-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, RRUoAw/SVOMvSJiXCsHRM1KO2lu3rH/02AUNQPJ/28KODe+33hY1Yl4UTYqh248d xvlYhNhIh3wFzYebWAkIZA== 0000899243-97-000488.txt : 19970329 0000899243-97-000488.hdr.sgml : 19970329 ACCESSION NUMBER: 0000899243-97-000488 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970328 SROS: NASD FILER: COMPANY DATA: COMPANY CONFORMED NAME: 3DX TECHNOLOGIES INC CENTRAL INDEX KEY: 0000915518 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760386601 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 000-21841 FILM NUMBER: 97566355 BUSINESS ADDRESS: STREET 1: 12012 WICKCHESTER STREET 2: SUITE 250 CITY: HOUSTON STATE: TX ZIP: 77084 BUSINESS PHONE: 7135793398 MAIL ADDRESS: STREET 1: 12012 WICKCHESTER STREET 2: SUITE 250 CITY: HOUSTON STATE: TX ZIP: 77079 10-K 1 FORM 10-K ================================================================================ U.S. SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K For Annual and Transition Reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] for the fiscal year ended December 31, 1996 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] Commission File No. 0-21841 3DX TECHNOLOGIES INC. (Exact name of registrant as specified in its charter) Delaware 76-0386601 (State of Incorporation) (IRS Employer Identification Number) 12012 Wickchester, Suite 250, Houston, Texas 77079 (Address of principal executive office) (Zip Code) Registrant's telephone number, including area code: (281) 579-3398 Securities registered pursuant to Section 12(b) of the Exchange Act: (None) Securities registered pursuant to Section 12(g) of the Exchange Act: Common Stock, $0.01 par value (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the common stock held by non-affiliates of the registrant (treating all executive officers and directors of the registrant and their respective affiliates, for this purpose, as if they may be affiliates of the registrant) was approximately $42,000,000 on March 26, 1997 based upon the closing sale price of the Common Stock on such date of $10-1/4 per share on the NASDAQ National Market as reported by The Wall Street Journal. As of March 26, 1997, the registrant had 7,216,177 shares of common stock issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the 3DX Technologies, Inc. Proxy Statement for the 1997 Annual Meeting of Stockholders, which proxy statement will be filed under the Securities Exchange Act of 1934 within 120 days of the end of the registrant's fiscal year ended December 31, 1996 are incorporated by reference into Part III of this Form 10-K. ================================================================================ TABLE OF CONTENTS PART I Item 1 Business............................................................. 1 Item 2 Properties........................................................... 8 Item 3 Legal Proceedings.................................................... 14 Item 4 Submission of Matters to a Vote of Security Holders.................. 14 PART II Item 5 Market for Registrant's Common Equity and Related Stockholder Matters 15 Item 6 Selected Financial Data.............................................. 16 Item 7 Management's Discussion and Analysis of Financial Condition and Results of Operations............................................... 18 Item 8 Financial Statements and Supplementary Data.......................... 26 Item 9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............................................. 26 PART III Item 10 Directors and Executive Officers of the Registrant.................. 27 Item 11 Executive Compensation.............................................. 27 Item 12 Security Ownership of Certain Beneficial Owners and Management...... 27 Item 13 Certain Relationships and Related Transactions...................... 27 PART IV Item 14 Exhibits, Financial Statement Schedules, and Reports On Form 8-K.... 28 SIGNATURES........................................................................ 31
i Cautionary Statement Regarding Forward-Looking Statements This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Actual results, events and circumstances could differ materially from those set forth in such statements due to various factors. Such factors include the possibility that the drilling of wells in projects in which the Company has a working interest may be delayed or abandoned, actual rates of production may not reach anticipated levels and opportunities for the Company to acquire future working interests in additional projects on terms considered reasonable to the Company may be limited or unavailable, changing economic, regulatory and competitive conditions, other technological developments and other risks and uncertainties, including those set forth herein. 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. There can be no assurance that the Company will be successful in any of these respects or that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production. The Company expects that its available cash and expected cash flows from operating activities will be sufficient to meet its financial obligations and fund its planned exploration and drilling activities for the short term (twelve months from December 31, 1996), provided, that (i) there are no significant declines in oil and gas prices below current levels or anticipated seasonal lows, (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 and (iii) the Company is able to discover and produce commercial quantities of oil and gas within the time frame, at rates of production the Company has predicted. The Company intends to satisfy its long-term liquidity requirements from a combination of expected cash flow generated from operations, borrowings from financial institutions (which may be secured by the Company's oil and gas reserves) and from future public or private offerings of equity and/or debt securities. For liquidity purposes, the Company considers "long-term" to be the second, third and fourth twelve month periods following December 31, 1996. PART I 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 only 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 carefully 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 rigorous 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 select 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. As of March 26, 1997, the Company's current portfolio includes 11 active operator partners and 29 exploration projects primarily located onshore and near shore within the Gulf Coast region from south Texas to southern Florida. Although the Company's current geographic focus is principally the Gulf Coast region, the Company has and will continue to pursue opportunities that may become available in other select geographic areas as its capital resources increase. The Company believes that it can effectively and efficiently participate in an increasing number of concurrent projects by continually improving its techniques for acquiring and analyzing data. One example of such an improvement is the Company's 3DXpress process, an innovative exploration technique that improves the quality of seismic data and significantly compresses the time frame traditionally required for acquisition, processing, imaging and analysis. This process 1 allows analysis of 3-D data while the seismic survey is being conducted, giving the Company's explorationists the ability to ensure data quality and steer data collection toward more promising prospective areas. Utilizing this technology, the Company has been able to image and analyze a larger number of projects concurrently and to identify potential drilling sites more rapidly and accurately. 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. The Company believes that its methods of applying 3-D imaging and analytical technology provide it with knowledge and information superior to that produced by companies engaged in many aspects of finding and producing oil and gas. 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 Company believes that the quality of information obtained from its application of 3-D imaging is dependent to a large extent on its ability to capitalize on the intelligence, acquired knowledge and creativity of the experienced geoscientists and engineers it employs. These experts have broad expertise and experience from their collective participation in over 300 3-D seismic projects in diverse geologic trends throughout the world. 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 enhance its ability to recruit, retain and motivate such experts, the Company is committed to providing its oil and gas finding 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 research to continually develop and adapt technology that the Company believes 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 more areas where prospects are more likely to exist. Utilizing this technology, the Company has been able to image and analyze a larger number of projects concurrently and identify potential drilling sites more rapidly and accurately. This ability to effect near-real time acquisition, processing and analysis of seismic data allows the Company to achieve optimum data and image quality, resulting in an improved ability to economically locate commercial quantities of hydrocarbons. The Company also believes that its application of emerging technologies, such as migration velocity analysis and depth migration technology, provides the Company with a competitive advantage in its ability 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 the strict application of its rigorous screening process and, based on its experience, continually adapts the selection criteria to ensure that the Company participates only in those projects that are likely to maximize the return on its capital investment. The Company considers high quality projects to be projects that: (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 balanced 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 2 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 maximize its 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. In exploration trends, the Company is generally able to obtain a larger working interest than it possessed with respect to its initial project investment. 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 known to 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. . 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. During 1996, the Company reviewed 78 potential projects, of which 17 met the Company's basic business initial screening criteria. Subsequent to December 31, 1996 through March 26, 1997, the Company has reviewed 32 additional potential projects of which ten met the Company's basic business initial screening criteria. To evaluate a potential project, the Company considers geographic location, scale, geological model, anticipated drilling prospects, number of pay zones and 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. . Technical Evaluation. If the project satisfies the Company's initial business screening criteria, it 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. . 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 all potential reservoirs within the project's area. The data collection, processing and analysis are usually managed by the Company to assure its integrity and consistency. . 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. . 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 a loss equal to its proportionate share of project costs prior to the time the project is abandoned. Similarly, the Company will incur a loss if the 3 Company's proportionate share of revenue generated from production is insufficient to cover the Company's share of project costs. The Company believes that its application of increasingly stringent criteria for project selection which results in participation in higher quality projects, its geographic focus in the Gulf Coast Region, its increasing base of knowledge and experience, its ability to acquire unpromoted working interests and its participation in a larger number of projects have reduced the probability of future impairment writedowns. However, no assurance can be given that future impairment writedowns, which may be material in amount, will not be incurred by the Company. Project Generation 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 possessing 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. Significant Business Relationships As of March 26, 1997 the Company's current portfolio included 11 active operator partners. Such partners are identified below: Alta Mesa Resources, Inc. Harrison Interests, Ltd. Ameritex Ventures, Ltd. Plains Resources, Inc. Bellwether Exploration Company PrimeEnergy Management Corporation Browning Oil Company Santa Fe Energy Resources, Inc. Cox & Perkins Exploration, Inc. Texoil Inc. Esenjay Petroleum Corporation In February 1996, the Company formed a joint venture and strategic alliance with Plains Resources, Inc. ("Plains"), the Company's partner in the Sunniland trend, pursuant to which the companies agreed to jointly pursue exploitation and exploration opportunities. Pursuant to the joint venture, the Company acquired a working interest of up to 8% in the Sunniland trend exploration project and an initial working interest of approximately 7% in the Four Isle Dome project. In addition to their joint venture, the Company and Plains have entered into a strategic alliance which has an initial term of five years. Under the terms of the alliance, the Company has the right to participate in exploitation or exploration projects where 3-D seismic is applicable (i) for up to 15% of Plains' interest in the Illinois Basin, located in southern Illinois, and in the Los Angeles Basin, located in Los Angeles County, California, and (ii) for up to 20% of Plains' interest in any additional properties Plains might acquire. The Company also has a strategic alliance with PrimeEnergy Management Corporation, a subsidiary of PrimeEnergy Corporation, covering an area of mutual interest in the Texas Gulf Coast trend and a contractual relationship on projects with Esenjay Petroleum Corporation, a privately held corporation, in the Texas Gulf Coast trend and the Mississippi/Alabama trend which, if successful, could lead to a broader geographic alliance. The Company has newly developed an additional strategic partnership with Santa Fe Energy Resources, Inc. This partnership resulted in the successful bidding of four out of seven blocks in the deep water areas of Mississippi Canyon and Ewing Bank in March 1997, and will give the Company significant upside drilling possibilities for 1998 and 1999. The Company believes that these types of joint ventures and alliances involving long-term partner relationships enhance the flow of opportunities presented to the Company and reduce the risk involved in determining the quality of the partner and the relationship. As part of its strategy, the Company attempts to convert successful relationships on individual projects with quality partners into long-term strategic alliances. 