ITEM 1. BUSINESS.
OVERVIEW
3DX Technologies Inc. ("the Company") is a knowledge-based oil and gas exploration company whose core competence and strategic focus is the utilization of 3-D seismic imaging and other advanced technologies in the search for commercial quantities of hydrocarbons. The Company enters into arrangements that enable it to combine its expertise and exploration capabilities with the operating skills of other oil and gas companies. The Company participates in selected exploration projects as a non-operating working interest owner, sharing both risks and rewards with its partners. The Company commenced operations in January 1993 to take advantage of perceived opportunities emerging from changes in the domestic oil and gas industry, including the divestiture of domestic oil and gas properties, advances in technology and the outsourcing of specialized technical capabilities. By reducing drilling risk through 3-D imaging and analysis, the Company seeks to improve the expected return on investment in its oil and gas projects.
The Company has developed a screening process that it applies to all projects that it considers. The screening process, adapted continually to incorporate the Company's ongoing experience, is designed to produce a balanced portfolio of projects that have reliable and experienced operating partners, are conducive to the application of advanced 3-D technology, have significant upside potential and may be extended into exploration trends.
STRATEGY
The Company's goal is to increase its proved reserves, production and cash flow by quickly, accurately and economically locating commercial quantities of hydrocarbons for itself and its partners. To reach its goal, the Company is pursuing a business strategy that includes the following principal elements:
Focusing Operational Efforts Exclusively on the Company's Expertise in 3-D Imaging and Analysis. The Company focuses all of its technical resources on obtaining the best possible subsurface image and on identifying the most effective location and target depth for each prospective well. To allow it to focus its efforts exclusively on 3-D imaging and analysis, the Company relies on its project partners to undertake the
project's other operating functions, including land acquisition, drilling and marketing. Although 3-D seismic technology is now routinely used in oil and gas exploration projects, the Company believes that its focus, experience and innovative methods of applying the technology provide it with advantages in extracting useful information from seismic and other data.
Developing and Supporting a Team of Technologically Sophisticated Explorationists. The quality of information obtained from the application of 3-D imaging is dependent to a large extent on the Company's ability to capitalize on the intelligence, acquired knowledge and creativity of the experienced geoscientists and engineers it employs. To allow the Company to capitalize fully on the intellectual resources offered by such experts, the Company's administrative operations and infrastructure are directed toward providing tools and support to the Company's technical specialists. To continue its ability to recruit, retain and motivate such experts, the Company is committed to providing its oil and gas geoscientists and engineers with the most advanced imaging and analytical technology commercially available and awards options to purchase common stock to each of its experts and other employees.
Maintaining a Research Program to Develop Innovative Application Techniques Involving Advanced Exploration Technology. The Company relies upon its ongoing applied research effort to continually develop and adapt technology that will enable it to retain its position as a leading high technology exploration company. For example, through its research efforts, the Company has developed the 3DXpress process. The Company's 3DXpress process is an innovative technique used in exploration that improves the quality of seismic data and significantly compresses the time frame traditionally required for acquisition, processing, imaging and analysis. This process allows analysis of 3-D data while the survey is being conducted, giving the Company's explorationists the ability to ensure data quality and steer data collection toward areas where prospects are more likely to exist. Utilizing this technology, the Company believes it has been able to image and analyze a larger number of projects concurrently and identify potential drilling sites more rapidly and accurately than with traditional methods. The Company also believes that the application of emerging technologies, such as migration velocity analysis and depth migration technology, provides the Company with a competitive advantage in its efforts to effectively and efficiently locate commercial quantities of hydrocarbons.
Pursuing a Disciplined Approach to Selective Project Participation, Partnering and Drilling Efforts. The Company adheres to a disciplined screening process and, based on its experience, continually adapts the criteria to select projects which are likely to maximize the return on its capital investment. The Company's selection criteria favor projects which (i) are managed by reliable and successful operating partners; (ii) are located on properties to which 3-D imaging can be effectively applied to evaluate the primary geologic risk; (iii) have high upside potential; (iv) may be extended into trend plays; and (v) have projected rates of return which make the production of hydrocarbons economically attractive.
Actively Managing the Company's Portfolio of Oil and Gas Projects. The Company has developed and actively manages a portfolio of partners, projects and producing assets having a diverse range of risk/reward ratios. Active portfolio management enables the Company to reduce its exposure to non-geologic project risks such as land acquisition, operator performance and drilling operations that are not mitigated by the application of 3-D imaging and analysis technologies. In addition, the Company believes that aggressive management of its portfolio enables it to make more efficient use of available capital by limiting the Company's exposure to any individual exploration project and by allowing it to focus its resources toward trend play opportunities arising from carefully selected projects.
PROJECT SELECTION AND MANAGEMENT METHODOLOGY
Successful application of the Company's business plan is dependent upon the Company's participation as an active working interest partner in select high quality projects. The working interest acquired by the Company in any project is determined through negotiation among the Company and its prospective partners prior to the Company's commitment to participate. The percentage working interest which the Company seeks to acquire varies with each project and is dependent upon the project's anticipated costs, risk and potential return. During the course of the project, the Company's working interest is subject to
change as a result of negotiated cost and working interest sharing arrangements, the terms of which are negotiated by the Company prior to its commitment to participate. To identify these projects, the Company undertakes a rigorous evaluation of the numerous projects proposed to it by its existing partners and other project generators. The Company engages in the following steps to evaluate, identify and manage high quality projects in which the Company participates.
o Initial Screening. Prior to committing technical resources to the evaluation of a potential project, the Company's business development team reviews both the potential project and its partners to determine if they satisfy certain initial business criteria. To evaluate a potential project, the Company considers geographic location, scale, geological model, anticipated drilling prospects, number of pay zones, trend potential and expected project economics. To evaluate a potential partner, the Company considers that partner's financial stability, reputation and record of success in exploration and production activities.
o Technical Evaluation. If the potential project and partner satisfies the Company's initial business screening criteria, the project is then evaluated by a multidisciplinary team of the Company's technical experts. Such technical evaluation allows the Company to analyze and evaluate further the basic geological model, determine the seismic character of reservoirs within the project site, determine if the application of 3-D imaging technology will adequately address the primary geologic risk, investigate local and regional production trends for target reservoirs, refine its evaluation of project economics and determine if the capital required conforms to the Company's investment guidelines. If the project meets these criteria, the Company will participate in the project, committing its capital, technological resources and 3-D imaging and analytical expertise.
o Earth Imaging. Once a project is approved for investment, the project team, led by one of the Company's geoscientists or engineers and including representatives of all or substantially all of the project's partners, commences its efforts to create the most accurate subsurface image possible. By integrating 3-D seismic data with other geologic and engineering data, the project team uses the derived subsurface image to model the potential reservoirs within the project's area. The seismic data collection, processing and analysis are usually managed by the Company to assure its integrity and consistency.
o Drilling Decision. After the project team completes the earth imaging and analysis of a selected project, the project team determines if the applicable data identify economically attractive drilling opportunities. The economic return expected from drilling must satisfy certain criteria and must be commensurate with the perceived risk. Thereafter, the project team makes recommendations to the partnership regarding drill sites and target depths.
o Post-Drilling Appraisal. Subsequent to the drilling of each well in a project, the Company integrates the information it has acquired in the drilling phase with its earth model, enabling it to enhance the model based on the best available data and knowledge. As a result, the Company builds an increasing base of knowledge upon which to make future drilling decisions with respect to each project.
As a working interest partner, the Company shares all project costs in proportion to its working interest percentage. In instances in which exploration and development activities are unsuccessful, the Company incurs an economic loss equal to its proportionate share of project costs prior to the time the project is abandoned. Similarly, the Company incurs an economic loss if the Company's proportionate share of revenue generated from production is insufficient to cover the Company's share of project costs.
PROJECT GENERATION AND SIGNIFICANT BUSINESS RELATIONSHIPS
By its participation in multiple projects, many with multiple partners, the Company seeks to demonstrate its ability to improve project economics. Its current partners are its best resource for future high
quality projects. The Company believes that its existing partners, which have benefited from the Company's ability to improve project economics by reducing primary geologic risk, will seek such benefits with respect to future projects and will therefore solicit the Company's involvement in such new projects. By participating in projects with partners who possess experience and knowledge in exploration operations that are complementary to the Company's imaging and analytical focus area, the Company believes that it and each project partner receive the benefit of the other's knowledge and expertise while achieving results that are greater than any particular partner might be able to achieve independently. The Company further believes that establishing long-term partner relationships will enhance the flow of prospective opportunities and the quality and stability of the business relationship, as well as reduce significant risks, such as the partner's operating capabilities and financial stability.
As of December 31, 1997, the Company's active exploration portfolio consisted of 25 projects and included 12 operator partners, as reflected in the table below:
The Company's strategy is to enter into long-term joint ventures and alliances with high quality operator partners to enhance the flow of opportunities presented to the Company and to assure consistent quality of operations. As part of this strategy, the Company attempts to convert successful relationships on individual projects with quality partners into long-term strategic alliances.
