in Cherry Point, Washington, and the Catoosa Demonstration Facility. In addition, since 1996, the Company has signed master license agreements with four oil companies and with the Commonwealth of Australia. The Company has also signed volume license agreements with three other oil companies. The license agreements allow the licensees to use the Syntroleum Process in their production of synthetic crude oil and fuels primarily outside of North America. Syntroleum received an aggregate of $39.5 million as initial deposits and options fees under existing license agreements and the rights to certain technologies in connection with these license agreements.
Under these license agreements, a licensee obtains the right to use the Syntroleum Process and to acquire catalysts from the Company, secures pricing terms for future site licenses and obtains rights to future improvements to the Syntroleum Process. Generally, the amount of the license fee for site licenses issued under the Company’s master and volume license agreements is determined pursuant to a formula based on the discounted present value of the product of (1) the annual maximum design capacity of the plant, (2) an assumed life of the plant and (3) the Company’s per barrel royalty rate. Initial cash deposits under the Company’s license agreements are credited against future site license fees (see Note 1).
Five customers and three customers accounted for 100 percent of the Company’s catalyst materials sales for the years ended December 31, 2004 and 2003, respectively.
On April 11, 2005, the Company’s wholly owned subsidiary, Syntroleum International Corporation (“Syntroleum International”), entered into a Participation Agreement with Dorset pursuant to which Dorset has committed to provide approximately $40,000,000 to Syntroleum International to be used to evaluate investment opportunities, conduct oil and gas project development activities, and acquire interests in oil and gas properties (the “Stranded Gas Venture”). On April 20, 2005, Ernest Williams II Q-TIP TUA dated 01/25/02 joined the Participation Agreement as a venture participant and agreed to provide an additional capital commitment of
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$10,000,000. In September 2005, Selim K. Zilkha Trust joined the Participation Agreement as a venture participant and agreed to provide a capital commitment of $10,000,000.
Under the terms of the Participation Agreement, the other venture participants will fund 100 percent of the costs to acquire the rights to stranded gas and liquids projects and will receive 20 percent of the interest acquired by the Company in any such project. Net cash proceeds received from the Company’s share of any project, including bonuses, or net revenues from the sale of production attributable to the Company’s working interest or overriding royalty interests in a project, less the payment of any operating expenses and maintenance capital expenditures, taxes, royalties or other required payments to a governmental entity, will be paid as follows:
| | • | | first, 100 percent to the other venture participants proportionately until each such participant has received an amount equal in value to 80 percent of the sum of such participant’s individual cost basis in all of the then existing projects in which such participant participated; |
| | • | | second, 100 percent to the other venture participants proportionately until each such participant has received an amount equal in value to a return of 10 percent per annum, compounded annually, on 80 percent of the sum of such participant’s individual costs basis in all of the projects in which such participant participated; and |
| | • | | third, 100 percent to Syntroleum International. |
As of December 31, 2005, the Company has received proceeds in the amount of $3,915,000 from the Stranded Gas Venture to be used to evaluate investment opportunities. The current balance of $4,247,000, which includes proceeds and accrued interest, has been recognized as a Stranded Gas Venture liability included in liabilities in the accompanying consolidated balance sheet as of December 31, 2005. Interest is allocated to a portion of principal at an annual rate of 10 percent, compounded annually, in accordance with the Participation Agreement.
| 15. | COMMONWEALTH OF AUSTRALIA SETTLEMENT: |
In early 2000, the Company began developing a nominal 11,500 b/d specialty product GTL plant, about four kilometers from the North West Shelf liquefied natural gas facility on the Burrup Peninsula of Western Australia, which the Company refers to as the Sweetwater Project. The Company selected this site after receiving a financial commitment in the form of loans and license agreements, from the Commonwealth of Australia. The plant design was intended to produce synthetic lube oil, normal paraffins, process oils and light paraffins using a fixed tube reactor design, operating with a proprietary catalyst, which produces a high yield of the desired products with high wax content.
The Company signed a non-exclusive license agreement with the Commonwealth of Australia, granting the Commonwealth the right to utilize the Syntroleum Process. Under the license agreement, the Commonwealth paid the Company a license fee in the amount of AUD $30 million (approximately U.S. $22.5 million at the December 31, 2003 exchange rate of $0.75 per Australian dollar), half of which was held in escrow and included in restricted cash on the Company’s consolidated balance sheets at December 31, 2004. These funds would have been distributed to the Company for use in Australia upon satisfaction of certain conditions relating to the development of GTL technologies in Australia. This license agreement is denominated in Australian dollars and is subject to changes in foreign currency.