4 In addition to its relationship with certain operator partners, the Company maintains an agreement with Landmark Graphics Corporation ("Landmark Graphics") pursuant to which the Company has acquired a license to use certain software manufactured by Landmark Graphics. The Company also maintains informal agreements with Landmark Graphics which entitle the Company's employees to participate in Landmark Graphics' medical insurance plan, life insurance plans and 401(k) plan. The Company currently anticipates that its informal agreements with Landmark Graphics will remain in place until at least December 31, 1997. 3-D Imaging Technology The Company's oil and gas finding 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. By the mid-to-late 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 advantageous 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 a significantly better quality and provides significantly greater advantages than the data acquired by 2-D seismic technology. The higher fidelity and resolution of 3-D data result 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. 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. The Company currently has 16 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 those geoscientists and engineers has between five to 20 years of experience involving the utilization of seismic data imaging and analysis, and they have collectively participated in over 300 3-D seismic projects in diverse geologic trends throughout the world. 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. By assembling for each project a multidisciplinary team of Company and project partner experts, led by one of the Company's geoscientists or engineers, the Company is able to capitalize on the expertise and experience of its partners' technical staff while retaining management and overall responsibility for the imaging and analytical phase of the project. 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. In addition to being responsible for finding oil and gas quickly and economically, the Company's project managers are in charge of scheduling, budgeting and timely reporting. To insure that all responsibilities assigned to various team members are completed in a systematic manner and that all variables arising in connection with the imaging and analysis of a specific project are thoroughly reviewed and integrated into the imaging and analysis procedures, all of the Company's project managers are required to adhere to the Company's technical template for each project for which they are responsible. Generally, the Company's project manager maintains responsibility for the project throughout the project life, which typically extends through drilling of the last exploratory well. 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. Application of the 3DXpress process, AVO, inversion and geostatistics to the process of reservoir characterization and innovative utilization of technologies including digital orthomaps and GPS locators are examples of such improvements which the Company believes enable it to acquire higher quality seismic data than that which may be acquired without effective utilization of such technologies and techniques. The Company believes such higher quality data enable it to locate hydrocarbon reserves more accurately thereby creating for it and its project partners a 5 significant competitive advantage. 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 four of the five 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., Hampton-Russell Software, Inc., Landmark Graphics 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 that 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, the Minerals Management Service ("MMS") has the authority to promulgate regulations requiring financial assurance from owners and operators of "offshore facilities" to cover potential environmental cleanup and restoration costs. Although there has been uncertainty about the scope and applicability of these requirements, Congress recently adopted legislation that has been signed by the President that excludes certain inland facilities with a worst-case oil spill risk of 1,000 barrels or less from the financial assurance requirements. Under this new legislation, the amount of financial responsibility that must be demonstrated for an offshore facility was reduced to $35.0 million if the facility is located seaward of the seaward boundary of a State, or $10.0 million if located landward of the boundary. These limitations can be adjusted upward should MMS believe there are additional risks. 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. 6 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 Environmental Protection Agency 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 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. Through operator partners, the Company indirectly maintains insurance 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 or protect against loss of revenues due to well failure. There can be no assurance that any insurance obtained by 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 7 additional named insured on the insurance policies procured and maintained by operator partners. The Company cannot predict the continued availability of such insurance or the availability of insurance at premium levels that justify its purchase. If 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 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 basis of competition 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 At March 26, 1997, the Company had 21 full-time employees including 16 geoscientists and engineers and one person, the President and Chief Executive Officer, engaged principally in the management of the Company. The Company believes that its relationship with its employees is good. None of the Company's employees is covered by a collective bargaining agreement. In addition, at March 26, 1997, the Company had arrangements with eight individuals to provide, from time to time, various consulting and professional services. The agreements with these consultants provide for the payment of fees and expenses for services rendered. The Company expects to continue a program, which it commenced in August 1996, to hire recent college graduates and advanced degree holders. Item 2. Properties Significant Projects and Properties The Company's exploration activities are currently primarily focused on three Gulf Coast trends, the Texas Gulf Coast trend, the Mississippi/Alabama trend and the Sunniland trend. In addition, the Company is pursuing select projects in South Louisiana and elected in December 1996 to participate in its initial international project located in the Republic of Cote d'Ivoire. Geologically, 3-D imaging of the structural and stratigraphic complexities common in the Gulf Coast provides the Company with an ability to identify significant hydrocarbon potential in and around existing fields that could not be detected with 2-D and conventional 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 encountering multiple reservoirs. As demonstrated by its election to participate in a project located in the Republic of Cote d'Ivoire, 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. Technically, the extensive drilling history within Gulf Coast trends provides a powerful subsurface and production database to which seismic data can be calibrated. These data provide the foundation required to design a seismic program that optimizes resolution at targeted reservoirs. These data, when combined with 3-D seismic data, provide a more accurate assessment of reservoir quality, productivity and reserve potential and in some instances, fluid type. The following sets forth a brief summary of the Company's exploration trend areas and significant projects and properties. Although the Company is aggressively pursuing activities in each of the following areas, there can be no assurance that drilling opportunities will be identified or, if drilled, will be successful. 8 Texas Gulf Coast Trend In the Texas Gulf Coast trend, the Company anticipates drilling between 20 to 30 gross wells in 1997 with budgeted capital expenditures approximating $10 to $15 million net to the Company's working interest. Of these wells, two have commenced drilling as of March 26, 1997. The Company and its partners control in excess of 125,000 gross acres in this trend. Between February 1996 and March 26, 1997, the Company and its partners have drilled nine wells in the trend, including the three drilled in 1997, eight of which have encountered commercial quantities of oil and gas. The Company has successfully utilized the 3DXpress process on 8,400 acres overlying six of these discoveries. At February 28, 1997, these six wells were producing in excess of 10.0 MMcfe/d. The Company has completed utilizing the 3DXpress process on five 3-D imaging program and has scheduled four additional programs during the second and third quarters of 1997 totaling 180 square miles in the trend. The Company's working interests in this trend currently range from 6% to 40%. The Texas Gulf Coast trend includes both onshore and offshore properties and generally extends along the Texas coast from Houston south to the Mexican border. 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 historical oil and gas producing formations include the Wilcox, Frio, Yegua and Miocene. The Company currently holds working interests in the Texas Gulf Coast trend as described below: Cove and McPac Fields. The Company proposed and drilled a well with its partner, Bellwether Exploration Company, into a new fault block of the Cove and McPac Fields in August 1996 and discovered commercial quantities of gas in two reservoirs. The Company owns a 7% working interest in the Cove McPac Gas Unit Number One well which is currently producing in excess of 9.0 MMcfe/d from 115 feet of perforated zones. The Cove and McPac Fields' acreage is held by production and is located in Matagorda Island Block 487- L, Texas state waters, 96 miles southwest of Houston in 60 feet of water. Gila Bend. The Company joined its partner, Ameritex Ventures, Ltd., in the project in December 1995. Integration of a 16-square mile 3-D seismic survey with the geology and production data resulted in a well being spud in July 1996. This well discovered four distinct pay zones of gas and condensate and currently is producing in excess of 3.0 MMcfe/d from the first of the four pay zones. The Company and its partners control 3,525 gross acres in Gila Bend, and the Company owns working interests ranging from 6% to 10%. Geronimo. The Company completed acquisition of a 77-square mile 3-D seismic survey in October 1996 utilizing the 3DXpress process in the Geronimo project, which is located in San Patricio County, Texas. Primary target formations include the Frio and Vicksburg sands, which are currently producing in fields in the area. The project area covers approximately 25,000 gross acres in which the Company owns a 15% working interest. The Company's partners in this project include Esenjay Petroleum Corporation ("Esenjay"). Commencement of drilling operations is scheduled on this project for the second quarter of 1997. Bright Falcon. The Company joined its partner, Cox & Perkins Exploration, Inc., in 1993, in the Bright Falcon project, the Company's first project in the Texas Gulf Coast trend. Since then, the Company and its partner have drilled seven wells, five of which were discoveries. As of March 26, 1997, three wells, one of which was recompleted in November 1996, are producing in the Bright Falcon project. The Bright Falcon wells were drilled into Yegua and Frio gas formations after a 26-square mile 3-D seismic survey covering the Lost Bridge-Bright Falcon fields was analyzed by the Company. The project is located in Jackson County, Texas and its acreage is held by production. The Company owns a 17% working interest in this project. Mississippi/Alabama Trend In the Mississippi/Alabama trend, the Company anticipates drilling five to eight gross wells in 1997 with budgeted capital expenditures approximating $3 million net to the Company's working interest. The Company and its partner, Esenjay, control over 41,000 gross acres in the trend. The Company completed acquisition of a 3-D seismic survey utilizing the 3DXpress process on a 64- square mile area in November 1996. The Company's first well in this trend commenced drilling in the first quarter of 1997. The Company currently has working interests ranging from approximately 10% to 25% in its properties in the trend. The Mississippi/Alabama trend 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 9 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. Sunniland Trend The Company's partner in the Sunniland trend project is Plains Resources, Inc. ("Plains"). As part of its anticipated initial exploration of the Sunniland trend in 1997, the Company plans to acquire a 3-D survey utilizing the 3DXpress process and to drill a well on a prospect that the Company believes 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 its partner currently are exploring other 3-D project opportunities within the Sunniland trend by acquiring, reprocessing and analyzing 2-D seismic data along with other evaluation methods. The Company and its partner control approximately 81,000 gross acres in the trend. The Company owns an 8% working interest therein excluding the currently established production. The Raccoon Point Field is within the Cretaceous Sunniland Trend, which extends from south of Ft. Myers, Florida to northwest of Miami, Florida. Prospective geology in the trend is characterized by carbonate reefs and shoals. The trend's primary historical oil and gas producing formation is the Sunniland formation. South Louisiana Projects Four Isle Dome. To March 26, 1997, the Company has identified multiple drilling targets in the upper Miocene zone of Four Isle Dome, located in Terrebone Parish, Louisiana. The first of these wells in which the Company owned a 20% working interest was spud by the Company and its partner, Plains, in October 1996 targeting the upper Miocene at an approximate depth of 14,000 feet. Although the primary objective sands were encountered, electric logs indicated that those sands would not produce commercial quantities of hydrocarbons. The Company also is participating with Plains in an additional well which is currently drilling below 14,000 feet. Prior to the Company's involvement in the project, Plains and its partners acquired a 51-square mile 3-D seismic survey in late 1995. In February 1996, the Company signed a joint venture agreement with Plains covering Four Isle Dome. Since then, the Company has assisted with completion of the seismic processing, has analyzed the seismic data and has identified drilling targets. The Company and its partner control approximately 19,000 gross acres on this project. Raceland. The Company and its partner, Texoil, Inc., plan to drill the first exploratory well, targeted at Miocene formations, in the Raceland project during the second quarter of 1997. The Raceland project is located near the Raceland Field in Lafourche Parish, Louisiana. Acquisition of a 64-square mile 3-D seismic survey on the underlying salt dome was completed in August 1996 and the Company currently is analyzing the seismic data. The nearby Raceland Field has produced over 24 MMBbls and 134 Bcf from Miocene sands at depths of 7,000 feet to 16,000 feet. The Company and its partner control over 17,000 gross acres in the Raceland project in which the Company owns a 5% working interest. East Cameron 42. The Company and its partners, Gulf Star Energy, Inc. and Santa Fe Energy Resources, Inc., drilled a gas discovery in Miocene sands on East Cameron 42, the Company's Hollywood project, in July 1996. The well is currently producing in excess of 4.0 MMcfe/d. East Cameron 42 is located in federal waters approximately 175 miles southwest of New Orleans in 45 feet of water. The project acreage is held by production, and the Company owns a 5% working interest in this well. Other Projects International Project. 