3-D IMAGING TECHNOLOGY
The Company's oil and gas exploration capabilities are dependent upon the effective application of 3-D imaging technologies. Although the initial application of 3-D imaging technology began in the late 1960's, its cost through the 1970s justified use only in deep offshore applications and other environments with substantial drilling costs and risk. During the latter half of the 1980's, 3-D imaging was a principal tool used in exploration activities in both the North Sea and the Gulf of Mexico. Advances in technology during the 1980's made the use of 3-D imaging more cost-effective and more readily available for use onshore.
In general, 3-D imaging technology provides an "image" of the subsurface geology by collecting seismic data along multiple parallel lines and creating a cube of information which is spatially sampled throughout. The data acquired by use of 3-D imaging technology is of significantly higher quality and provides significantly better information than the data acquired by 2-D seismic technology. The higher fidelity and resolution of 3-D data results in more accurate images than are possible using 2-D seismic and other conventional methods. The productive application of 3-D imaging technology requires the skills of highly trained experts.
The Company maintains an extensive computer facility to support its oil-finding activities. A Silicon Graphics Power Challenge provides the large-scale computing capacity to support real-time data processing and depth migration. A network of eight Sun Sparc and Ultra Sparc workstations, functioning in a client-server environment, provides the framework for synthesis of the geological, geophysical and engineering data into an integrated image of the subsurface. The principal supplier of the software used by the Company for both processing and data interpretation is Landmark Graphics Corporation and its subsidiaries. In addition, the Company maintains licenses for certain complex geological and geophysical applications from Hampson-Russell Software Inc., Paradigm Geophysical, Inc., and Petrosoft Inc.
GEOLOGIC, GEOPHYSICAL AND ENGINEERING EXPERTISE
The Company has assembled a group of talented and experienced geologists, geophysicists and engineers that work in multidisciplinary teams to enable the Company to exploit fully the advantages afforded by 3-D imaging technologies. As of December 31, 1997, the Company employed 17 full-time experts who design and manage the process of seismic data acquisition, processing, imaging and analysis and drill site selection using computer systems and software owned or licensed by the Company. The majority of these geoscientists and engineers have between five to 20 years of experience involving the utilization of seismic data imaging and analysis, and they have extensive experience with 3-D seismic projects in diverse geologic trends throughout the world. If a project requires technical expertise not available from the Company's or project partners' personnel, the Company's project manager will identify and recruit an industry expert to join the project team. By assembling in-house technical expertise, the Company is able to manage fully and effectively the imaging and analytical phase of the projects in which it participates. The Company provides its technical expertise exclusively to those projects in which it participates as a working interest partner.
RESEARCH AND DEVELOPMENT
The Company believes that it possesses a competitive advantage over other oil and gas companies by utilizing the experience of its in-house scientific experts to continually develop innovative techniques and tools to optimize the Company's utilization of 3-D imaging technologies. The Company's ongoing research and development and its continuous accumulation of knowledge have resulted in technical improvements and innovations that the Company believes provide it with significant competitive advantages. The Company enhances its ongoing research program by forging strategic alliances with select suppliers of hardware and software which have demonstrated foresight in the science of earth imaging. The Company believes that its strategy of applied research and development will allow it to remain at the forefront of oil and gas exploration technology.
The Company has been able to adapt and refine concurrent imaging methods to create the Company's 3DXpress process through the effective application of its applied research and development strategy. In its first commercial application of the 3DXpress process, the Company commenced and completed a project's imaging and analysis phase in a four week period. Thereafter, the project operator successfully drilled and completed seven of the eight resulting wells in a complex geologic setting relying upon the Company's drill site and target depth recommendations.
Other innovations and improvements to the imaging process resulting from the Company's ongoing research include the use of digital orthomaps for survey planning and control, the use of GPS locators on seismic vibrators for positioning control, application of AVO, inversion and geostatistics to the process of reservoir characterization and the application of interactive migration velocity analysis and depth migration to achieve superior image reconstruction. Many of these innovations and improvements are the result of strategic alignments with pioneering technology suppliers such as GPS Technologies, Inc., Hampson-Russell Software, Inc., Landmark Graphics Corporation and Paradigm Geophysical, Inc.
REGULATION
The Company's operations are subject to numerous federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public interest in the protection of the environment has increased dramatically in recent years. Offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. The Company believes that the trend of more expansive and stricter environmental legislation and regulations will continue. To the extent laws are enacted or other governmental action is taken which prohibit or restrict onshore and offshore drilling or impose environmental protection requirements that result in increased costs to the oil and gas industry in general, the business and prospects of the Company could be adversely affected.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages including natural resource damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA.
Under the OPA and regulations promulgated thereunder, owners and operators of "offshore facilities" must satisfy certain financial assurance requirements to evidence their ability to cover potential environmental cleanup and restoration costs. In projects in which the Company has a participating working interest, the operator partner is responsible for all demonstrations of financial responsibility including the posting of any indemnity bonds which are required by applicable governmental regulations. The expenses incurred in the operator partner's demonstration of financial responsibility are expenses which are allocated to each project partner based on the respective partner's working interest.
The OPA also imposes other requirements, such as the preparation of an oil spill contingency plan. The Company has such a plan in place. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party to civil or criminal enforcement actions.
To complement the OPA, the State of Texas enacted the Oil Spill Prevention and Response Act (OSPRA). The Texas General Land Office (GLO) is the lead agency for carrying out OSPRA, and to that end the GLO has promulgated regulations affecting anyone who owns or operates a vessel or facility that stores or transfers oil in areas where a spill could reach Texas coastal waters.
In addition, the Outer Continental Shelf Lands Act ("OCSLA") authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf (the "OCS"). Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations of lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or private prosecution.
The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Further, certain oilfield wastes are subject to the Resource Conservation & Reservation Act ("RCRA") with respect to the regulation of hazardous wastes. The RCRA regulates the generation, transportation and disposal of hazardous wastes.
The Texas Railroad Commission has issued rules for management of certain types of hazardous waste generated in the oilfield. However, until delegation of the RCRA program to the Railroad Commission, hazardous wastes generated in the oilfield are regulated by the Texas Natural Resources Conservation Commission. The Texas Railroad Commission regulates pollution of groundwater and surface water resulting from exploration, production and development of oil and natural gas resources.
The Clean Water Act (CWA) and regulations promulgated thereunder prohibit the discharge of pollutants into waters of the United States without a permit pursuant to the National Pollutant Discharge Elimination System (NPDES) provisions. The CWA also requires reporting of oil spills to the National Response Center. The United States Environmental Protection Agency (EPA) has issued general NPDES permits for oil and gas platforms in the Gulf of Mexico, which permits impose limits on discharges of such things as oil, grease, produced water and drilling fluids. Onshore platforms may also be subject to the requirement for NPDES permits for both production discharges and for discharges of stormwater. In Louisiana, the NPDES permit program has recently been delegated to the State of Louisiana. In Texas, the NPDES permit program is administered by the EPA. Failure to obtain the proper permit may result in both civil and criminal penalties as well as an order to cease discharges, which in effect is an order to shut down production.
Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations. Compliance with such laws and regulations has not historically represented a significant expense for the Company and management does not foresee the need for material expenditures to ensure continued compliance with currently existing laws and regulations. Laws and regulations in these areas are, however, subject to change and there can be no assurance that future laws or regulations will not have a material adverse effect on the Company.
OPERATING HAZARDS AND INSURANCE
The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-out, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, gas leaks, ruptures and discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. In addition to the foregoing, offshore operations are subject to the additional hazards of marine operations, such as capsizing, collision and adverse weather and sea conditions.
The Company maintains insurance coverage, both directly for its own account and indirectly through its operator partners, against some, but not all, operating risks. The insurance maintained by project operator partners generally does not cover claims relating to failure of title to oil and gas leases, trespass during 3-D survey acquisition or surface damage attributable to seismic operations, business interruption nor does it protect against loss of revenues due to well failure. There can be no assurance that any insurance obtained
by the Company or its project operator partners covering claims related to worker's compensation, comprehensive general liability for bodily injury and property damage, comprehensive automobile liability and pollution, cleanup, underground blowout and evacuation will be adequate to cover any losses or liabilities which may be incurred within projects in which the Company participates. The Company is an additional named insured on the insurance policies procured and maintained by operator partners. The Company cannot predict the continued availability of insurance coverage or the availability of insurance at premium levels that justify its purchase. If the Company or any project operator partner were unable to procure insurance at an acceptable cost with respect to each of the projects in which the Company participates, the occurrence of significant adverse events not fully insured or indemnified against could materially and adversely affect the Company's financial condition and operations.
COMPETITION
Competition in the oil and gas industry is intense, particularly with respect to the acquisition of acreage and capital. The Company's competitors in the provision of seismic imaging, analytical and other related services and in the exploration for oil and gas include numerous major and independent oil and gas companies, smaller, technology-driven service companies, individual proprietors, drilling and income programs and partnerships. Many of the Company's competitors possess and employ financial and personnel resources substantially in excess of those available to the Company and may, therefore, be able to define, evaluate, bid for and participate in a greater number of oil and gas properties than the Company. The Company believes that technology, experience and reliability are the primary elements upon which the Company competes in the industry, as oil and gas exploration companies demand higher quality seismic data delivered and analyzed in increasingly shorter time frames and greater assurances that the interests of such company are respected and advanced. Although the Company believes that it competes effectively in each of these areas, there can be no assurance that the Company's ability to attract and invest in high quality projects will not be adversely affected if its current competitors or new market entrants introduce new services with better quality technology than those offered by the Company.