The Company also entered into a loan agreement with the Commonwealth of Australia under which the Commonwealth would make an unsecured, non-amortizing, interest-free loan to the Company in the amount of AUD $40 million with a 25-year maturity. Loan proceeds were to be used to support the further development and commercialization of GTL technologies in Australia. Under the terms of the loan agreement, the Company agreed to conduct a feasibility study on constructing a large-scale GTL fuels plant in Australia. Loan proceeds were to be made available to the Company in three advances.
During 2000, the Company received the first advance under the loan agreement in the amount of AUD $8 million and during 2001, the Company received a second advance of loan proceeds in the amount of AUD $12 million. These funds were placed in escrow and were held in Australian currency. The third advance was not made to the Company and would have been AUD $20 million. Pending satisfaction of certain conditions relating to the financing, construction and completion of the Sweetwater Project, proceeds were to be held in escrow. The loan agreement provided that if the conditions were not satisfied by August 2004, any loan proceeds remaining in escrow were to be returned to the Commonwealth.
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Loan proceeds were also included in restricted cash on the Company’s consolidated balance sheet as of December 31, 2003. Both the restricted funds and the related debt have been adjusted to reflect the exchange rates in effect as of the balance sheet date. The debt amount reflected the total cash loan proceeds discounted over the remaining term of the loan using an imputed interest rate of nine percent. The difference between the cash proceeds received and the discounted debt amount totaled $9.8 million. This difference was initially recorded as a reduction in the cost of the related property and equipment. As a result of the suspension of the Sweetwater Project in October 2002, as discussed below, and the expensing of all capitalized costs related to this project, this amount was reclassified from property and equipment and recorded as a deferred credit, as there is no remaining cost of property and equipment related to this project. This credit was reversed as the debt was accreted and would have been fully accreted at the time the debt was repaid by the Company. Similar to the restricted cash and related debt, the deferred credit was also subject to foreign currency fluctuations. Any repayments for this debt would be made from the restricted cash held in escrow at an Australian financial institution.
The Company’s engineering, procurement and construction contract for the Sweetwater Project with Tessag Industrie Anlagen GmbH expired on August 30, 2002. On October 29, 2002, the Company announced the suspension of its Sweetwater Project. The Company had been attempting to arrange financing for the Sweetwater plant using non-recourse senior and subordinated debt totaling approximately 60 percent of the total project costs, as well as equity financing from third parties, together with the Company’s own equity contribution, for the remaining balance of the costs. The Company had been in discussions with several potential equity participants in the project. Additionally, the Company had been approached regarding the possibility of moving the plant to other sites where stranded gas is located. In connection with proposals to move the plant to other sites, the Company discussed the availability of financial sponsorship. However, after evaluating the alternatives, the Company determined that insufficient economic support existed to continue pursuing the plant at the time. This decision was based on decreased financing activities for international projects subsequent to the events of September 11, 2001, the Company’s inability to negotiate long-term product off-take agreements, lower than expected product margins caused by increased capital costs and reduced expectations for market prices for the proposed product slate and the loss of Enron Corporation as a 13 percent equity partner. In connection with the suspension of the project, the Company expensed approximately $31 million of costs previously capitalized as property and equipment on the consolidated balance sheet in September 2002. This amount reflected engineering, catalyst materials, upgrading and other site costs associated with the proposed plant. No physical construction work on the plant had occurred.
In April 2004, the Company reached an agreement with the Commonwealth of Australia to resolve all issues between the two parties regarding the suspension of the Sweetwater Project. Under this agreement, all of the funds that were held in escrow accounts in Australia related to advances on the loan and the license agreement, plus all interest earned on these funds since the suspension of the project and other associated costs, were returned to the Commonwealth of Australia in September 2004. The Commonwealth will retain its license for the Syntroleum Process; however, rather than retaining the right to receive AUD $30 million in credits against future license fees, the Commonwealth will only receive AUD $15 million in credits. The income statement impact of this transaction was a charge against earnings of $610,000 for interest and other associated costs since the suspension of the project and is included in other income (expense) on the Company’s consolidated statement of operations for the year ended December 31, 2004. The Company has no plans to re-start the Sweetwater Project.