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 are required to purchase and reprocess existing seismic data which includes an 81 square mile seismic survey and complete an engineering and economic study during a one year evaluation period. Thereafter, if the partnership elects to proceed, the drilling of one exploration well is required during each of two subsequent years. The Company owns a 10% working interest in the project. Lanell Farms. The Company and its partner, Browning Oil Company, have completed drilling operations on a well at Lanell Farms, located in Gaines County, West Texas, which targeted the Devonian and Wolfcamp formations. With respect to the Wolfcamp formation, the well has been tested at rates greater than 200 Bbls/d. 10 Production equipment was installed and initial sales began in January 1997. The Company and its partner concluded that the Devonian formation will not produce commercial quantities of hydrocarbons. A second well, targeting the Wolfcamp formation, is scheduled to spud in the second quarter 1997. The 2,000-acre project area is covered by a 3-D seismic survey in which the Company participated. The Company owns a 6% working interest in the first well and a 10% working interest in the second well to be drilled. 11 Oil and Gas Reserves All of the Company's proved reserves described below were located onshore in West Texas and onshore and near-shore in the Louisiana and Texas Gulf Coast region. All of the Company's proved reserves reflected in the table were proved developed reserves. The Company's estimated total proved reserves of oil and natural gas as of December 31, 1994, 1995 and 1996, based upon estimates prepared by the Company, were as set forth in the following table: At December 31, --------------------- 1994 1995 1996 ------ ------ ------ (1) Estimated Net Proved Reserves Data (in thousands): Gas (MMcf)........................... 1,237 443 2,464 Oil and condensate (MBbl)............ 40 41 32 Total equivalent (MMcfe)............. 1,477 689 2,656 Pre-tax present value of proved reserves discounted at 10% (in thousands)(2).......................... $1,606 $ 771 $6,623 Standardized Measure of Discounted Future Net Cash Flows (in thousands)(2)(3)....................... $1,606 $ 771 $6,623 ______________ (1) Estimates of the Company's net proved gas and oil and condensate reserves and related revenue estimates as of December 31, 1996 were prepared by the independent engineering consulting firm Ryder Scott Company Petroleum Engineers. (2) Because the Company has substantial net operating loss carryforwards, the amounts reflected are the same before taxes and after projected income taxes. (3) In accordance with requirements of the Securities and Exchange Commission, represents the present value of estimated future net revenues after income taxes discounted at 10%. In addition to the discussion below, reference is made to the Financial Statements including the Supplemental Oil and Gas Information (unaudited) included in the notes thereto included elsewhere herein. Such discussion also contains information with respect to the Company's reserves at December 31, 1994, 1995 and 1996. The Company has not included estimates of total proved reserves, comparable to those disclosed herein, in any reports filed with federal authorities or agencies other than the Commission. At December 31, 1994, 1995 and 1996, the Company held interests in the following productive wells: At December 31, ------------------------------------------------------- 1994 1995 1996 ------------------------------------------------------- Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2) --------- ------- --------- ------- --------- ------- Oil Wells....... 6 0.06 7 0.16 8 0.31 Gas Wells....... 4 0.56 5 0.74 11 1.71 (1) The number of gross wells equals the total number of wells in which the Company owns a working interest. (2) The number of net wells equals the sum of the Company's fractional working interests owned in gross wells. In general, estimates of economically recoverable oil and gas reserves and of the future net revenues therefrom are based upon a number of variable factors and assumptions, such as historical production from the subject properties, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and natural gas prices and future operating costs, all of which may vary considerably from actual results. All such estimates are to some degree speculative and classifications of reserves are only attempts to define the degree of speculation involved. For these reasons, estimates of the economically recoverable oil and gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Therefore, the actual production, revenues, severance and excise taxes, development and operating expenditures with respect to the Company's reserves will likely vary from such estimates, and such variances could be material. 12 The Company's producing wells have been producing for only a short period of time. Accordingly, estimates of future production based on this limited history are subject to various uncertainties with regard to the rate at which current production will decline. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history, and subsequent evaluation of the same reserves, based upon production history, will result in variations, which may be substantial, in the estimated reserves. In accordance with applicable requirements of the 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. Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. 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 1994, 1995 and 1996. Gross Wells Net Wells ---------------------- ----------------------- Productive Dry Total Productive Dry Total ---------- --- ----- ---------- --- ----- Exploratory Wells(1) Year ended December 31, 1994.. 7 5 12 0.59 0.70 1.29 Year ended December 31, 1995.. 2 - 2 0.28 - 0.28 Year ended December 31, 1996.. 7 7 14 0.74 0.84 1.58 Development Wells Year ended December 31, 1994.. - - - - - - Year ended December 31, 1995.. - - - - - - Year ended December 31, 1996.. 3 - 3 0.60 - 0.60 As of March 26, 1997, the Company was participating in two gross and 0.26 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 the years ended December 31, 1994, December 31, 1995 and December 31, 1996, respectively.
Gas Oil ------------------------------- ------------------------------ Net Production Average Sales Net Production Average Sales (MMcf) Price/Mcf (MMcf) Price/Bbl -------------- ------------- -------------- ------------- Year ended December 31, 1994 105.1 $1.93 6.1 $16.58 Year ended December 31, 1995 97.1 1.59 6.7 17.89 Year ended December 31, 1996 271.2 2.50 8.5 20.43
Average oil and gas operating expenses per Mcfe were $0.10, $0.44 and $0.15 for the years ended December 31, 1994, 1995 and 1996, respectively. With the addition of severance and ad valorem taxes, the total average oil and gas operating expenses per Mcfe were $0.24, $0.57 and $0.33 for the years ended December 31, 1994, 1995 and 1996, respectively. 13 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, 1996. Undeveloped acreage is considered to be those lease acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. Developed Undeveloped ------------ ------------- Gross Net Gross Net Alabama................................. - - - - Florida................................. - - 5,000 400 Texas................................... 2,976 462 46,219 6,381 Louisiana............................... 2,880 144 8,900 499 Mississippi............................. - - 3,280 492 ----- --- ------ ----- Total................................... 5,856 606 63,399 7,772 ===== === ====== ===== In addition to the above acreage, as of March 26, 1997, the Company has leases, options or farm-ins to acquire leases on 438,934 gross (50,226 net) acres of undeveloped land located in Alabama, Florida, Louisiana, Mississippi, Texas and the Republic of Cote d'Ivoire. Item 3. Legal Proceedings Since its organization through March 26, 1997, the Company has not been involved in any legal proceedings. 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. Submission of Matters to a Vote of Security Holders During the three-month period ended December 31, 1996, the written consent of the holders of the Company's issued and outstanding capital stock was solicited and acquired in three instances. On December 11, 1996 prior to the consummation of the Company's initial public offering ("Initial Public Offering" or the "Offering") of Common Stock, the holders of 66.7%, 69.4% and 70.9% of the Company's issued and outstanding Redeemable Preferred Stock, Series B, par value $.01 per share (the "Series B Preferred Stock"), the Company's issued and outstanding Senior Redeemable Convertible Preferred Stock, Series C, par value $.01 per share (the "Series C Preferred Stock") and the Company's issued and outstanding Common Stock, respectively, entitled vote thereon, approved: (i) a Restated Certificate of Incorporation which was filed in the office of the Secretary of State of the State of Delaware on December 19, 1996, (ii) Second Amended and Restated Bylaws of the Company and (iii) increases in the number of shares of Common Stock reserved for issuance pursuant to the Company's 1994 Stock Option plan which number of reserved shares was increased to 1,501,813 shares of Common Stock. In addition, on December 19, 1996, the holders of 74.8%, 66.7% and 63.6%, respectively of the issued and outstanding Series B Preferred Stock, Series C Preferred Stock and Common Stock, entitled to vote thereon, approved a further Restated Certificate of Incorporation which was filed in the Office of the Secretary of the State of Delaware on December 26, 1996. On December 19, 1996, the holders of 74.8%, 66.7% and 63.6% of the Company's issued and outstanding Series B Preferred Stock, Series C Preferred Stock and Common Stock, respectively, entitled to vote thereon, approved by written consent an amendment to the Company's Restated Certificate of Incorporation which amendment was filed in the office of the Secretary of State of the State of Delaware on December 24, 1996. In accordance with Delaware law, notice of these actions taken by holders of a majority of the Company's capital stock was given to all other holders of the Company's issued and outstanding capital stock from whom consents were not solicited who were entitled to vote on such matters. Among those holders of the Company's capital stock from whom consents were solicited, in each instance, 100% of such holders approved the action being taken. 14 PART II 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 bid quotations as quoted by the NASDAQ National Market and reported since the shares became publicly traded. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions. High Low ------ ----- 1996 Fourth Quarter (beginning December 19, 1996)...... $11 $11 1997 First Quarter (through March 26, 1997)............ $12 1/2 $10 On March 26, 1997, the closing sale price of the Company's Common Stock as reported on the NASDAQ system was $10 1/4. On March 26, 1997, there were approximately 50 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 and although the Company is currently able to pay certain cash dividends, the Company does not presently anticipate paying any 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. The future payment of cash dividends on the Common Stock will be within the sole discretion of the Company's Board of Directors and will depend upon the earnings, capital requirements and financial position of the Company, applicable requirements of Delaware General Corporation Law, general economic conditions and other factors considered relevant by the Company's Board of Directors. Recent Sales of Unregistered Securities On October 6, 1995, the Company issued to the holders of Series C Preferred Stock, warrants to purchase an aggregate of 266,224 shares of Series C Preferred Stock. The exercise price of each warrant was $3.00 per share, subject to adjustment and cashless exercise based on a predetermined formula. Prior to the expiration of the warrants on December 26, 1996, the date of consummation of the Company's Initial Public Offering of Common Stock, each of the holders thereof exercised the warrants. As a result, 142,682 shares of Series C Preferred Stock were issued and such shares were immediately converted into 73,767 shares of Common Stock. No brokers or underwriters were involved in the above issuance. All certificates for the shares Series C Preferred Stock and Common Stock so issued bear restrictive legends. In connection with each of the offerings and sales described above, the Company relied on Section 3(a)(9) for an exemption from the registration requirements of the Securities Act. 15 Item 6. Selected Financial Data The financial information set forth below as of December 31, 1993 and for the period from inception of operations (January 6, 1993) through December 31, 1993 and as of and for the years ended December 31, 1994, 1995 and 1996 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 the other financial data included elsewhere in this Form 10-K.