EMPLOYEES AND INDEPENDENT CONSULTANTS
As of December 31, 1997, the Company had 23 full-time employees including 17 explorationists. The Company believes that its relationship with its employees is good. None of the Company's employees is covered by a collective bargaining agreement. The Company expects to continue a program, which it commenced in August 1996, to hire recent college graduates and advanced degree holders.
ITEM 2.
ITEM 2. PROPERTIES
SIGNIFICANT PROJECTS AND PROPERTIES
The Company's exploration activities are primarily focused in the onshore Gulf Coast region of the United States, principally in Texas, but also include projects in Louisiana, Mississippi, Alabama and Florida. Additionally, the Company has active exploration projects offshore in the Gulf of Mexico and internationally in West Africa, offshore both The Republic of Cote d'Ivoire and Ghana.
3-D seismic imaging is an effective tool to identify the structural and stratigraphic features in the Gulf Coast region and provides the Company with an ability to identify hydrocarbon potential in and around existing fields that could not be detected with 2-D seismic and earlier exploration techniques. Due to geologic complexities within this region, it may be possible to identify multiple prospects within a single project. These prospects typically offer multiple drilling opportunities with individual wells capable of penetrating multiple reservoirs.
The extensive drilling history within Gulf Coast trends provides a powerful subsurface and production database to which seismic data can be calibrated. This data provides the foundation required to design a
seismic program that optimizes resolution at targeted reservoirs. This subsurface information, when combined with 3-D seismic data, provides a more accurate assessment of reservoir quality, productivity, reserve potential and, in some instances, fluid type.
As demonstrated by its election to participate in projects located in The Republic of Cote d'Ivoire and Ghana, the Company believes it can extend its trend strategy into other select geographic areas where the application of 3-D imaging technology can be utilized to reduce the primary geological risks prior to drilling.
The major producing areas in which the Company holds an interest are reflected in the table below as of and for the year ended December 31, 1997:
GULF COAST AREA
Of the 23 wells which were evaluated in 1997 and in which the Company held an interest, 21 were in the Gulf Coast area, including 16 in Texas, 3 in Mississippi and Alabama, and 2 in Louisiana. All of the Company's 11 successful wells in 1997 were in the Gulf Coast area.
TEXAS GULF COAST. This trend area includes both onshore and near-shore properties and generally extends along the Texas coast for a distance of approximately 100 miles inland from the coastline. Prospective geology in the trend is characterized by numerous stacked sand formations that were deposited continuously by river channels and deltas. The trend's primary oil and gas producing formations include the Miocene, Frio, Vicksburg, Yegua, and Wilcox. The Company has active exploration projects targeting each of these oil and gas formations from depths of 3,000' to 15,000'. Of the Company's 25 active exploration projects, 15 are in the Texas Gulf Coast area. The Company completed eight major 3-D seismic shoots in the Texas Gulf Coast region during 1997, covering over 350 square miles. Below is a discussion of certain of the active exploration projects in this area:
Miocene Trend. The Company currently has nine producing gas wells in the Miocene Trend area in Calhoun and Matagorda Counties, Texas, at depths between 3,000' and 6,000'. The Company owns working interests ranging from 20% to 40% in these wells, which are operated by Prime Operating Company, a subsidiary of PrimeEnergy Corporation. The Miocene Trend projects in which the Company currently owns an interest are considered to be substantially developed and the Company does not plan to drill any additional wells on these projects in 1998. However, the Company may continue to pursue additional opportunities in this trend area.
Geronimo and Geronimo Extension. The Company completed acquisition of a total of 115 square miles of 3-D seismic data in 1996 and 1997 utilizing the 3DXPRESS process on these projects which are located in San Patricio County, Texas. Primary target formations include the Frio and Vicksburg sands. The Company spudded four wells on these projects in 1997, two of which were successful, one of which was lost due to mechanical failure, and the fourth of which was drilling at December 31, 1997. The well which was lost did not fully evaluate the target formation and is expected to be
redrilled in 1998. The Company owns working interests ranging from 11% to 22% in these projects, which are operated by Esenjay Petroleum Corporation.
Ramrod. The Company completed acquisition of 34 square miles of 3-D seismic data in early 1997 on this project, which targeted both Miocene and Frio potential. The Company owns a 40% working interest and together with its partner, PrimeEnergy Corporation, drilled 5 wells on this project in 1997, all of which were successful. Four of the wells were Miocene wells. The fifth well drilled was the St. George #1, which made a potentially significant discovery in the deeper section of the Frio. This well was tested subsequent to December 31, 1997 at rates exceeding 10 Mmcf of gas and 200 barrels of condensate per day with a flowing tubing pressure of almost 9,000 psi. The Company plans to produce this first well for a period of at least three months before continuing with development plans for the field. Because this well is a new field wildcat without nearby analogs, the estimate of proved reserves assigned to it by the Company's independent reservoir engineers was very conservative.
Hall Ranch. The Company has a 25% working interest in the Hall Ranch prospect, which is located in Karnes County, Texas. Esenjay Petroleum is the operator of the project. The partnership completed a 42 square mile 3-D seismic survey on this project in the second quarter of 1997. The primary objective in the area is the lower Wilcox formation at depths of 10,000' to 13,000'. The Company drilled one well on this prospect in 1997 which experienced mechanical difficulties and had to be plugged and abandoned prior to evaluating the objective formation. The redrill of this well and an additional well in a separate fault block are planned for drilling in the first half of 1998.
Galveston Bay Area. The Company has two major projects in the Galveston Bay area. This area targets potential production in the upper and lower sections of the Frio formation and the Vicksburg formation. There has been extensive recent exploration activity in this area and several significant discoveries have been announced by other companies within the industry. The first Company project at Smith Point, onshore in Chambers County, Texas, contains 40,000 acres under lease or option. The Company, which owns a 15% working interest in this project, completed an 80 square mile 3-D survey during 1997 and has developed four drilling locations for 1998, with further evaluation continuing. The operator of this project is Rutherford Oil Corporation. The second project, Gillock, which is located in Galveston County, Texas, was generated by Aspect Resources LLC. The Company owns a 15% working interest in this project. A 60 square mile 3-D seismic survey is planned for the second quarter of 1998 on this project.
Wilcox Trend. The Company has two projects in the counties of Lavaca and Dewitt, Texas. This area contains production primarily from the Upper and Middle Wilcox formations. The first project, Matthews, is operated by Union Gas Corporation. 3DX has a 20% working interest in this project. A 19 square mile 3-D seismic survey was completed in the third quarter of 1997 and the Company plans to drill its first well in the second quarter of 1998. The other project, Thomaston, is operated by Phillips Petroleum Company and represents one of the first projects in what the Company seeks to be a continuing strategic alliance with Phillips. A 65 square mile 3-D seismic survey was completed on this project in the fourth quarter of 1997 and was acquired and processed using the Company's 3DXpress process for real-time seismic acquisition and processing.
LOUISIANA. The Company has two active exploration projects in Louisiana. The Four Isle Dome prospect in Terrebonne Parish, operated by Louisiana Land and Exploration, targets Miocene-age sands at depths up to 15,000'. The Company has a 5% working interest in Four Isle Dome. The Hayes prospect, in Calcasieu and Jefferson Davis Parishes, targets Miocene age sands at depths up to 14,000'. The Company has a 10% working interest in this project. The Company intends to drill wells on both of these projects in 1998.
MISSISSIPPI/ALABAMA. This area includes onshore properties and generally extends across a seven-county area from Newton County in Southern Mississippi eastward through Southern Alabama to the Florida border. Prospective geology in the trend is characterized by discrete occurrences of basement and salt-related features that deform shallower sand formations to create potential structural traps for oil and gas. The primary historical oil and gas producing formations in the trend have been the Cotton Valley, Lower Haynesville, Smackover and Norphlet. The Company drilled three wells during 1997 on its Lipsmacker project in this area, each of which was unsuccessful. The Company has identified two additional drilling locations on the Lipsmacker project which it intends to drill in 1998.
FLORIDA. The Company has an active exploration effort in the Sunniland trend area in Florida, which is operated by Plains Resources, Inc. ("Plains"). Prospective geology in the trend is characterized by carbonate reefs and shoals. The primary oil and gas producing formation is the Cretaceous-age Sunniland formation, which extends from south of Ft. Myers, Florida to northwest of Miami, Florida. In 1998, the Company plans to drill a well on a prospect that may confirm an extension of the Raccoon Point Field. Cumulative production from this field, located in Collier County, Florida, has exceeded 9.5 MMBOE. The Company and Plains are exploring other project opportunities within the Sunniland trend by acquiring, reprocessing and analyzing 2-D seismic data along with other exploration techniques. The Company holds an 8% working interest in this exploration project.