| 16. | STOCKHOLDER RIGHTS PLAN: |
On October 24, 2004, the Company entered into the Second Amended and Restated Rights Agreement, whereby each outstanding share of the Company’s common stock carries a stock purchase right issued pursuant to a dividend distribution declared by the Company’s Board of Directors in March 1997. The rights entitle the holder to buy one one-hundredth of a share of Series A Junior Preferred Stock at a price of $20.8333 per one one-hundredth of a share. Generally, the rights become exercisable ten days after a public announcement that a person or group has acquired, or a tender offer is made for, 20 percent, or in the case of Mr. Robert A. Day and his affiliates 35 percent, or more of the common stock of the Company. If either of these events occurs, each right will entitle the holder to receive the number of shares of the Company’s common stock having a market value equal to two times the exercise price of the right. The rights may be redeemed by the Company for $0.01 per right until ten days following the first date of public announcement of a person becoming an Acquiring Person. The rights expire October 2014.
The Company applies SFAS No. 131,Disclosures About Segments of an Enterprise and Related Information. The Company’s reportable business segments have been identified based on the differences in products or services provided.
F-27
The Technology, General, Administrative and Other segment includes research and development expenses for further development of GTL technology, including operations of the Catoosa Demonstration Facility and the Tulsa pilot plant, engineering and design of our mobile facility, and ongoing research and development efforts focusing primarily on commercialization of the technology we previously developed, as well as general and administrative expenses. Revenues in the Technology, General, Administrative and Other segment consist of joint development revenues from government agencies and major oil companies as well as catalyst materials sales.
The Domestic Oil and Gas segment includes the acquisition of oil and gas leases, geological and geophysical work, drilling and completion of wells and administrative work in the United States. Revenues for Domestic Oil and Gas activities will include revenues from production and processing of oil and gas. All of the assets of the Domestic Oil and Gas segment have been disposed of or are classified as held for sale. Management has classified this segment as discontinued operations in the consolidated statement of operations for the years ended December 31, 2005, 2004 and 2003 (See Note 3).
The International Oil and Gas segment includes project development expenses and capital expenditures for projects that involve traditional methods of production and processing and projects that may later include the use of our GTL technologies in international areas. International Oil and Gas revenues will include revenues from production and processing of oil and gas.
The reportable business segments are summarized below (in thousands):
| | | | | | | | | | | | | | | | |
| | | Domestic Oil
and Gas | | | International
Oil and Gas | | | Technology,
General,
Administrative
and Other | | | Total | |
2005 | | | | | | | | | | | | | | | | |
Revenue | | $ | — | | | $ | — | | | $ | 7,908 | | | $ | 7,908 | |
Operating cost | | $ | — | | | $ | 4,475 | | | $ | 38,196 | | | $ | 42,671 | |
Net income/(loss) | | $ | (3,882 | ) | | $ | (1,048 | ) | | $ | (36,464 | ) | | $ | (41,394 | ) |
Total assets | | $ | 1,927 | | | $ | 8,135 | | | $ | 79,733 | | | $ | 89,795 | |
Capital expenditures | | $ | 1,238 | | | $ | 13,669 | | | $ | 1,167 | | | $ | 16,074 | |
2004 | | | | | | | | | | | | | | | | |
Revenue | | $ | — | | | $ | — | | | $ | 6,606 | | | $ | 6,606 | |
Operating cost | | $ | — | | | $ | 1,699 | | | $ | 45,374 | | | $ | 47,073 | |
Net income/(loss) | | $ | (480 | ) | | $ | (1,699 | ) | | $ | (40,371 | ) | | $ | (42,550 | ) |
Total assets | | $ | 4,488 | | | $ | 1,067 | | | $ | 39,196 | | | $ | 44,751 | |
Capital expenditures | | $ | 4,476 | | | $ | 865 | | | $ | 929 | | | $ | 6,270 | |
2003 | | | | | | | | | | | | | | | | |
Revenue | | $ | — | | | $ | — | | | $ | 19,240 | | | $ | 19,240 | |
Operating cost | | $ | — | | | $ | — | | | $ | 53,893 | | | $ | 53,893 | |
Net income/(loss) | | $ | (164 | ) | | $ | — | | | $ | (34,474 | ) | | $ | (34,638 | ) |
Capital expenditures | | $ | 76 | | | $ | — | | | $ | 822 | | | $ | 898 | |
Subsequent to December 31, 2005, the Company granted an aggregate of 261,500 options to purchase shares of common stock to employees at a weighted average exercise price of $9.59 per share. The Company also issued 119,998 shares of common stock as a result of the vesting of restricted common stock units and 91,707 shares of common stock for incentive compensation. The Company issued 45,230 restricted common stock units to employees under our stock option and incentive plans and 38,759 shares of common to directors for services to be provided in the future.