Period from Inception of Operations (January 6, 1993) Statement of Operations Data: Through Years ended December 31, -------------------------------------- December 31, 1993 1994 1995 1996 ----------------- ---- ---- ---- Revenues: Oil and gas............................ $ - $ 303,836 $ 274,511 $ 851,827 Rental income.......................... 127,034 100,962 58,195 229,556 Interest and other..................... 7,528 52,817 236,186 247,960 ------------- ---------- ----------- ----------- Total revenues....................... 134,562 457,615 568,892 1,329,343 ------------- ---------- ----------- ----------- Costs and expenses: Lease operating........................ - 14,225 60,877 49,016 Production taxes....................... - 19,812 17,656 58,660 Impairment of oil and gas properties... - - 1,627,321 1,476,690 Depletion, depreciation & amortization. 65,368 210,347 446,350 883,962 General and administrative............. 596,267 598,244 905,063 1,596,143 Interest and other..................... 88,006 - - 236 ------------- ---------- ----------- ----------- Total costs and expenses............. 749,641 842,628 3,057,267 4,064,707 ------------- ---------- ----------- ----------- Net loss from operations................ (615,079) (385,013) (2,488,375) (2,735,364) Dividends on preferred stock............ (52,790) (421,696) (1,058,956) (520,393) Redemption premium on Series B Preferred Stock........................ - - - (365,810) Accretion on preferred stock............ (14,353) (30,367) (48,408) (54,844) ------------- ---------- ----------- ----------- Net loss from operations applicable to common stockholders.................... $ (682,222) $ (837,076) $(3,595,739) $(3,676,411) ============= ========== =========== =========== Primary and fully diluted net loss per common share........................... $(0.59) $(0.33) $(1.14) $(1.16) ============= ========== =========== =========== Weighted average number of common shares outstanding..................... 1,154,329 2,534,175 3,148,826 3,162,934 ------------- ---------- ----------- -----------
16
Balance Sheet Data: December 31, ---------------------------------------------------- 1993 1994 1995 1996 ---- ---- ---- ---- Working capital........................ $2,003,266 $2,102,586 $ 7,264,763 $15,987,485 Property and equipment, net............ 635,696 2,669,177 2,935,093 8,576,331 Total assets........................... 2,791,694 5,196,795 10,450,504 26,827,189 Accrued dividends...................... - - 275,256 - Long-term debt......................... - - - - Series B Preferred Stock............... 2,630,825 5,451,522 6,277,826 - Series C Preferred Stock............... - - 7,903,833 - Common Stockholders' equity (deficit).. $ 16,365 $ (673,972) $(4,240,319) $24,573,624
17 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, 1994, 1995 and 1996. This discussion should be read in conjunction with the Financial Statements of the Company, the notes related thereto and the other financial data included elsewhere in this Form 10-K. Overview 3DX Technologies Inc. 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 only 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 carefully 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 working interest acquired by the Company in any project is determined through negotiations 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 known to the Company prior to its commitment to participate. Expenditures made in oil and gas exploration vary with each project depending principally on the costs related to the acquisition of land and seismic data, analysis of seismic data and the expenses incurred in drilling exploratory and development wells. In addition, costs attributable to the acquisition of 3-D seismic data are initially greater than those which would be incurred if 2-D seismic data were acquired. The Company, however believes that the benefits derived from the use of 3-D imaging greatly outweigh the incremental costs which are incurred through the utilization of 3-D imaging rather than 2-D imaging. Specifically, by utilizing 3-D imaging technology, the Company is able to acquire greater volumes and enhanced quality of subsurface information not attainable with 2-D seismic data. Through the use of 3-D imaging technologies, the Company is able to acquire in one instance seismic data covering a prospective well target which may have been previously identified and any other prospective well targets in the surrounding geographic area. As a result of the Company's utilization of the higher quality and significantly larger quantity of information obtainable only from 3-D imaging technology, the Company has enhanced its ability to identify drill site locations which are expected to maximize production from any particular well, may enhance the Company's overall project return through the identification of multiple prospective wells, and enable the Company to avoid unnecessary drilling expenditures which it might otherwise incur had it relied only upon 2-D seismic data. 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 a loss equal to its proportionate share of project costs prior to the time the project is abandoned. Similarly, the Company will incur a loss if the Company's proportionate share of revenue generated from production is insufficient to cover the Company's share of project costs. During 1993, the Company commenced its business operations and initiated participation as a working interest partner in two projects, the Bright Falcon project and the Fausse Pointe project. The Company did not have oil and gas revenues during 1993. To finance its operations and acquire funds for capital expenditures, the Company sold equity securities through private placement offerings raising approximately $3.5 million. During 1994, the Company acquired working interests in seven projects and successfully drilled and completed seven gross wells. The Company's oil and gas revenues in 1994 totaled $304,000. To supplement operating revenues and enable it to continue to implement its exploration program, the Company raised additional capital in the approximate amount of $2.5 million through a private placement of its equity securities in October 1994. 18 During 1995, the Company continued to expand its operating activities by acquiring working interests in six additional projects and successfully drilling and completing two gross wells. The Company recognized total oil and gas revenues in the amount of $275,000 during 1995. Through a private placement, the Company raised additional capital in the approximate amount of $8.0 million to finance continued capital expenditures in connection with the further implementation of its exploration and development program. During the year ended December 31, 1996, the Company recognized oil and gas revenues totaling $851,827 and owned working interests in 24 projects, 15 of which were acquired during this period. During the year ended December 31, 1996, the Company drilled 17 wells and completed ten gross successful wells. Since it commenced operations in January 1993, the Company has acquired working interests in 35 projects of which it has discontinued its participation in six projects. As of March 26, 1997, the Company is currently participating as the owner of working interests in 29 projects. The Company elected to discontinue its participation in the six projects after determining that such projects were unlikely to produce commercial quantities of hydrocarbons. Such determinations were made after drilling an unsuccessful well in each of three projects and after reviewing "seismic data" prior to drilling in each of the other three projects. Subsequent to December 31, 1996, the Company has acquired working interests in four additional projects and discontinued its participation in one project in which it had a working interest as of December 31, 1996. The Company currently anticipates that it will participate in the drilling of between 35 and 40 gross wells during 1997, although the number of wells may increase as additional projects are added to the Company's portfolio. As of March 26, 1997, three of these wells had commenced drilling. There can be no assurance that such wells will be drilled and if drilled that such wells will be successful. 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. There can be no assurance that the Company will be successful in any of these respects or that the prices of oil and gas prevailing at the time of production will be at a level allowing for profitable production. In connection with the continuing expansion of its exploration and development program, the Company has commenced efforts to increase its technical and support staff and has added seven employees subsequent to the consummation of the Initial Public Offering. As a result, the Company anticipates that its general and administrative expenses will increase in 1997 as compared to 1996. Further, the Company anticipates incurring additional legal, administrative and accounting costs in future periods as a result of the Company becoming a publicly-held company in December 1996. The Company uses the full-cost method of accounting for its oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain general and administrative costs that are directly attributable to the Company's acquisition, exploration and development activities, are capitalized in a "full-cost pool" for each country as they are incurred. The Company records depletion of its full-cost pool using the unit of production method. To the extent that such capitalized costs in each full-cost pool (net of depreciation, depletion and amortization and related deferred taxes) exceed the present value (using a 10% discount rate) of estimated future net after-tax cash flows from proved oil and gas reserves, such excess costs are charged to operations. Once incurred, a write-down of oil and gas properties is not reversible at a later date. The Company incurred such charges in the aggregate amount of $1.6 million and $1.5 million for the years ended December 31, 1995 and 1996, respectively, as a result of a determination that the Company's aggregate investment in developed and abandoned projects exceeded the present value of the Company's proved reserves as of December 31, 1995 and as of March 31, 1996 and June 30, 1996. The Company believes that its increasingly stringent criteria for project selection which results in participation in higher quality projects, its geographic focus in the Gulf Coast Region, its increasing base of knowledge and experience, its ability to acquire unpromoted working interests and its participation in a larger number of projects have made the probability of future impairment writedowns less likely. However, no assurance can be given that future impairment writedowns, which may be material in amount, will not be incurred by the Company. The Company has 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 will make adjustments if it is determined that it is more likely than not that the deferred tax assets will be realized. As of December 31, 1996, the Company had tax net operating loss carryforwards ("NOL's") of $5,999,000 which begin to expire in 2008. As a result of the recent stock transactions, including the Offering, there is a yearly limitation placed on the Company's utilization of its NOL's 19 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. Working Interests Acquired Subsequent to December 31, 1996 The Company continually reviews opportunities for participation in exploration projects. Subsequent to December 31, 1996, the Company has acquired working interests in the following additional projects: Project Anticipated Commencement ---------------------- Project Location Date Acquisition Drilling ---------------- ------------ ----------- -------- Matagorda County, Texas..... March 1997 $ 520,000 $ 200,000 Federal Offshore............ March 1997 697,660 1,100,000 Federal Offshore............ March 1997 100,944 1,000,000 Federal Offshore............ March 1997 41,155 1,900,000 San Patricio County, Texas.. March 1997 401,000 180,000 ---------- ---------- Total.................... $1,760,759 $4,380,000 ========== ========== The amounts described as "acquisition" include the estimated costs expected to be incurred by the Company based on its respective working interest percentage prior to drilling, specifically with respect to land acquisition and seismic imaging. The amounts described as "drilling" are estimates of the expenses that the Company anticipates incurring, based on its respective working interest percentage, in connection with drilling of the first exploration well. Future drilling costs will be dependent upon the success of the initial exploration well, the target depths of wells and the number of wells drilled. The Company is currently unable to predict or estimate with any certainty the amounts of such expenditures. Results of Operations The following table sets forth certain operating information of the Company during the periods indicated: Year Ended December 31, ----------------------- 1994 1995 1996 ---- ---- ---- Production: Gas (MMcf) 105.1 97.1 271.2 Oil and condensate (MBbls) 6.1 6.7 8.5 Total equivalent (MMcfe) 141.7 137.3 322.2 Average sales price: Gas (per Mcf) $ 1.93 $ 1.59 $ 2.50 Oil and condensate (per Bbl) 16.58 17.89 20.43 Average Expenses (per Mcfe): Lease operating (1) $ 0.24 $ 0.57 $ 0.33 Depletion of oil and gas properties(2) 0.64 1.15 1.31 - ------------- (1) Includes all direct expenses of operating the Company's properties, as well as severance and ad valorem taxes. (2) Excludes depreciation and amortization of technical interpretation equipment, office furniture and equipment and office leasehold improvements, impairments of oil and gas properties and amortization of organization costs. 