OTHER PROJECTS
OFFSHORE GULF OF MEXICO. The Company has two producing properties and three active exploratory projects offshore in the Gulf of Mexico. The two producing properties, the Cove project at Matagorda Island Block 487-L and the Hollywood project at East Cameron Block 42, are at this time considered to be fully developed. The Company owns a 7% and 5% working interest in these projects, respectively. One of the exploratory projects is part of the Company's initial joint venture with Phillips Petroleum which commenced in July 1997. On this project, the Company committed to conduct a field study on an existing producing block in the Gulf of Mexico with the objective of identifying additional exploratory or exploitation opportunities. The Company has the right to participate as a 5% working interest partner in future drilling on this block. The other exploratory projects consist of two deep water projects in the flex trend of the Gulf of Mexico. These projects have eight-year lease terms which expire in March 2005. The Company does not currently plan to drill wells on either of these projects during 1998. A third deep water block was also acquired in 1997. The Company participated in the drilling of an exploration well on this block in 1997 which was unsuccessful.
WEST AFRICA. The Company joined its partner, Santa Fe Energy Resources (Cote d'Ivoire) Ltd., in January 1997 to evaluate Block CI-24 which consists of 190,000 acres located in the offshore waters of The Republic of Cote d'Ivoire. Pursuant to a production sharing contract, the Company and its partner purchased and reprocessed existing seismic data, which includes an 81 square mile 3-D seismic survey, and completed an engineering and economic study. The partnership plans to drill the first exploratory well on this project in 1998. The Company owns a 10% working interest in the project. During 1997, the Company and Santa Fe acquired an additional project offshore Cote d'Ivoire, Block CI-202. Late in 1997, the partnership began work on a 400 square kilometer 3-D seismic survey, which was completed during the first quarter of 1998. The Company holds a 10% working interest in Block CI-202. Also during 1997, the Company and Santa Fe acquired a concession offshore Ghana covering a total area of almost 3 million acres. The Company's working interest in the project, which is in the early stage of exploration, ranges from 5% to 10%.
OIL AND GAS RESERVES
All of the Company's proved reserves described below are located onshore and offshore Texas and in the Federal waters offshore Louisiana. All of the Company's proved reserves reflected in the table are proved developed reserves. The reserve estimates as of December 31, 1995 were based on estimates prepared by the Company, while the reserve estimates subsequent to that date were prepared by the independent engineering consulting firm Ryder Scott Company Petroleum Engineers. In accordance with
applicable requirements of the Securities and Exchange Commission, the estimated discounted future net revenues from estimated proved reserves are based on prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. The Company has not provided any estimates of total proved reserves, comparable to those disclosed herein, in any reports filed with federal authorities or agencies other than the Securities and Exchange Commission.
(1) In accordance with statutory requirements of the Securities and Exchange Commission, these amounts represent the present value of estimated future net revenues after income taxes discounted at 10%. The present value amounts are the same before taxes and after projected income taxes as a result of the Company's substantial net operating loss carryforwards.
The process of estimating proved developed and proved undeveloped oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of available geologic, engineering and economic data for each reservoir. The data for a given reservoir may change over time as a result of additional development activity, production history and viability of production under varying economic conditions. The actual production, revenues, severance taxes, development and operating expenditures with respect to the Company's reserves will likely vary from such estimates, and such variances could be material.
PRODUCTIVE WELLS
At December 31, 1997, 1996 and 1995, the Company held interests in the following productive wells:
The number of gross wells equals the total number of wells in which the Company owns a working interest. The number of net wells equals the sum of the Company's fractional working interests owned in gross wells.
OIL AND GAS DRILLING ACTIVITIES
The following table sets forth the gross and net number of productive, dry and total exploratory and development wells that the Company drilled in each of 1997, 1996 and 1995:
As of December 31, 1997, the Company was participating in 2 gross (0.32 net) exploratory wells.
PRODUCTION
The following table summarizes the net volumes of oil and gas produced and sold and the average prices received with respect to such sales from all properties in which the Company held an interest during 1997, 1996 and 1995, respectively.
Average oil and gas operating expenses per Mcfe including severance and ad valorem taxes, were $0.36, $0.33, and $0.57 for 1997, 1996 and 1995, respectively.
ACREAGE
The following table sets forth the developed and undeveloped oil and gas acreage in which the Company held an interest as of December 31, 1997. Undeveloped acreage consists of those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.
In addition to the above acreage, as of December 31, 1997, the Company had agreements, options or farm-ins to acquire leases on 149,319 gross (31,493 net) acres of undeveloped land located in Florida, Mississippi and Texas.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
The Company has not been the subject of any legal proceedings since its organization. There can be no assurance, however, that the Company will not in the future be involved in litigation incidental to the conduct of its business.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the fourth quarter of 1997.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is traded over the counter on the NASDAQ National Market under the symbol "TDXT". The following table sets forth, on a per share basis for the periods indicated, the high and low prices as quoted by the NASDAQ National Market since the shares became publicly traded on December 26, 1996. As of January 23, 1998 there were approximately 580 record holders of the common stock.
DIVIDEND POLICY
The Company has not declared or paid any cash dividends on its common stock since its formation. The Company's current credit agreement prohibits the payment of cash dividends. The Company does not anticipate paying cash dividends on its common stock in the foreseeable future. The Company currently intends to retain any future earnings to finance the expansion and continued development of its business.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The financial information set forth below for the years ended December 31, 1997, 1996, 1995 and 1994 and for the period from inception of operations on January 6, 1993 through December 31, 1993 is derived from the financial statements of the Company, which were audited by Arthur Andersen LLP. This information should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," the financial statements of the Company, the notes related thereto and other financial data included elsewhere in this Form 10-K.
(a) Period from inception of operations, January 6, 1993, through December 31, 1993. (b) As discussed in Note 2 to the financial statements, rental income has been reflected as a reduction of general and administrative expenses in all periods presented. (c) As discussed in Note 2 to the financial statements, earnings per share for periods prior to the Company's initial public offering have been restated to retroactively reflect the effect of SAB No. 98.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following is a discussion of the financial condition and results of operations of the Company for the three years ended December 31, 1997, 1996 and 1995. This discussion should be read in conjunction with the financial statements of the Company, the notes thereto and the other financial data included elsewhere in this Annual Report on Form 10-K.
Overview
The Company is a knowledge-based oil and gas exploration company whose core competence and strategic focus is the utilization of 3-D imaging and other advanced technologies in the search for commercial quantities of hydrocarbons. The Company enters into arrangements that enable it to combine its expertise and exploration capabilities with the operating skills of other oil and gas companies. The Company participates in selected exploration projects as a non-operating working interest owner, sharing both risks and rewards with its partners. The Company commenced operations in January 1993 to take advantage of perceived opportunities emerging from changes in the domestic oil and gas industry, including the divestiture of domestic oil and gas properties, advances in technology and the outsourcing of specialized technical capabilities. By reducing drilling risk through 3-D imaging and analysis, the Company seeks to improve the expected return on investment in its oil and gas projects.
As a working interest partner, the Company shares all project costs in proportion to its working interest percentage. In instances in which exploration and development activities are unsuccessful, the Company incurs an economic loss equal to its proportionate share of project costs prior to the time the project is abandoned. Similarly, the Company incurs economic loss if the Company's proportionate share of revenue generated from production is insufficient to cover the Company's share of project costs.
The Company's future financial results will depend primarily on: (i) the Company's ability to continue to source and screen potential projects; (ii) the Company's ability to discover commercial quantities of hydrocarbons; (iii) the market price for oil and gas; and (iv) the Company's ability to fully implement its exploration and development program, which is dependent on the availability of capital resources. There can be no assurance that the Company will be successful in any of these respects, that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production, or that the Company will be able to obtain additional funding to increase its currently limited capital resources.
The Company recorded a valuation allowance against the estimated amount of deferred tax assets for which realization is uncertain. The Company reviews the valuation allowance at the end of each quarter and makes adjustments, as necessary, if it is determined that it is more likely than not that the deferred tax assets will be realized. As of December 31, 1997, the Company had tax net operating loss carryforwards ("NOL's") of approximately $11.2 million which begin to expire in 2008. As a result of the recent stock transactions, including the initial public offering, there is a yearly limitation placed on the Company's utilization of its NOL's under Section 382 of the Internal Revenue Code of 1986, as amended. See Note 3 to the financial statements of the Company included elsewhere herein.
RESULTS OF OPERATIONS
The following table sets forth certain operating information of the Company during the periods indicated:
- -------------
(1) Includes all lease operating expenses and taxes attributable to the Company's properties, including production and ad valorem taxes.
Oil and Gas Revenues. Oil and gas revenues increased to $3,045,447 for the year ended December 31, 1997 (the "1997 period") from $851,827 for the year ended December 31, 1996 (the "1996 period"). This increase was primarily attributable to higher oil and gas production levels. Production increased by over 277% to 1,216.2 Mmcfe for the 1997 period, from 322.2 Mmcfe for the 1996 period. The increased production resulted from successful wells drilled during the last three months of 1996 and throughout the year in 1997. The number of productive wells in which the Company owned an interest increased to 30 (5.03 net) at the end for the 1997 period from 19 (2.02 net) at the end of the 1996 period. The average sales price for natural gas, which accounted for 93% of equivalent production during the 1997 period, decreased by 2% to $2.46 per Mcf from $2.50 per Mcf for the 1996 period. The average sales price for oil decreased to $18.54 during the 1997 period versus $20.43 per barrel for the 1996 period.