In February 2006, the consulting agreement with TI Capital Management was amended to alter previous terms and conditions. The Company has also agreed to amend, subject to shareholder approval, the joint development agreement with Sovereign. These amendments are referenced in Note 8.
In February 2006, the Company entered into a Participation Agreement and Joint Operating Agreement with Brittania-U. Under the agreements, we must commence Phase I drilling which includes drilling and evaluation and if necessary, testing of the Ajapa-2 well on OML 90 at an estimated cost of $10 million. Phase I will not
F-28
commence until Brittania-U obtains all of the necessary approvals and consents. If necessary approvals and consents are not received before May 3, 2006, the Participation Agreement and Joint Operating Agreement will terminate, unless extended by both parties.
| 19. | QUARTERLY DATA (UNAUDITED): |
| | | | | | | | | | | | | | | | |
| | | Quarter Ended | |
| | | March 31, | | | June 30, | | | September 30, | | | December 31, | |
| | | (in thousands, except per share data) | |
2005 | | | | | | | | | | | | | | | | |
Revenues | | $ | 223 | | | $ | 6,211 | | | $ | 708 | | | $ | 766 | |
Operating income (loss) | | | (11,562 | ) | | | (3,709 | ) | | | (13,178 | ) | | | (14,988 | ) |
Net income (loss) from continuing operations | | | (11,618 | ) | | | 446 | | | | (12,798 | ) | | | (13,542 | ) |
Net income (loss) from discontinued business | | | (16 | ) | | | (1,010 | ) | | | (2,616 | ) | | | (240 | ) |
Net income (loss) | | | (11,634 | ) | | | (564 | ) | | | (15,414 | ) | | | (13,782 | ) |
Basic and diluted EPS: | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (0.24 | ) | | $ | (0.00 | ) | | $ | (0.23 | ) | | $ | (0.23 | ) |
Discontinued operations | | $ | (0.00 | ) | | $ | (0.01 | ) | | $ | (0.05 | ) | | $ | (0.01 | ) |
Net income | | $ | (0.24 | ) | | $ | (0.01 | ) | | $ | (0.28 | ) | | $ | (0.24 | ) |
| |
| | | Quarter Ended | |
| | | March 31, | | | June 30, | | | September 30, | | | December 31, | |
| | | (in thousands, except per share data) | |
2004 | | | | | | | | | | | | | | | | |
Revenues | | $ | 5,928 | | | $ | 145 | | | $ | 216 | | | $ | 317 | |
Operating income (loss) | | | (5,598 | ) | | | (12,676 | ) | | | (11,493 | ) | | | (10,700 | ) |
Net income (loss) from continuing operations | | | (6,125 | ) | | | (11,755 | ) | | | (12,386 | ) | | | (11,804 | ) |
Net income (loss) from discontinued operations | | | (245 | ) | | | (56 | ) | | | (89 | ) | | | (90 | ) |
Net income (loss) | | | (6,370 | ) | | | (11,811 | ) | | | (12,475 | ) | | | (11,894 | ) |
Basic and diluted EPS | | | | | | | | | | | | | | | | |
Continuing operations | | $ | (0.16 | ) | | $ | (0.28 | ) | | $ | (0.27 | ) | | $ | (0.26 | ) |
Discontinued operations | | $ | (0.00 | ) | | $ | (0.00 | ) | | $ | (0.00 | ) | | $ | (0.01 | ) |
Net income | | $ | (0.16 | ) | | $ | (0.28 | ) | | $ | (0.27 | ) | | $ | (0.27 | ) |
To date, the nature of the Company’s revenues and costs have been related to certain projects and are wholly dependent upon the nature of the Company’s projects. The various size and timing of these projects, including the DOE Catoosa Project, operations and modifications at our Catoosa demonstration facility and OML 113 offshore Nigeria, affects the comparability of the periods presented.
F-29