20 Year Ended December 31, 1996 Compared to Year Ended December 31, 1995 Oil and Gas Revenues. Oil and gas revenues increased 210% to $852,000 for the year ended December 31, 1996 from $275,000 for the comparable period of 1995. Of this increase, $369,000, or 64%, was attributable to an increase in production and $208,000, or 36%, was attributable to an increase in the average sales price for natural gas and oil. Production increased by 135% to approximately 322.1 MMcfe for the year ended December 31, 1996, from 137.3 MMcfe for the comparable 1995 period. The increased production reflected production for the entire year ended December 31, 1996 from the successful wells drilled during the last six months of 1995. In addition, production for the year ended December 31, 1996 included production from a well completed in June 1996, a well completed in August 1996, and five successful wells completed in a single project during the period July through December 1996. The average sales prices for oil increased 14% to $20.43 during the year ended December 31, 1996 from $17.89 for the comparable 1995 period. The average sales price for natural gas increased by 57% to $2.50 per Mcf for the year ended December 31, 1996 from $1.59 per Mcf for the comparable 1995 period. Lease Operating Expense. Lease operating expense (including production and ad valorem taxes) increased by 37% to $108,000 for the year ended December 31, 1996 from $79,000 for the comparable 1995 period. This increase was primarily attributable to the increase in 1996 production. Lease operating expense per Mcfe decreased by 42% to $0.33 for the year ended December 31, 1996 from $0.57 for the comparable 1995 period. Substantially all of the decrease in lease operating expense per Mcfe was the result of the successful completion of five wells within a single project during the period July through December 1996. These wells had lower lease operating costs per Mcfe than wells from which production had been obtained in the comparable prior period. The lower lease operating expense per Mcfe of the five wells completed during the period July through December 1996 relate principally to the nature and location of the completed wells. These five wells are producing 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 completed wells require no artificial lift or compression so that the power and maintenance costs associated with such wells are minimal. Additionally, the highly permeable nature of the producing zones results in relatively high production rates, which lowers all fixed expenses associated with production from these wells on a per Mcfe basis. By contrast, wells completed in prior periods, in general, have had higher expenses due to the need for artificial lift and/or compression associated with producing these wells. Also, many of these wells have produced water in addition to hydrocarbons, resulting in additional expenses for treatment and disposal of such fluid. Although the Company is unable to predict with certainty the lease operating expense per Mcfe that may be incurred in the future, the Company does not anticipate that such expenses on a per Mcfe basis will be in amounts less than those which were incurred during the year ended December 31, 1996. Depletion, Depreciation and Amortization Expense. The major components of depletion, depreciation and amortization are depletion of oil and gas properties and administrative depreciation and amortization. Depletion of oil and gas properties for the year ended December 31, 1996 increased by 167% to $423,000 from $158,000 for the comparable period in 1995. The increase in depletion of oil and gas properties resulted from the increase in oil and gas production. Depletion of oil and gas properties per Mcfe for the year ended December 31, 1996 increased 14% to $1.31 from $1.15 due to an increase in reserves at a slower rate in 1996 than the increase in the Company's evaluated property full cost pool of capitalized costs. Depreciation and amortization of technical interpretation equipment, office furniture and equipment and office leasehold improvements increased 60% to $461,000 for the year ended December 31, 1996 from $288,000 for the comparable 1995 period. This increase was primarily attributable to the acquisition of additional technical interpretation equipment and software with an approximate cost of $422,000 during the year ended December 31, 1996. Impairment of Oil and Gas Properties. Oil and gas impairment charges recorded as of March 31, 1996 and June 30, 1996 totaled approximately $1.5 million, primarily as a result of completion of the evaluation of two prospects which had poor drilling results during these periods. The addition of the total investment in these prospects to evaluated costs resulted in impairment charges under the Company's accounting policy for oil and gas properties, as described in Note 2 to the Financial Statements. During the year ended December 31, 1996, there was a downward revision in the Company's January 1, 1996 oil and gas reserve estimates. Such revisions resulted from additional production and performance information which first became available during 1996. 21 The Company incurred similar oil and gas impairment charges during the year ended December 31, 1995 in the aggregate amount of approximately $1.6 million. As a result of an increase in oil and gas prices and the completion of six wells in the period July through December 1996 which resulted in the related increase in the Company's estimate of proved reserves, the present value (using a 10% discount rate) of estimated future net after-tax cash flow from proved oil and gas reserves exceeded the Company's aggregate investment in developed and abandoned projects by approximately $3.2 million as of December 31, 1996. General and Administrative Expense. General and administrative expense, net of costs capitalized to exploration and development projects, increased by 76% to $1,596,000 for the year ended December 31, 1996 from $905,000 for the comparable 1995 period. This increase was primarily attributable to compensation expense recognized in connection with stock options granted within one year of the initial filing of 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. Rental Income. Rental income increased by 297% to $230,000 for the year ended December 31, 1996 from $58,000 for the comparable 1995 period. The Company derives rental income pursuant to an agreement to exchange use of certain of the Company's technical and office equipment by an independent seismic processing company for a percentage of the gross fee billings of such seismic processing company. As a result, the rental income recognized by the Company varies significantly from period to period. Interest and Other Income. Interest and other income increased by 5% to $248,000 for the year ended December 31, 1996 from $236,000 for the comparable 1995 period, primarily as a result of an increase in short-term investments made with the proceeds of the sale of Series C Preferred Stock. Net Loss. As a result of the foregoing, the Company's net loss increased by 8% to $2.7 million for the year ended December 31, 1996 from $2.5 million for the comparable 1995 period. 22 Year Ended December 31, 1995 Compared to Year Ended December 31, 1994 Oil and Gas Revenues. Oil and gas revenues decreased by 10% to $275,000 for the year ended December 31, 1995 from $304,000 for the comparable 1994 period. Of this decrease, $9,000 or 31% was attributable to a decrease in production and $20,000 or 69% was attributable to a decrease in the average sales price for gas. Production decreased by 3% to 137.3 MMcfe for the year ended December 31, 1995 from 141.7 MMcfe for the comparable 1994 period, primarily as a result of a decline during 1995 in production from certain wells in the Bright Falcon project as compared to 1994. The reduction in revenue attributable to a decline in production from this particular project was partially offset by new production from other wells completed in the last six months of 1995. The average sales price for oil increased by 8% to $17.89 per Bbl during the year ended December 31, 1995 from $16.58 per Bbl during the year ended December 31, 1994. The average sales price for gas decreased by 18% to $1.59 per Mcf during the year ended December 31, 1995 from $1.93 per Mcf during the year ended December 31, 1994. Lease Expense. Lease operating expense (including production and ad valorem taxes) for the year ended December 31, 1995 increased by 132% to $79,000 from $34,000 for the year ended December 31, 1994. This increase was primarily attributable to workovers and higher lease operating expenses relating to producing wells on the Bright Falcon project. Lease expense per Mcfe increased to $0.57 during the year ended December 31, 1995 from $0.24 for the comparable 1994 period. Substantially all of the increase in lease operating expense per Mcfe was related to the workovers and higher lease operating expenses described above. Depletion, Depreciation and Amortization Expense. Depletion of oil and gas properties for the year ended December 31, 1995 increased 74% to $158,000 from $91,000 for the prior year. Depletion per Mcfe for the year ended December 31, 1995 increased 80% to $1.15 from $0.64 for the prior year. The increases in both total depletion and depletion per Mcfe were the result of a downward revision in the amount of 909 Mcfe in the Company's oil and gas reserves in 1995. Depreciation and amortization of technical interpretation equipment, office furniture and equipment and office leasehold improvements increased by 140% to $288,000 during the year ended December 31, 1995 from $120,000 for the comparable 1994 period. This increase was due primarily to the acquisition during 1995 of additional technical interpretation equipment and software with an approximate cost of $620,000. Impairment of Oil and Gas Properties. The Company incurred oil and gas property impairment charges during 1995 of $1.6 million. No such charges were incurred in 1994. The 1995 charges resulted from the Company's determination that its investment in developed and abandoned projects exceeded the present value of the Company's proved reserves at December 31, 1995. The impairment charges reflected the completion of the evaluation of two prospects which had poor drilling results and a significant downward revision of oil and gas reserve estimates in 1995. The primary factors contributing to the reserve revision related to: (1) the premature loss of a well due to mechanical reasons which was unanticipated at the time of the initial estimate, and (2) the removal of "proved, undeveloped" reserves attributable to a well location, which the project partners elected not to drill. Both of these revisions related to prospects which were associated with the Bright Falcon project. General and Administrative Expense. General and administrative expense, which is net of overhead capitalized to projects, increased by 51% to $905,000 for the year ended December 31, 1995 from $598,000 in the comparable 1994 period. This increase was primarily attributable to compensation expense for new employees and compensation expense in the amount of $51,000 attributable to stock options issued within one year of the Initial Public Offering. Rental Income. Rental income decreased by 43% to $58,000 for the year ended December 31, 1995 from $101,000 for the comparable 1994 period. This decrease is attributable to a decrease during 1995 in the gross fee billings of the seismic processing company which utilizes certain of the Company's technical and office equipment. The Company earns rental income by exchanging use of its equipment for a percentage of the seismic processing company's gross fee billings. Interest and Other Income. Interest and other income increased to $236,000 for the year ended December 31, 1995 from $53,000 for the comparable 1994 period, as a result of an increase in short-term investments made with the proceeds from the sale of Series C Preferred Stock. Net Loss. As a result of the foregoing, the Company's net loss increased to $2.5 million for the year ended December 31, 1995 from $385,000 for the year ended December 31, 1994. 23 Year Ended December 31, 1994 Compared to Year Ended December 31, 1993 Oil and Gas Revenues and Expenses. Oil and gas revenues were $304,000 for the year ended December 31, 1994. Production during 1994 was 141.7 MMcfe. No oil and gas revenues, operating expenses or depletion of oil and gas properties were recognized by the Company in 1993. Depreciation and amortization of technical interpretation equipment, office furniture and equipment and office leasehold improvements increased by 85% to $120,000 for the year ended December 31, 1994 from $65,000 for the comparable 1993 period. This increase was primarily attributable to the acquisition during 1994 of additional technical interpretation equipment with an approximate cost of $227,000. Rental Income. Rental income decreased by 20% to $101,000 for the year ended December 31, 1994 from $127,000 for the comparable 1993 period. Interest and Other Income. Interest and other income increased to $53,000 for year ended December 31, 1994 from $8,000 during the comparable 1993 period. This increase is primarily attributable to the short term investment of the proceeds of the sale of the Units. Net Loss. Primarily as a result of the foregoing, the Company's net loss decreased by 37% to $385,000 for 1994 from $615,000 for the comparable 1993 period. Liquidity and Capital Resources On December 26, 1996, the Company consummated an Initial Public Offering which raised approximately $23.6 million in net proceeds. In January 1997, the Company's underwriters exercised their over-allotment option to purchase additional shares of Common Stock, resulting in additional net proceeds to the Company of approximately $3.8 million. At December 31, 1996, the Company had working capital in the amount of $16.0 million. To date, the Company has funded its oil and gas exploration activities principally through cash provided by the sale of equity securities. The Company was initially capitalized in January 1993 through (i) the issuance and sale of 768,117 shares of Common Stock to the Company's three founders and (ii) the issuance of 100,000 shares of Series A Preferred Stock to Landmark Graphics for total consideration valued by the Company and Landmark Graphics to be $500,000. The Series A Preferred Stock was initially convertible into 517,000 shares of non-voting Common Stock that was similar in all other respects to the Common Stock. As part of the consideration for the Series A Preferred Stock, Landmark Graphics guaranteed a $400,000 bank loan for the Company. In November 1993 and October 1994, the Company raised additional capital