Oil and gas revenues increased to $851,827 for the 1996 period from $274,511 for the 1995 period. This increase was attributable to both higher oil and gas production levels and a significant increase in the average price for both natural gas and oil. Production increased by over 135% to 322.2 Mmcfe for the 1996 period, from 137.3 Mmcfe for the 1995 period. The increased production resulted from successful wells drilled during the last six months of 1995 and throughout the year in 1996. The average sales price for natural gas, which accounted for 84% of equivalent production during the 1996 period, increased by 57% to $2.50 per Mcf for the 1996 period from $1.59 per Mcf for the 1995 period. The average sales price for oil increased to $20.43 during the 1996 period versus $17.89 for the 1995 period.
Lease Operating Expenses. Total lease operating expenses, including production taxes, increased to $436,243 for the 1997 period from $107,676 for the 1996 period. This increase was primarily attributable to the additional costs of operating new producing wells drilled during the last three months of 1996 and throughout the year in 1997 and is comparable to the increase in production during the corresponding periods. Lease operating expenses per Mcfe of production increased slightly to $0.36 per Mcfe for the 1997 period from $0.33 per Mcfe for the 1996 period.
Total lease operating expenses, including production taxes, increased to $107,676 for the 1996 period from $78,533 for the 1995 period. Lease operating expenses per Mcfe decreased to $0.33 for the 1996 period from $0.57 per Mcfe for the 1995 period. Substantially all of this decrease in lease operating expenses per Mcfe was the result of lower lease operating expenses per Mcfe for certain wells completed during the 1996 period. These wells were producing at relatively high rates from onshore, shallow, highly permeable gas
sands and produce relatively small amounts of water, so there are negligible treating or disposal costs associated with such wells. These wells require no artificial lift or compression so the power and maintenance costs associated with such wells are minimal. Additionally, the highly permeable nature of the producing zones resulted in relatively high production rates, which lowered the operating expenses associated with production from these wells on a per Mcfe basis.
Depletion, Depreciation and Amortization Expense. Depletion of oil and gas properties for the 1997 period increased to $2,636,305 from $422,839 for the 1996 period. The increase in depletion of oil and gas properties resulted from both the increase in oil and gas production during the 1997 period, as discussed above, and an increase in the depletion rate for this period. Depletion of oil and gas properties per Mcfe for the 1997 period increased to $2.17 per Mcfe, or 66%, from the rate of $1.31 per Mcfe in the corresponding period in 1996. The increase in the rate resulted from greater additions to evaluated oil and gas property costs than the additions to oil and gas reserves relative to the existing depletion rate per Mcfe. This was principally the result of the costs of unsuccessful wells drilled in 1997.
Depletion of oil and gas properties for the 1996 period increased to $422,839 from $158,336 for the 1995 period. The increase in depletion of oil and gas properties resulted from both the increase in oil and gas production during the 1996 period and a 14% increase in the depletion rate. Depletion of oil and gas properties per Mcfe for the 1996 period increased to $1.31 per Mcfe over the rate of $1.15 per Mcfe in the corresponding period in 1995. The increase in the rate resulted from greater additions to evaluated oil and gas property costs than the additions to oil and gas reserves relative to the existing depletion rate per Mcfe.
Impairment of Oil and Gas Properties. Under the rules of the full-cost accounting method as prescribed by the Securities and Exchange Commission, the Company is required to compare the net costs of its evaluated properties to the net present value of its proved reserves, using prices and costs in effect at the end of each quarterly period. If such evaluated costs, net of accumulated depreciation, depletion and amortization exceed the present value of proved reserves, an impairment charge is required to writedown those excess costs. Oil and gas impairment charges recorded during 1997 were $9,061,240, all of which were attributable to the fourth quarter ended December 31, 1997. This writedown results principally from three factors: (1) the significant decline in oil and gas prices being received by the Company on December 31, 1997 as compared to September 30, 1997, (2) a relatively large investment in three unsuccessful exploratory wells all of which were evaluated in fourth quarter of 1997, and (3) a conservative estimate of proved reserves on a potentially significant discovery on the Ramrod prospect, as discussed in Item 2, "Properties." Impairments recorded during 1996 and 1995 totaled $1,476,690, and $1,627,321, respectively, primarily as a result of the evaluated costs of prospects which had poor drilling results during those periods.
General and Administrative Expense. General and administrative expense, net of costs capitalized to exploration and development projects, increased 39% to $2,532,957 for the 1997 period from $1,827,946 for the 1996 period. The increase is primarily a result of personnel costs associated with hiring which occurred during 1997 and increased professional fees and other costs associated with being a public company offset by a decrease in the amount of $390,616 relating to the amortization of deferred compensation expense. The 1996 amount represented a 61% increase from $1,134,882 incurred during the year ended December 31, 1995. This increase was primarily attributable to the amortization of deferred compensation expense recognized in connection with stock options granted within one year of the filing of the registration statement for the initial public offering, which expense is based on the difference between the option price and the initial $11.00 per share initial public offering price of the common stock.
Interest and Other Income. Interest and other income increased 136% to approximately $585,154 for the 1997 period from approximately $247,960 for the comparable period during 1996. This increase reflects interest income on the higher level of short-term investments during 1997 as a result of investment of the proceeds of the Company's initial public offering. The 1996 amount represents a 5% increase from $236,186 earned during the comparable 1995 period, as a result of interest income attributable to short-term investment of the proceeds of the Series C preferred stock.
Net Loss. As a result of the foregoing, the Company's net loss increased to approximately $11.0 million for the 1997 period from approximately $2.7 million for the 1996 period. The most significant factor which caused the increase in net loss was the impairment of oil and gas properties recorded under full-cost accounting rules. The net loss for 1996 increased slightly from the net loss of $2.5 million in 1995, as a result of all of the foregoing.
LIQUIDITY AND CAPITAL RESOURCES
To date, net cash provided by operating activities has been limited and the Company has funded its oil and gas exploration activities principally through cash provided by the sale of equity securities. On December 26, 1996, the Company consummated an initial public offering of common stock which provided approximately $23.6 million in proceeds, net of offering expenses. In January 1997, the Company's underwriters exercised their over-allotment option to purchase 375,000 additional shares of common stock, resulting in additional net proceeds to the Company of approximately $3.8 million. Approximately $7.5 million of the proceeds of the initial public offering was used to redeem all the issued and outstanding shares of the Series B preferred stock and to pay accrued dividends on the issued and outstanding Series C preferred stock. The balance of the net proceeds were designated to fund the Company's exploration and development capital expenditures and for general corporate purposes, including expenses associated with hiring additional personnel.
The Company's business requires substantial oil and gas capital expenditures. To achieve its near-term goals, the Company has been and will be required to make oil and gas capital expenditures substantially in excess of its net cash flow from operations in order to acquire, explore and develop oil and gas properties. Capital expenditures for oil and gas exploration and development activities during the years ended December 31, 1997, 1996, and 1995, were $19.9 million, $6.2 million and $2.2 million, respectively. The Company has not set a final capital expenditure budget for 1998, but has opportunities to invest in excess of $10 million in exploration and development projects in which the Company currently owns an interest. The Company continues to define new opportunities on both its active exploration projects and new projects. However, the level of capital spending in 1998 is dependent upon the Company's ability to obtain additional sources of funding.
As of December 31, 1997, the Company had a deficit in working capital of approximately $632,000. On December 18, 1997, the Company executed a credit agreement with a commercial bank. The credit agreement provided borrowing capacity of $3.0 million at December 31, 1997. Such borrowing capacity is a function of the value of the Company's proved oil and gas reserves, and is redetermined on a quarterly basis. The bank is currently conducting a schedule redetermination. Based of preliminary indications from the bank, the Company expects the revised borrowing base to be between $2.0 and $3.0 million. The credit agreement is secured by substantially all of the Company's oil and gas properties and contains restrictions on dividends and additional liens and indebtedness and requires the maintenance of a minimum current ratio and net worth, each as defined in the credit agreement. There were no borrowings under the credit agreement during 1997. The Company prefers to use debt only to fund development drilling and not to finance exploration costs. However, the Company expects to use funds available under the credit agreement as a source of financing to fund both exploration and development activities until additional equity or other sources of permanent funding are obtained.
As a result of the Company's periodic review of each of its oil and gas exploration and development properties and its available capital, the Company has on two occasions sold partial interests in specific oil and gas projects to other investors to reduce its total investment commitment to such projects. No gain or loss was recognized on either transaction. The Company is currently reviewing its portfolio and has identified one property in which it intends to sell the majority of its interests to provide additional capital for its exploration program. Such interests consist of both producing wells and future drilling locations. The Company may identify additional properties for sale in the course of its continuing review. There can be no assurance, however, that the Company will be able to sell any such interests, or that the terms of such sale will be acceptable to the Company.