in the amount of $5.4 million through the sale of 54,000 Units. Immediately prior to the sale of the Units, the Company had a working capital deficit of $768,588 and an equity deficit of $55,141 and did not believe that financing alternatives for funding of the Company's planned capital expenditures and exploration activities except for the sale of Units were available. As a condition to their investment, the prospective purchasers of Units required Landmark Graphics to convert the Series A Preferred Stock to 329,003 shares of Common Stock rather than the 517,000 shares which Landmark Graphics was entitled pursuant to the original terms of the Series A Preferred Stock. Rather than being required to perform under its guarantee, Landmark Graphics agreed to convert the shares of Series A Preferred Stock which it owned, accepting the reduced number of shares of Common Stock. The prospective Unit purchasers (who were unaffiliated with each of the Company and Landmark Graphics) required Landmark Graphics to convert its shares of Series A Preferred Stock on the terms described above to effect an increase in such persons' prospective ownership in the Company. Additional capital in the amount of $8.0 million was raised by the Company in a private placement of Series C Preferred Stock during the third quarter of 1995. Shortly after the sale of the Series C Preferred Stock was completed, the Company completed a review and analysis of its estimated oil and gas reserves and concluded that a downward revision in its estimates was appropriate since certain proved undeveloped reserves were no longer considered likely to be recoverable. To compensate the investors who had purchased Series C Preferred Stock, each purchaser was issued warrants to purchase additional shares equal to 10% of the number of shares of Series C Preferred Stock such investor had purchased. On December 26, 1996, the Company completed an Initial Public Offering for the sale of 2,400,000 shares of Common Stock. From the date of the Initial Public Offering through March 26, 1997, the net proceeds of the Offering, including over-allotment, approximated $27.4 million. Of such proceeds, approximately $9.0 million has been paid through March 26, 1997 (1) to redeem all the issued and outstanding shares of the Series B Preferred Stock, (2) for capital and exploration expenditures, (3) to pay dividends accrued on the issued and outstanding Series C Preferred Stock and (4) for general 24 corporate purposes, including expenses associated with hiring additional personnel. The Company plans to use the remaining proceeds to fund future capital and exploration programs and general corporate purposes. The Series B Preferred Stock accrued dividends (in cash or in shares of Series B Preferred Stock, as determined by the Board of Directors) at an annual rate per share of $12.50 if in cash or .13276 shares of Series B Preferred Stock if in stock, payable annually on December 31. Assuming the dividend was paid in cash, the aggregate annual dividend on the issued and outstanding Series B Preferred Stock approximated $836,000. The Company was obligated to redeem all of the issued and outstanding Series B Preferred Stock in two installments commencing on November 9, 2002 at a redemption price of $100 per share. To eliminate the accrual of dividends for years subsequent to December 31, 1995, the Company elected to use a portion of the net proceeds of the Offering to redeem all of the issued and outstanding shares of Series B Preferred Stock. The Company's net loss of $2.7 million for the year ended December 31, 1996 included non-cash expenses comprised of impairment of oil and gas properties in the amount of $1.5 million, compensation expense in the amount of $868,000 related to stock options granted within one year prior to the Initial Public Offering, and depletion, depreciation and amortization in the amount of $884,000. Net cash used in investing activities for the year ended December 31, 1996 was $5.0 million. The acquisition, exploration and development of oil and gas properties in the amount of $6.2 million was the principal use of cash in the Company's investing activities. The principal source of cash from the Company's investing activities was the maturity of investment securities held to maturity totaling $1.6 million. The Company has no outstanding long-term debt and is not a party to any debt or collateral-based lending arrangements. The Company has never utilized commodity swaps for its oil and gas production and it does not anticipate doing so in the foreseeable future. In addition, the Company has not entered into any hedging transactions and has no current intention to do so in the future. The development of the Company's business has in the past required substantial oil and gas capital expenditures. To meet its goal, the Company in the future will be required to make oil and gas capital expenditures substantially in excess of historical levels to acquire, explore and develop oil and gas properties. Capital expenditures for oil and gas exploration and production activities during 1994, 1995, and 1996, were $1.8 million, $2.2 million and $6.2 million, respectively. Budgeted capital expenditures for the Company's oil and gas exploration and production activities during 1997 are currently estimated to be approximately $14.9 million. As a result of the Company's periodic review of each of its portfolio of 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. In each such instance, the Company sold one-half and two-thirds of its working interests in such projects, respectively, in exchange for proceeds in an amount approximating one-half and two-thirds of the costs incurred by the Company in connection with such projects, respectively. No gain or loss was recognized on either transaction. Although the Company presently has no current commitment to sell all or any portion of its working interests, such sales could be used as a source of liquidity by the Company in the future. The Company expects that its available cash and expected cash flows from operating activities will be sufficient to meet its financial obligations and fund its planned exploration and drilling activities for the short term (twelve months from the date of the filing with the Commission of this Annual Report on Form 10-K, through December 31, 1997), provided, that (i) there are no significant declines in oil and gas prices below current levels or anticipated seasonal lows, (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 and (iii) the Company is able to discover and produce commercial quantities of oil and gas and within the time frame the Company has predicted. The Company intends to satisfy its long-term liquidity requirements from a combination of expected cash flow generated from operations, borrowings from financial institutions (which may be secured by the Company's oil and gas reserves) and from future public or private offerings of equity and/or debt securities. For liquidity purposes, the Company considers "long-term" to be the second, third and fourth twelve-month periods following December 31, 1996. In the event the cash flows from the Company's operating activities and the net proceeds from the Offering are not sufficient to fund development and exploration expenditures, or results from developmental drilling are not as successful as 25 anticipated, the Company will be required to modify the implementation of its operating strategy unless additional financing is available. There can be no assurance such financing would be available on terms which would be acceptable to the Company. 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, 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 common stock price as an estimate of the fair value). As of December 31, 1996, the Company had unamortized deferred compensation of $893,040 which will be charged to expense during the next four 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. Item 8. Financial Statements and Supplementary Data The financial statements required by this item are incorporated under Item14 in Part IV of this report. Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. 26 PART III Item 10. Directors and Executive Officers of the Registrant The information required to be set forth in this Item is incorporated by reference to a similarly titled heading in the Company's definitive proxy statement, relating to the 1997 annual meeting of its stockholders to be filed with the Securities and Exchange Commission not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K (hereinafter the "Proxy Statement"). Item 11. Executive Compensation The information required to be set forth in this Item is incorporated by reference to a similarly titled heading in the Proxy Statement. Item 12. Security Ownership of Certain Beneficial Owners and Management The information required to be set forth in this Item is incorporated by reference to a similarly titled heading in the Proxy Statement. Item 13. Certain Relationships and Related Transactions The information required to be set forth in this Item is incorporated by reference to a similarly titled heading in the Proxy Statement. 27 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a)(1) Financial Statements: Index To Financial Statements Page ---- Report Of Independent Public Accountants.......................... F-1 Balance Sheets as of December 31, 1995 and 1996.............. F-2 Statements of Operations for the three years ended December 31, 1996......................... F-3 Statements of Changes in Common Stockholders' Equity (Deficit) for the three years ended December 31, 1996................. F-4 Statements of Cash Flows for the three years ended December 31, 1996......................... F-5 Notes to Financial Statements................................ F-6 (a)(2) Financial Statement Schedules: Not applicable 28 (a)(3) Exhibits: Index To Exhibits Exhibit Description of Exhibit Number ---------------------- ------- 3.1(i) Sixth Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1(i)(d) to the Company's Amendment No.2 to Registration Statement on Form S-1 (No. 333-14473), filed December 16, 1996). 3.1(ii) Second Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1(ii)(b) to the Company's Amendment No.2 to Registration Statement on Form S-1 (No. 333-14473), filed December 16, 1996). 4.1 Form of Specimen Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Amendment No.1 to Registration Statement on Form S-1 (No. 333-14473), filed November 27, 1996). 10.1 Technical Services Agreement between Landmark Graphics Corporation and Novera Energy Inc. dated January 1993 (incorporated by reference to Exhibit 10.1 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). 10.2 Stock Purchase Agreement among the Company, C. Eugene Ennis, Douglas C. Nester, Peter M. Duncan and the Investors named therein dated November 9, 1993 (incorporated by reference to Exhibit 10.2 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). 10.3 Series C Preferred Stock Purchase Agreement among the Company, C. Eugene Ennis, Douglas C. Nester, Peter M. Duncan and the Investors named therein dated July 26, 1995 (incorporated by reference to Exhibit 10.3 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). 10.4 Second Amended and Restated Co-Sale Agreement among the Company, C. Eugene Ennis, Douglas C. Nester, Peter M. Duncan and the Investors named therein dated July 26, 1995 (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). 10.5 Stock Purchase and Restriction Agreement between the Company and C. Eugene Ennis dated November 9, 1993 (incorporated by reference to Exhibit 10.5 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). 10.6 Stock Purchase and Restriction Agreement between the Company and Peter M. Duncan dated November 9, 1993 (incorporated by reference to Exhibit 10.6 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). 10.7 Stock Purchase and Restriction Agreement between the Company and Douglas C. Nester dated November 9, 1993 (incorporated by reference to Exhibit 10.7 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). 10.8 Lease Contract dated January 22, 1995 between the Company and The Penn Mutual Life Insurance Company and Letter dated March 1, 1995 from Trammell Crow Houston, Inc. (incorporated by reference to Exhibit 10.8 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). 29 Exhibit Description of Exhibit Number ---------------------- ------- 10.9 1994 Stock Option Plan (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement on Form S-1 (No. 333-14473), filed October 18, 1996). + 10.10 1996 Incentive Compensation Program (incorporated by reference to Exhibit 10.10 to the Company's Amendment No.1 to Registration Statement on Form S-1 (No. 333-14473), filed November 27, 1996). + 11.1* Computation of Earnings per Share. 23.2* Consent of Ryder Scott Company. 24.1* Power of Attorney (included on signature page) 27.* Financial Data Schedule (for SEC use only) - --------------------------- * filed herewith + Management contract or compensatory plan (b) Reports on Form 8-K: The following Current Report on Form 8-K was filed during the quarter ended December 31, 1996 and through the date hereof. Date of Report Item No. Financial Statements -------------- -------- -------------------- None. 30 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/ C. Eugene Ennis _____________________________________ President and Chief Executive Officer Know All Men By These Presents, that each individual whose signature appears below hereby constitutes and appoints C. Eugene Ennis, Joseph Schuchardt III 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. Date Signature Title(s) ------ --------- -------- March 26, 1997 /s/ C. Eugene Ennis President, Chief Executive ______________________________ Officer; Director (Principal C. Eugene Ennis Executive Officer and Principal Accounting Officer March 26, 1997 /s/ Peter M. Duncan Vice President, Technology _______________________________ Peter M. Duncan March 26, 1997 /s/ Douglas C. Nester Vice President, Exploration _______________________________ Douglas C. Nester March 26, 1997 /s/ Robert J. Bacon, Jr. Vice President, Joint _______________________________ Ventures Robert J. Bacon, Jr. March 26, 1997 /s/ Joseph Schuchardt, III Vice President, Business _______________________________ Development Joseph Schuchardt, III March 26, 1997 /s/ Jon W. Bayless Director _______________________________ Jon W. Bayless 31 March 26, 1997 /s/ Robert H. Chaney Director _______________________________ Robert H. Chaney March 26, 1997 /s/ Charles E. Edwards Director _______________________________ Charles E. Edwards March 26, 1997 /s/ Douglas C. Williamson Director _______________________________ Douglas C. Williamson 32 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, 1995 and 1996, and the related statements of operations, changes in common stockholders' equity (deficit) and cash flows for each of the three years in the period ended December 31, 1996. 