The Company expects that its projected cash flows from currently producing properties will be sufficient to fund its cash general and administrative costs for the next twelve months, including technical employee and related costs which are capitalized under full-cost accounting, and will also provide limited funding for its capital program. The Company's projections of cash flows from currently producing properties are dependent on the following assumptions: (i) there are no significant declines in oil and gas prices below
current levels or anticipated seasonal lows, and (ii) there are no significant declines in oil and gas production from existing properties other than declines in production currently anticipated based on engineering estimates of the decline curves associated with such properties.
To enable it to continue to take advantage of oil and gas exploration and development opportunities, the Company intends to seek additional financing in 1998 to satisfy its capital requirements. The Company is currently evaluating alternatives to obtain additional equity financing, which include sales of common or preferred stock. The Company anticipates funding its short-term capital spending from a combination of expected cash flow generated from operations, borrowings under the credit agreement and proceeds from the sale of oil and gas properties. In the absence of additional financing, the Company could be required to modify the implementation and timing of its oil and gas exploration and development capital spending for 1998, which modification could have a material adverse effect on the Company. No assurance can be given that the Company will be able to obtain additional financing on terms which would be acceptable to the Company, if at all.
EFFECTS OF INFLATION AND CHANGES IN PRICE
The Company's results of operations and cash flows are affected by changing oil and gas prices. If the price of oil and gas increases (decreases), there could be a corresponding increase (decrease) in the operating cost that the Company is required to bear for operations, as well as an increase (decrease) in revenues. Historically, general price inflation has had a minimal effect on the Company.
OTHER
In connection with stock options granted within one year prior to the initial filing of the registration statement relating to the initial public offering, the Company recorded deferred compensation expense based on the difference between the option exercise price and the fair value of the Company's common stock at the date of grant, using the $11.00 per share initial public offering price as an estimate of the fair value. Such deferred compensation is being amortized as additional compensation expense over the vesting period for the options. As of December 31, 1997, the Company had unamortized deferred compensation of $512,132 which will be charged to expense during the next three years. The Company has elected not to adopt the fair value accounting of SFAS No. 123 for employees and continues to account for these plans under APB Opinion No. 25.
The Company has assessed the expected impact of the date change in the Year 2000 on the software programs used in its operations. The majority of the Company's technical applications are not date sensitive. The applications that do have date sensitive aspects, including the Company's accounting software, have either been updated to compensate for the date change in the Year 2000 or are currently being updated by the software vendors. Based on this assessment, the Company does not expect to have any significant operational issues or material costs related to the Year 2000 software issue.
ITEM 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not applicable.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The financial statements required by this item are incorporated under Item 14 in Part IV of this report.
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
PART III
ITEMS 10 TO 13 INCLUSIVE.
These items have been omitted in accordance with the general instructions to Form 10-K Annual Report. The Registrant will file with the Securities and Exchange Commission in April 1998, pursuant to Regulation 14A, a definitive proxy statement that will involve the election of directors. The information required by these items will be included in such proxy statement and are incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a)(3)EXHIBITS:
INDEX TO EXHIBITS
---------------
* filed herewith + management contract or compensating plan
(b) REPORTS ON FORM 8-K:
There were no Current Reports on Form 8-K filed during the quarter ended December 31, 1997 and through the date hereof.
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.
3DX TECHNOLOGIES INC.
By: /s/ Randall D. Keys -------------------------------- Vice President, Finance, Chief Financial Officer and Secretary
Know All Men By These Presents, that each individual whose signature appears below hereby constitutes and appoints C. Eugene Ennis, Randall D. Keys and Peter M. Duncan and each of them individually, his true and lawful agent, proxy and attorney-in-fact, with full power of substitution and resubstitution, for him in his name, place and stead, in any and all capacities, to (i) act on, sign and file with the Securities and Exchange Commission any and all amendments to this report together with all schedules and exhibits thereto, (ii) act on, sign and file with the Securities and Exchange Commission any exhibits to this report, (iii) act on, sign and file such certificates, instruments, agreements and other documents as may be necessary or appropriate in connection therewith and (iv) take any and all actions which may be necessary or appropriate in connection therewith, granting unto such agents, proxies and attorneys-in-fact and each of them individually, full power and authority to do and perform each and every act and thing necessary or appropriate to be done, as fully for all intents and purposes as he might or could do in person, hereby approving, ratifying and confirming all that such agents, proxies and attorneys-in-fact, any of them or any of his or their substitute or substitutes may lawfully do or cause to be done by virtue hereof.
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.
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of 3DX Technologies Inc.:
We have audited the accompanying balance sheets of 3DX Technologies Inc. (a Delaware corporation) as of December 31, 1997 and 1996, and the related statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of 3DX Technologies Inc. as of December 31, 1997 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
Houston, Texas February 25, 1998 ARTHUR ANDERSEN LLP
3DX TECHNOLOGIES INC.
BALANCE SHEETS
The accompanying notes are an integral part of these financial statements.
3DX TECHNOLOGIES INC.
STATEMENTS OF OPERATIONS
The accompanying notes are an integral part of these financial statements.
3DX TECHNOLOGIES INC.
STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
The accompanying notes are an integral part of these financial statements.
3DX TECHNOLOGIES INC.
STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these financial statements.
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
3DX Technologies Inc. ("3DX" or the "Company") began operations in January 1993 to offer 3-D seismic imaging and computer-aided exploration capabilities as a partner to experienced oil and gas operators. The Company combines its 3-D imaging capabilities with the operator's local knowledge and infrastructure to evaluate and exploit drilling opportunities. The Company primarily invests in prospects in the Gulf Coast region of the U.S., where 3-D seismic evaluation and interpretation is expected to reduce drilling risk. Working interests in major prospects have ranged from 5% to 40% in property investments to date.
The Company was initially funded by its three founding stockholders and by Landmark Graphics Corporation (Landmark), a Houston company which is a leading supplier of interactive computer-aided exploration systems used by geoscientists to analyze subsurface data in the process of exploring for and producing petroleum reserves. The three founding stockholders of 3DX were formerly employed by Landmark.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Oil and Gas Properties
3DX accounts for its oil and gas properties using the full-cost method. All costs associated with the acquisition, exploration and development of oil and gas properties, including such costs as leasehold acquisition costs, geological and geophysical expenditures, dry hole costs and tangible and intangible development costs, are capitalized as incurred. Included in capitalized costs for 1997, 1996 and 1995 are general and administrative costs of $1,962,691, $1,146,722, and $618,614, respectively. Such capitalized costs include payroll and related costs of exploration department personnel which are directly attributable to the Company's current exploration and development activities. Other costs, such as office and facilities costs, technical equipment maintenance, depreciation and support and communication costs are also capitalized to the extent they are attributed to the Company's oil and gas property acquisition and exploration activities and would not otherwise be incurred if such activities were not being undertaken.
Dispositions of proved oil and gas properties are reported as adjustments to capitalized costs, with gains and losses not recognized unless such adjustments would significantly alter the relationship between capitalized costs and estimated proved oil and gas reserves.
The evaluated costs of oil and gas properties plus estimated future development and dismantlement costs (including plugging, abandonment and site-restoration costs) are charged to operations as depreciation, depletion, and amortization using the unit-of-production method based on the ratio of current production to estimated proved recoverable oil and gas reserves. The Company excludes unevaluated property costs from the depreciation, depletion and amortization calculations until proved reserves have been discovered or a determination of impairment has been made. Unevaluated properties are evaluated for impairment on a property-by-property basis.
Impairment of capitalized costs of oil and gas properties is determined for each cost center on a country-by-country basis. For each cost center, to the extent that capitalized costs of oil and gas properties, net of related accumulated depreciation, depletion and amortization and any related deferred income taxes, exceed the future net revenues of estimated proved oil and gas reserves, discounted at 10% and net of any income tax effects, plus the lower of cost or fair value of unevaluated properties, such excess costs are charged to operations as an impairment of oil and gas properties. Writedowns of $9,061,240, $1,476,690 and $1,627,321 were recorded during 1997, 1996 and 1995, respectively.
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
Other property and equipment, consisting of technical interpretation equipment and related software and office furniture, equipment and leasehold improvements are recorded at cost. Depreciation is determined on a straight-line basis over the estimated useful lives of the assets, which range from three to five years. Depreciation of other property and equipment totaled $728,005, $459,189 and $288,014 for 1997, 1996 and 1995, respectively, and is included in general and administrative expenses.
Accounting for Income Taxes
The Company provides deferred income taxes at the balance sheet date for the estimated tax effects of differences in the tax basis of assets and liabilities and their financial statement carrying amounts.
Natural Gas Revenues
Natural gas revenues are recorded using the sales method, whereby the Company recognizes natural gas revenues based on the amount of gas sold to product purchasers on its behalf. The Company has no material gas imbalances.
Rental Income
The Company has an informal income-sharing arrangement with a seismic processing company whereby the Company receives a percentage of the seismic processing company's gross billings in exchange for office space and the use of technical equipment provided by the Company. The Company's share of billings under this arrangement amounted to $264,651, $229,556, and $58,195 in 1997, 1996 and 1995, respectively, and is reflected as a reduction of the Company's general and administrative expenses.