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, 1995 and 1996, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1996, in conformity with generally accepted accounting principles. Houston, Texas March 14, 1997 ARTHUR ANDERSEN LLP F-1 3DX TECHNOLOGIES INC. BALANCE SHEETS ASSETS December 31, ------------------------- 1995 1996 ---- ---- Current assets: Cash and cash equivalents............ $ 5,704,014 $17,521,745 Securities held to maturity.......... 1,595,167 - Accounts receivable.................. 113,704 554,210 Prepaid expenses..................... 85,786 165,095 ----------- ----------- Total current assets............. 7,498,671 18,241,050 ----------- ----------- Property and equipment: Oil and gas properties (full-cost method-including $1,375,145 and $4,403,165, respectively, not subject to depletion, depreciation and amortization)................... 4,023,869 11,567,562 Technical interpretation equipment... 1,083,925 1,505,534 Office furniture, equipment and leasehold improvements.............. 170,877 205,531 ----------- ----------- 5,278,671 13,278,627 Less accumulated depletion, depreciation and amortization....... (2,343,578) (4,702,296) ----------- ----------- 2,935,093 8,576,331 Other assets: Deposits............................. 12,886 7,886 Organization costs, net of accumulated amortization............ 3,854 1,922 ----------- ----------- $10,450,504 $26,827,189 =========== =========== LIABILITIES, REDEEMABLE PREFERRED STOCK AND COMMON STOCKHOLDERS' EQUITY (DEFICIT) Current liabilities: Accounts payable..................... $ 194,742 $ 1,960,984 Accrued liabilities.................. 39,166 292,581 ----------- ----------- Total current liabilities........ 233,908 2,253,565 ----------- ----------- Dividends payable on Series C preferred stock.................................. 275,256 - ----------- ----------- Commitments (Note 10) Mandatorily redeemable Series B preferred stock, $.01 par value, $100 per share redemption price, 200,000 shares authorized, 66,871 and 0 shares issued and outstanding, respectively... 6,277,826 - ----------- ----------- Mandatorily redeemable Series C senior preferred stock, $.01 par value, $3 per share redemption price, 3,300,000 shares authorized, 2,662,241 and 0 shares issued and outstanding, respectively........................... 7,903,833 - ----------- ----------- Common stockholders' equity (deficit): Common stock, $.01 par value, 12,000,000 shares authorized, 2,987,908 and 6,841,177 shares issued and outstanding, respectively 29,879 68,412 Paid-in capital...................... 1,730,459 34,189,700 Deferred compensation related to certain stock options............... (837,864) (893,040) Notes receivable from stock sales.... (47,756) - Accumulated deficit.................. (5,115,037) (8,791,448) ----------- ----------- Total common stockholders' equity (deficit)................ (4,240,319) 24,573,624 ----------- ----------- $10,450,504 $26,827,189 =========== =========== The accompanying notes are an integral part of these financial statements. F-2 3DX TECHNOLOGIES INC. STATEMENTS OF OPERATIONS Years Ended December 31, ---------------------------------------- 1994 1995 1996 ---- ---- ---- Revenues: Oil and gas............................ $ 303,836 $ 274,511 $ 851,827 Rental income.......................... 100,962 58,195 229,556 Interest and other..................... 52,817 236,186 247,960 ---------- ----------- ----------- Total revenues........................ 457,615 568,892 1,329,343 ---------- ----------- ----------- Costs and expenses: Lease operating........................ 14,225 60,877 49,016 Production and ad valorem taxes........ 19,812 17,656 58,660 Impairment of oil and gas properties... - 1,627,321 1,476,690 Depletion, depreciation, and amortization.......................... 210,347 446,350 883,962 General and administrative............. 598,244 905,063 1,596,379 ---------- ----------- ----------- Total costs and expenses.............. 842,628 3,057,267 4,064,707 ---------- ----------- ----------- Net loss................................ (385,013) (2,488,375) (2,735,364) Dividends on preferred stock............ (421,696) (1,058,956) (520,393) Redemption premium on Series B Preferred Stock........................ - - (365,810) Accretion on preferred stock............ (30,367) (48,408) (54,844) ---------- ----------- ----------- Net loss applicable to common stockholders........................... $ (837,076) $(3,595,739) $(3,676,411) ========== =========== =========== Primary and fully diluted net loss per common share........................... $ (0.33) $ (1.14) $ (1.16) ========== =========== =========== Weighted average number of common shares outstanding..................... 2,534,175 3,148,826 3,162,934 ========== =========== =========== The accompanying notes are an integral part of these financial statements. F-3 3DX TECHNOLOGIES INC. STATEMENTS OF CHANGES IN COMMON STOCKHOLDERS' EQUITY (DEFICIT)
Common Stockholders' Equity (Deficit) ------------------------------------------------------------------------------------------------------- Common Stock Stock ---------------------- Paid-In Deferred Accumulated Subscriptions Shares Amount Capital Compensation Deficit Receivable Total ------- ------ -------- ------------ ------------ -------------- ----- Balance at December 31, 1993...................... 2,232,530 $ 22,325 $ 664,999 $ - $ (682,222) $ (41,527) $ (36,425) Principal collections...... - - - - - 27,862 27,862 Shares issued in October 1994...................... 755,378 7,554 176,605 - - (12,492) 171,667 Accrual of dividends....... - - - - (421,696) - (421,696) Accretion on preferred stock..................... - - - - (30,367) - (30,367) Net loss................... - - - - (385,013) - (385,013) --------- --------- ----------- ------------ ----------- ------------ ----------- Balance at December 31, 1994...................... 2,987,908 29,879 841,604 - (1,519,298) (26,157) (673,972) Principal collections...... - - - - - 36,156 36,156 Shares issued in 1995...... - - - - - (57,755) (57,755) Accrual of dividends....... - - - - (1,058,956) - (1,058,956) Accretion on preferred stock..................... - - - - (48,408) - (48,408) Deferred compensation related to certain stock options................... - - 888,855 (888,855) - - - Compensation expense related to certain stock options................... - - - 50,991 - - 50,991 Net loss................... - - - - (2,488,375) - (2,488,375) --------- --------- ----------- ------------ ----------- ------------ ----------- Balance at December 31, 1995...................... 2,987,908 29,879 1,730,459 (837,864) (5,115,037) (47,756) (4,240,319) Principal collections...... - - - - - 47,756 47,756 Shares issued for exercise of stock options.......... 3,124 31 573 - - - 604 Accrual of dividends....... - - - - (520,393) - (520,393) Accretion on preferred stock..................... - - - - (54,844) - (54,844) Deferred compensation related to certain stock options................... - - 922,806 (922,806) - - - Compensation expense related to certain stock options................... - - - 867,630 - - 867,630 Shares issued for Initial Public Offering (net of offering costs)........... 2,400,000 24,000 23,539,064 - - - 23,563,064 Conversion of Series C preferred to common stock. 1,450,145 14,502 7,996,798 - - - 8,011,300 Redemption of Series B preferred stock........... - - - - (365,810) - (365,810) Net loss................... - - - - (2,735,364) - (2,735,364) --------- --------- ----------- ------------ ----------- ------------ ----------- Balance at December 31, 1996...................... 6,841,177 $ 68,412 $34,189,700 $ (893,040) $(8,791,448) $ - $24,573,624 ========= ======== =========== ============ =========== ============ ===========
The accompanying notes are an integral part of these financial statements. F-4 3DX TECHNOLOGIES INC. STATEMENTS OF CASH FLOWS
Years Ended December 31, ------------------------------------------ 1994 1995 1996 ---- ---- ---- Cash flows from operating activities: Net loss............................... $ (385,013) $(2,488,375) $(2,735,364) Adjustments to reconcile net loss to net cash provided by (used in) operating activities: Depletion, depreciation and amortization....................... 210,347 446,350 883,962 Compensation expense related to certain stock options.............. - 50,991 867,630 Impairment of oil and gas properties......................... - 1,627,321 1,476,690 (Increase) decrease in accounts receivable......................... 147,928 (45,485) (440,506) (Increase) decrease in prepaid expenses........................... (8,237) (76,188) (79,309) Increase (decrease) in accounts payable............................ 24,441 (3,005) 388,767 Increase (decrease) in accrued liabilities........................ 26,777 (14,540) 253,415 ----------- ----------- ----------- Net cash provided by (used in) operating activities.................. 16,243 (502,931) 615,285 ----------- ----------- ----------- Cash flows from investing activities: Acquisition, exploration and development of oil and gas properties. (1,822,174) (2,185,804) (6,166,219) Sales proceeds-undeveloped oil and gas interests............................. - 480,931 - Purchase of technical and office equipment and leasehold improvements.. (108,817) (395,093) (229,311) Purchase of technical equipment from Landmark Graphics..................... (87,373) (405,480) (226,953) (Purchase of) proceeds from securities held to maturity...................... - (1,595,167) 1,595,167 Other.................................. 500 (12,886) 5,000 ----------- ----------- ----------- Net cash used in investing activities.. (2,017,864) (4,113,499) (5,022,316) ----------- ----------- ----------- Cash flows from financing activities: Common stock proceeds, net of issuance costs................................. 162,651 - 23,563,668 Series B preferred stock proceeds, net of issuance costs..................... 2,352,722 25,297 - Series C preferred stock proceeds, net of issuance costs..................... - 7,851,133 143,843 Redemption of Series B preferred stock. - - (6,687,100) Payment of Series C preferred stock dividends............................. - - (795,649) ----------- ----------- ----------- Net cash provided by financing activities............................ 2,515,373 7,876,430 16,224,762 ----------- ----------- ----------- Net change in cash and cash equivalents. 513,752 3,260,000 11,817,731 Cash and cash equivalents at beginning of year................................ 1,930,262 2,444,014 5,704,014 ----------- ----------- ----------- Cash and cash equivalents at end of the year................................... $ 2,444,014 $ 5,704,014 $17,521,745 =========== =========== ===========
The accompanying notes are an integral part of these financial statements. F-5 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 its 3-D seismic data and computer-aided exploration capabilities as a partner to experienced oil and gas operators in 3DX's geographical areas of interest. By combining the operator's local knowledge and infrastructure with 3DX's imaging capabilities, 3DX believes it is able to evaluate and exploit drilling opportunities at lower-than-normal cost. The Company primarily invests in prospects where 3-D seismic evaluation and interpretation is expected to reduce drilling risk. Working interests in major prospects have ranged from 5% up to 40% in property investments to date. All of the Company's operations are currently located in the United States. The Company's future operations are dependent on a variety of factors, including its successful application of its technical expertise, profitable exploitation of its oil and gas properties, successful access to capital sources and variable oil and gas prices and costs, among others. 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. The Company completed an Initial Public Offering ("Initial Public Offering" or the "Offering") in December 1996, with the sale of 2,400,000 shares of common stock, resulting in proceeds to the Company approximating $23.6 million, net of issuance costs. (See Note 6). 