Net Loss per Common Share
In February 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 128, "Earnings Per Share," which establishes new computation, presentation, and disclosure requirements for earnings per share for public companies. The statement is effective for financial statements issued for periods ending after December 15, 1997. In connection with this new statement, the Securities and Exchange Commission issued Staff Accounting Bulletin (SAB) No. 98, which prescribes a new accounting treatment for the impact on earnings per share of "nominal issuances" of common stock and common stock options issued within one year prior to the filing of a registration statement for an initial public offering of common stock. Under the prior rules, common stock options having a nominal exercise price issued within one year of an initial public offering were required to be reflected retroactively in the computation of earnings per share for all periods even if the effect was antidilutive. Under SAB No. 98, these common stock options are only required to be reflected in earnings per share if the effect is dilutive. The Company has restated all prior periods to reflect this change in accounting principle. The effect of this change is presented in the following table:
The computation of basic and diluted net loss per common share was based entirely on the weighted average common shares outstanding. Stock options which are potentially dilutive were excluded from the net loss per common share calculation in each of the years presented as the effect would have been antidilutive. See Note 7 for the number of stock options outstanding.
Statements of Cash Flows
For the purposes of the statements of cash flows, the Company considers all highly liquid investments purchased with original maturities of three months or less to be cash equivalents.
Concentration of Credit Risk
All of the Company's receivables are due from oil and gas producing companies located in the United States. The Company has not experienced any significant credit losses related to its receivables.
Major Customers
Operators for producing oil and gas wells in which the Company holds working interests sold the Company's share of oil and gas production to three major customers during the years ended December 31, 1997, 1996 and 1995. Sales to one customer represented 63% and 58% of oil and gas revenues in 1997 and 1996, respectively. During 1995, sales to two customers represented 79% of oil and gas revenues.
Fair Value of Financial Instruments
The carrying amounts of cash and cash equivalents, accounts receivable, account payable and accrued liabilities are short-term in nature and approximate fair value.
Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Oil and gas reserve estimates, which are the basis for units-of-production depletion and impairment of oil and gas properties, are inherently imprecise and are expected to change as future information becomes available.
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
Prior Year Reclassifications
Certain prior year amounts have been reclassified to conform with the current presentation.
Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board issued SFAS No. 130, "Reporting Comprehensive Income" and SFAS No. 131, "Disclosures About Segments of an Enterprise and Related Information." SFAS 130 establishes standards for reporting and displaying of comprehensive income and its components. SFAS No. 131 establishes standards for the way that public enterprises report information about operating segments and related information in interim and annual financial statements. SFAS 130 and 131 are effective for periods beginning after December 15, 1997. These two statements will not have any effect on the Company's 1997 financial position or results of operations. Management is presently evaluating what, if any, additional disclosures may be required when these two statements are implemented.
3. INCOME TAXES
Significant components of the Company's deferred tax liabilities and assets are as follows:
The Company did not record any current or deferred income tax provision or benefit in any of the periods presented. The Company's provision for income taxes differs from the amount computed by applying the statutory rate due principally to the valuation allowance recorded against its deferred tax asset account relating to net operating tax loss carryforwards. Management believes that such allowance is necessary until there is greater assurance that the net operating tax loss carryforwards can be utilized.
The Company has recorded a valuation allowance against its deferred tax assets in each year to reflect the estimated portion for which realization is uncertain. As of December 31, 1997, the Company had tax net operating loss carryforwards of approximately $11.2 million which begin to expire in 2008. As a result of recent stock transactions, including the initial public offering, the Company's utilization of its net operating losses under Section 382 of the Internal Revenue Code is limited.
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
4. CREDIT AGREEMENT
On December 18, 1997, the Company executed a credit agreement with a commercial bank. The credit agreement expires on June 30, 2002 and provides for total borrowings of $25 million, subject to availability under a borrowing base calculation which is redetermined on a quarterly basis. The credit agreement, which is secured by substantially all of the Company's producing oil and gas properties, had a current availability of $3.0 million under Tranche A of the agreement as of December 31, 1997. There was no availability under Tranche B. Tranche A advances carry an interest rate, at the Company's option, of either the London Interbank Offered Rate ("LIBOR") plus 2% or the lender's prime rate. Tranche B advances carry an interest rate of either LIBOR plus 4% or the lender's prime rate plus 2%. The credit agreement contains restrictions on dividends and additional liens and indebtedness and requires the maintenance of a minimum current ratio and net worth, each as defined in the credit agreement. There were no borrowings under the credit agreement during the year ended December 31, 1997.
5. MANDATORILY REDEEMABLE PREFERRED STOCK
Series B
In November 1993, the Company issued 29,000 Series B equity units at $100 per unit, for total proceeds before offering costs of $2,900,000. In October 1994, the Company issued 25,000 additional Series B equity units at $100 per unit, for total proceeds before offering costs of $2,500,000. Each equity unit consisted of one share of redeemable Series B preferred stock, par value $.01 per share ("Series B Preferred Stock"), at $94.1558 per share and 30.215 shares of common stock, par value $.01 per share, at $0.19 per share. The Series B Preferred Stock carried a redemption value of $100 per share. The difference between the sales price and the redemption value was subject to pro-rata accretion which was charged to retained earnings, such that the book value of each share of Series B Preferred Stock would equal $100 at the required mandatory redemption in two installments commencing in November 2002. The Series B Preferred Stock also carried a cumulative annual dividend, payable on December 31 of each year, of $12.50 per share if paid in cash or .13276 shares of Series B Preferred Stock if paid in stock. All dividends were paid in additional shares of Series B Preferred Stock. Series B equity units totaling $1,025,000, or 19% of the total proceeds of the offering, were sold to related parties, consisting of officers of the Company, consultants and Landmark. Additionally, units totaling $3,032,000, or 56%, were sold to two investors and their affiliates, each of which required the right to designate one member of the Board of Directors of the Company.
In connection with the initial public offering which was completed on December 26, 1996 (see Note 6), all of the issued and outstanding shares of Series B Preferred Stock were redeemed. The unamortized redemption premium of $365,810 was charged to the Company's accumulated deficit.
Series C
During the period from July 26, 1995 through September 25, 1995, the Company sold a total of 2,662,241 shares of senior redeemable convertible Series C preferred stock, par value $.01 per share ("Series C Preferred Stock"), at $3.00 per share, for total proceeds before offering costs of $7,986,723. The Series C Preferred Stock carried a cumulative dividend at an annual rate of $.24 per share if paid in cash or .08 shares of Series C Preferred Stock if paid in stock, payable or accruing quarterly, commencing on December 31, 1995. Unpaid dividends earned interest at an annual interest rate of 8%. During the year ended December 31, 1996, the Company paid accrued dividends on Series C Preferred Stock of $795,649. Shares totaling $925,515, or 12% of the total proceeds, were sold to related parties, including consultants to and officers of the Company, as well as two directors and their affiliates. Additionally, one investor purchased
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
shares totaling $3,999,999, or 50% of the offering, on the condition that it be given the right to designate one member of the Company's Board of Directors.
Each share of Series C Preferred Stock was convertible into one share of common stock. Subsequent to the reverse stock split in October 1996, each share was convertible into .517 shares of common stock. The Series C Preferred Stock could be automatically converted to common stock upon the occurrence of certain conversion events, including the successful completion of an initial public offering of the Company's common stock if certain pricing and other criteria were met. The Series C preferred stock also contained a mandatory-redemption feature under which the stock could be redeemed, at the option of at least 67% of the holders, at the $3.00 per share liquidation value in two installments commencing in November 2002.
In October 1995, the Board of Directors granted the holder of each share of Series C Preferred Stock a warrant to purchase additional shares equal to 10% of the shares owned by such holder, at an exercise price of $3.00 per share. Such shares were exercisable at any time until the earlier of (a) five years from the date of issuance and (b) the effective date of an initial public offering of the Company's securities. No value was assigned to these warrants as the computed value of the warrants using the Black-Scholes model was zero.
In connection with the Initial Public Offering which was completed on December 26, 1996, all of the issued and outstanding shares of Series C Preferred Stock, and all outstanding Series C Preferred Stock warrants were converted into common stock.
Stock Subscriptions Receivable
Certain officers and directors of the Company purchased Series B equity units and Series C Preferred Stock for promissory notes, which are reflected as an offset to equity in the accompanying financial statements. The promissory notes were full recourse and carried interest at a fixed rate of 6% per annum. The notes from the Company's officers were collateralized by certain vested stock options the individuals held from their former employer. The principal and accrued interest on all notes for the purchase of equity securities of the Company were paid off as of December 31, 1996.
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
The following table summarizes the 1996 and 1995 activity of Series B and Series C Preferred Stock:
6. STOCKHOLDERS' EQUITY
In May 1995, the stockholders approved a 10-for-1 stock split of the Company's common stock. In October 1996, the stockholders approved a reverse stock split whereby holders of common stock received .517 shares of common stock for every share previously owned. All references in this report to number of common shares outstanding reflect stock splits retroactively to inception of the Company.
On December 26, 1996, the Company completed an initial public offering for the sale of 2,400,000 shares of common stock at $11.00 per share, less offering costs. In January 1997, the Company's underwriters exercised their 30-day over-allotment option to purchase 375,000 additional shares of common stock at the offering price of $11.00 per share, less underwriting discounts and commissions. Total proceeds to the Company from the initial public offering, net of offering costs, were approximately $27.4 million.
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
7. STOCK OPTIONS
In June 1994, the Board of Directors approved the 1994 Stock Option Plan (the "Plan") for employees, officers, directors and certain consultants of the Company. The ten year options vest over four years for employees (25% at the end of each of the first two years and monthly over the last 24 months. For directors and consultants, the options vest 50% at the end of the first year and 25% at the end of the second and third years. Certain of these options are eligible for accelerated vesting upon a change of control of the Company. The Company has reserved a total of 2,004,937 shares of common stock for issuance under this Plan, of which 611,778 shares were available for grant as of December 31, 1997. The following table summarizes option balances and activity for the Plan:
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
In connection with stock options granted within one year of the initial public offering, the Company recorded deferred compensation as additional paid in capital with a corresponding offset to stockholders' equity. The amount of deferred compensation is based on the difference between the option exercise price and the $11.00 per share initial public offering common stock price for those options. Deferred compensation is being amortized as compensation expense over the option vesting period, and totaled $477,014, $867,630 and $50,991 during the years ended December 31, 1997, 1996 and 1995, respectively. Unamortized deferred compensation as of December 31, 1997 amounted to $512,132.
In October 1995, the FASB issued SFAS No. 123. SFAS No. 123 is a new standard of accounting for stock-based compensation and establishes a fair value method of accounting for awards granted after December 31, 1995 under stock compensation plans. The Company has elected to continue accounting for employee stock options under Accounting Principles Board Opinion No. 25. Had the Company elected to apply SFAS No. 123, the estimated effects on net income and earnings per share resulting from grants made after December 31, 1994 would have been as follows:
Volatility was not considered in the calculation of option values prior to December 26, 1996, as the Company was not publicly traded.
8. SAVINGS PLAN
The Company's employees participated, prior to January 1, 1998, in Landmark's 401-K employee savings plan (the Plan), which became effective upon inception of the Company. The Plan covers substantially all employees and entitles them to contribute up to 16% of their annual compensation, subject to limitations imposed by the Internal Revenue Code. The Company did not make any contributions to the Plan on behalf of employees during any of the years presented. Effective January 1, 1998, the Company established a separate employee savings plan exclusively for its employees with substantially the same terms and provisions as the previous Plan.
3DX TECHNOLOGIES INC.
NOTES TO FINANCIAL STATEMENTS - (CONTINUED)
9. RELATED PARTIES
Prior to the Company's initial public offering of common stock in December 1996, Landmark was the beneficial owner of greater than 5% of the issued and outstanding Common Stock and was considered a related party. In connection with its initial capitalization, the Company entered into a Technical Services Agreement with Landmark pursuant to which Landmark agreed to grant to the Company ongoing licenses to use Landmark software as Landmark first made such software available to its customers. In addition, the agreement provides for a strategic alliance between Landmark and the Company, which enables the Company to request, and requires Landmark to deliver, enhancements and modifications to existing Landmark software and, in certain instances, to develop new software for use in the Company's oil and gas exploration efforts. In exchange for such rights, the Company has agreed to serve as an alpha test site for software developed by Landmark. During 1997, 1996 and 1995, the Company purchased technical equipment and software, supplies and hardware maintenance from Landmark in the amounts of $645,109, $267,007 and $521,128, respectively.
In addition, the Company and Landmark were also parties to an informal arrangement pursuant to which the Company's employees participated in Landmark's medical insurance plan, life insurance plans and 401(k) employee savings plan. The Company reimburses Landmark for the costs of providing these benefits, together with an administrative fee. Effective January 1, 1998, the Company ceased to participate in this informal arrangement and established separate benefit plans exclusively for its employees.
In April 1995, the Company sold 66.67% of its working interest in the Double Diamond Jones Ranch prospect to a group of individual investors who are stockholders in the Company through a limited partnership. Proceeds from the sale, which represented both the estimated fair market value of the interest sold as well as 3DX's proportionate cost to date on the prospect, amounted to $480,931. No gain or loss was recorded on this transaction.
10. COMMITMENTS
In March 1995, the Company entered into a 5-year office lease agreement. Future minimum payments under this non-cancelable office lease are as follows at December 31, 1997:
Rental expense under this office lease amounted to $94,633, $94,633 and $83,919 during the years ended December 31, 1997, 1996 and 1995, respectively.
3DX TECHNOLOGIES INC.
SUPPLEMENTARY INFORMATION - UNAUDITED
QUARTERLY FINANCIAL DATA (UNAUDITED)
The table below sets forth selected unaudited quarterly financial information for 1997 and 1996:
(a) As discussed in Note 2, rental income has been reflected as a reduction of general and administrative expense in all periods presented. (b) As discussed in Note 2, the Company recorded a writedown of oil and gas properties of $19,061,240 in the fourth quarter of 1997, and writedowns totaling $1,476,690 in 1996, including $1,090,718 in the second quarter of 1996. (c) Net loss per common share are computed independently for each of the quarters presented and therefore may not sum to the totals for the year. (d) As discussed in Note 2, earnings per share amounts for periods prior to the Company's initial public offering have been restated to retroactively reflect the effect of SAB No. 98.
3DX TECHNOLOGIES INC.
SUPPLEMENTARY INFORMATION - UNAUDITED (Continued)
RESULTS OF OPERATIONS FOR OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The following table sets forth the Company's results of operations for oil and gas producing activities for the years ended December 31, 1997, 1996 and 1995.
The results of operations from oil and gas producing activities were determined in accordance with Statement of Financial Accounting Standards No. 69, "Disclosures About Oil and Gas Producing Activities" ("SFAS No. 69") and, therefore, do not include corporate overhead, interest and other general income and expense items.
COSTS RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
The aggregate amounts of capitalized costs relating to the Company's oil and gas producing activities and the related accumulated depletion, depreciation, and amortization and impairment at December 31, 1997, 1996 and 1995 were as follows:
The costs of unevaluated oil and gas properties consists of projects which at each date were undergoing exploration or development activities or were projects on which the Company planned to commence such exploration activities in the future. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. The Company believes that substantially all of the unevaluated properties at December 31, 1997 will be fully evaluated within the succeeding two-year period.
3DX TECHNOLOGIES INC.
SUPPLEMENTARY INFORMATION - UNAUDITED (Continued)
The following table represents an analysis of remaining unevaluated oil and gas property costs at December 31, 1997 according to the years in which they were incurred:
The following table sets forth the costs incurred in the Company's oil and gas property acquisition, exploration and development activities for the years presented:
OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
RESERVES
The process of estimating proved developed and proved undeveloped oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of available geologic, engineering and economic data for each reservoir. The data for a given reservoir may change over time as a result of, among other things, additional development activity, production history and viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur in the future. Although every reasonable effort is made to ensure that reserve estimates are based on the most accurate and complete information possible, the significance of the subjective decisions required and variances in available data for various reservoirs make these estimates generally less precise than other estimates presented in connection with financial statement disclosures.
The following information regarding estimates of the Company's proved oil and gas reserves, all located in the United States, is based on reports prepared on behalf of the Company by the Company's independent petroleum engineers. The following table sets forth the changes in the Company's total proved reserves for the years ended December 31, 1997, 1996 and 1995. All of the reserve quantities reflected in the table below are proved developed reserves.
3DX TECHNOLOGIES INC.
SUPPLEMENTARY INFORMATION - UNAUDITED (Continued)
Standardized Measures of Discounted Future Net Cash Flows
The Company's standardized measure of discounted future net cash flows, and changes therein, related to proved oil and gas reserves are as follows (in thousands):
CHANGES IN STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS:
3DX TECHNOLOGIES INC.
SUPPLEMENTARY INFORMATION - UNAUDITED (Continued)
Estimated future cash inflows are computed by applying year-end prices of oil and gas to year-end quantities of proved reserves. Future price changes are considered only to the extent provided by contractual arrangements. Estimated future development and production costs are determined by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. Estimated future income tax expense is calculated by applying year-end statutory tax rates to estimated future pretax net cash flows related to proved oil and gas reserves, less the tax basis (including net operating loss carryforwards projected to be usable) of the properties involved.
These estimates were determined in accordance with SFAS No. 69. Because of unpredictable variances in expenses and capital forecasts, crude oil and gas prices and oil and gas reserve volume estimates, as well as the statutory pricing and discounting assumptions used in these cash flow estimates, management believes the usefulness of this data is limited. These estimates of future net cash flows do not necessarily represent management's assessment of estimated fair market value, future profitability or future cash flow to the Company. Management's investment and operating decisions are based upon reserve estimates that include proved as well as probable reserves and upon different price and cost assumptions from those used herein.
The future cash flows presented in the "Standardized Measures of Discounted Future Net Cash Flows" are based on year-end oil and gas prices for oil and gas reserves which as of December 31, 1997 were approximately $16.17 per barrel of oil and approximately $2.29 per Mcf of gas. The Company does not have oil and gas reserves which are committed under long-term oil and gas sales or hedging contracts.
INDEX TO EXHIBITS
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* filed herewith + management contract or compensating plan