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 the years ended December 31, 1994, 1995 and 1996 are general and administrative costs of $375,922, $618,614, and $1,146,722, respectively. Such capitalized costs include payroll and related costs of the exploration department personnel which are directly attributable to the Company's current acquisition, exploration and development activities. Other costs (primarily including office rent, technical computer maintenance and support, and communication costs) are also capitalized to the extent they are attributed to the Company's own 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 proved recoverable oil and gas reserves as estimated by the Company and corroborated by independent petroleum engineering firms. The Company excludes unevaluated property costs from the depreciation, depletion and amortization computations until the discovery of proved reserves or a determination of impairment occurs. Unevaluated properties are evaluated for impairment on a property-by-property basis annually through 1995 and quarterly beginning in 1996. When the determination has been made that an unproved property has either encountered proved reserves or has been impaired, the related costs are transferred to the evaluated cost pool. Information regarding the number of, and total investment in, abandoned projects at the time of abandonment by the Company is set forth below: F-6 Number of Investment in Projects Abandoned Accounting Period Abandoned Projects ----------------- --------- -------------- Year ended December 31, 1994 0 $ 0 Year ended December 31, 1995 3 1,173,644 Year ended December 31, 1996 2 927,366 Impairment of capitalized costs of oil and gas properties is determined for each cost center, determined on a country-by-country basis. The Company's only active cost center since inception has been the United States of America. For each cost center, to the extent that capitalized costs of oil and gas properties, net of related accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the discounted future net revenues of estimated proved oil and gas reserves, net of 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. No such write-downs were required during 1994. Write-downs of $1,627,321 and $1,476,690 were required for the years ended December 31, 1995 and 1996, respectively. In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standard No. 121 ("SFAS No. 121") regarding accounting for the impairment of long-lived assets. The Company adopted SFAS No. 121 effective January 1, 1996. However, such adoption did not affect the primary test of asset recoverability because the Company's oil and gas properties are accounted for under the full-cost method of accounting as discussed above. The adoption of SFAS No. 121 had no effect on the Company's results of operations for the year ended December 31, 1996. Technical interpretation equipment, including software, and office furniture and equipment are recorded at cost. Depreciation is determined on a straight-line basis over the estimated useful lives of the assets. The estimated useful life of the technical interpretation equipment, including software, is three years, and for office furniture and equipment, it is five years. Depletion, depreciation and amortization expense includes depreciation related to technical interpretation equipment, including software, and office furniture and equipment of $119,675, $288,014, and $459,189 for the years ended December 31, 1994, 1995 and 1996, respectively. Securities held to Maturity Securities held to maturity at December 31, 1995 include various types of government debt securities which matured on March 31, 1996, and are carried at amortized cost at December 31, 1995. Accounting for Income Taxes The Company provides deferred income taxes at the balance sheet date for the estimated tax effects of differences in the existing tax bases 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 In January 1993, the Company entered into an informal revenue-sharing arrangement with a seismic processing company whereby the Company would receive a percentage of the seismic processing company's gross billings in exchange for providing office space and use of the Company's technical equipment. Revenues under this ongoing arrangement amounted to $100,962, $58,195 and $229,556 in 1994, 1995 and 1996, respectively. 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. F-7 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 majority of oil and gas production to three customers in 1994, 1995 and 1996. Sales to these customers exceeded 10% of oil and gas revenues during the years indicated (in thousands): 1994 1995 1996 ---- ---- ---- Enron Corp. its subsidiaries and affiliates $ 154 $ 134 $ 43 Dow Hydrocarbon U.S.A. - - 493 Ada Crude Oil Company 120 82 47 Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, securities held to maturity and accounts receivable, approximate their fair values due to their short-term nature. 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 the ceiling test, are inherently imprecise and are expected to change as future information becomes available. Prior Year Reclassifications Certain prior year amounts have been reclassified to conform with the current presentation. Accounting Pronouncements In October 1996, the American Institute of Certified Public Accountants issued Statement of Position No. 96-1, "Environmental Remediation Liabilities," which establishes new accounting and reporting standards for the recognition and disclosure of environmental remediation liabilities. The provisions of the statement are effective for fiscal years beginning after December 15, 1996. The impact of this new standard is not expected to have a significant effect on the Company's financial position or results of operations. In February 1997, the Financial Accounting Standards Board issued 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. F-8 3. INCOME TAXES Significant components of the Company's deferred tax liabilities and assets are as follows: December 31, --------------------------------------- 1994 1995 1996 ---- ---- ---- Deferred tax liability: Exploration and development expenditures deducted for tax and capitalized for books................. $(345,831) $ (103,867) $ (325,812) Other items, net....................... - (37,523) (54,872) --------- ----------- ----------- Total deferred tax liability........ (345,831) (141,390) (380,684) --------- ----------- ----------- Deferred tax assets: Net operating loss carryforwards....... 653,394 1,238,317 2,039,546 Other items, net....................... 28,419 66,375 126,517 --------- ----------- ----------- Total deferred tax assets........... 681,813 1,304,692 2,166,063 Less: Valuation allowance.............. (335,982) (1,163,302) (1,785,379) --------- ----------- ----------- Net deferred tax assets................. 345,831 141,390 380,684 --------- ----------- ----------- Net deferred tax liability.............. $ - $ - $ - ========= =========== =========== 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, 1996, the Company has tax net operating loss carryforwards of $5,998,666 which begin to expire in 2008. As a result of recent stock transactions, including the Initial Public Offering, (See Note 6), there is a yearly limitation on the Company's utilization of its Net Operating Losses under Section 382 of the Internal Revenue Code. 4. RELATED-PARTY TRANSACTIONS The Company purchased technical equipment, supplies, and software and hardware maintenance amounting to $118,630 in 1994, $521,128 in 1995, and $267,007 in 1996 from Landmark. 5. MANDATORILY REDEEMABLE PREFERRED STOCK The Company's Series B and Series C redeemable preferred stocks described below were presented on the balance sheet outside of common equity because they both had mandatory-redemption provisions outside the control of the Company, and both were being accreted to their projected redemption values through a charge to common equity during the periods such securities were outstanding. Series B In November 1993, the Company negotiated an agreement pursuant to which certain investors agreed to purchase 54,000 units (each unit consisting of one share of redeemable Series B preferred stock and 30.215 shares of common stock) for total consideration in the amount of $5,400,000. The sales of the units was timed to be funded in two traunches to match the projected cash flow needs of the Company, with the first traunch (consisting of 29,000 units) funded in November 1993 and the second traunch (consisting of 25,000 units) funded in October 1994. The terms of the agreement provided a substantial penalty for any investor who committed to purchase units in the second traunch and failed to do so. All investors who committed to purchase units in the second traunch did so in October 1994. Sales of the 54,000 units were as follows: 4,500 units were sold to members of management (8.3% of the total units sold), 4,000 units were sold to Landmark (7.4% of the total units sold), 1,750 units were sold to consultants to the Company (3.2% of the total units sold), 28,820 units were sold to two investment funds (18,820 units to Citi Growth Fund L.P. and 10,000 units to R. Chaney & Partners - 1993 L.P.) whose purchases were conditioned on the ability of each investor group to designate one member of the Board of Directors (53.4% of the total units sold), 1,500 units were F-9 sold to one investor-designated member and one future member of the Board of Directors (2.8% of the total units sold), and the remaining 13,430 units were sold to other unrelated investors (24.9% of the total units sold). In November 1993, the Company sold 29,000 equity units consisting of an aggregate of 29,000 shares of the Company's redeemable Series B preferred stock, par value of $.01 per share, and 876,237 shares of common stock, par value of $.01 per share. The stock was sold for net proceeds of $94.1558 per share of Series B preferred stock and $.19 per share of common stock. The difference between the sales price and the redemption price of $100 per share was subject to an annual pro-rata accretion charge to retained earnings, so that at the time of the mandatory redemption, the value of each share of preferred stock will equal the redemption price of $100. The Series B preferred stockholders were entitled to 100 votes for each share held, and shall vote together with holders of common stock and not as a separate class. The Series B preferred stockholders were entitled to receive (out of any funds legally available therefor) dividends (in cash or in shares of Series B preferred stock, as determined by the Board of Directors) at an annual rate per share of $12.50 if in cash or .13276 shares of Series B preferred stock if in stock, payable annually on December 31, commencing in December 1994. In the event the Board of Directors failed to declare the dividend in stock or cash ten working days prior to the end of each year, the dividend was deemed declared in stock as of the end of the year. As a result, the dividend was constructively cumulative. The Series B preferred stock had a redemption price of $100 per share. The Series B preferred stock also contained a mandatory-redemption feature under which the stock was to be redeemed at the redemption price in two installments (50% on November 9, 2002 and 50% on November 9, 2003). 3DX had the option to redeem the outstanding Series B Preferred stock at any time with funds legally available therefor. As consideration for the Series B preferred and common stock sale, the Company received $2,875,019 in cash and promissory notes from two of its founders amounting to $24,984. The Company incurred legal and other offering costs of $103,659 in connection with this Series B preferred stock unit sale. On October 24, 1994, the Company sold 25,000 equity units consisting of an aggregate of 25,000 shares of the Company's redeemable Series B preferred stock, par value of $.01 per share, and 755,378 shares of common stock, par value of $.01 per share. The stock was sold for net proceeds of $94.1558 per share of Series B preferred stock and $.19 per share of common stock. As consideration for the Series B preferred and common stock sale, the Company received $2,487,511 in cash and a promissory note from one of its founders amounting to $12,492. Dividends on the Series B preferred stock have been paid in stock rather than in cash as determined by the Board of Directors. In connection with the Initial Public Offering which became effective on December 26, 1996, all of the issued and outstanding shares of the Series B Preferred Stock were redeemed. A $365,810 redemption premium (which adjusts the Series B Preferred Stock carrying value to the liquidation price of $100 per share) was charged to the Company's accumulated deficit. Series C During the period from July 26, 1995 until September 25, 1995, the Company sold a total of 2,662,241 shares of the Company's senior redeemable convertible Series C preferred stock, par value of $.01 per share. The stock was sold for $3 per share. Purchasers of the 2,662,241 shares of Series C Preferred Stock consisted of members of management who purchased 89,237 shares (3.4% of the total Series C shares sold), consultants to the Company who purchased 17,134 shares (0.6% of the total Series C shares sold), two members of the Board of Directors who purchased 10,000 shares (0.4% of the total Series C shares sold), other previous Series B unit investors who purchased 329,203 shares (including 125,467 shares purchased by Citi Growth Fund L.P. and 66,667 shares by R. Chaney & Partners - 1993 L.P.) (12.3% of the total Series C shares sold), NationsBank Capital Corporation whose purchase of 1,333,333 shares was conditioned on its ability to designate a member of the Company's Board of Directors (50.1% of the total Series C shares sold), and the remaining 883,334 shares were sold to other unaffiliated investors (33.2% of the total Series C shares sold). The Series C preferred stockholders were entitled to one vote for each number of common shares their Series C preferred stock was convertible into, and voted together with holders of common stock and not as a separate class. The Series C preferred stockholders were entitled to receive when, as and if declared by the Board of Directors (out of any funds legally available therefor) dividends (in cash or in shares of Series C preferred stock, as determined by the Board of Directors) at an annual rate per share of $.24 if in cash or .08 shares of Series C preferred stock if in stock, payable or accruing quarterly, commencing on December 31, 1995. If dividends are accrued, the unpaid dividends compound at an annual interest rate of 8%. In the event the Board of Directors failed to declare the dividend in stock or cash ten working days prior to the end of each calendar quarter, the dividend was automatically deemed declared in cash as of the end of the quarter. As a result the dividend was constructively cumulative. F-10 The Series C preferred stock also contained a right to convert to common stock on a one share for one share basis at any time (See below for discussion of the impact of the October 1996 reverse stock split), and the shares were to be automatically converted upon the occurrence of certain automatic 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 was to be redeemed (if requested in writing with at least 30 days notice by at least 67% of the holders) at the liquidation price in two installments (50% on November 9, 2002 and 50% on November 9, 2003). In the event of a merger, sale or dissolution of the Company, or initiation of mandatory redemption of the senior preferred Series C stock where the proceeds to the holders are less than two times the holders' original basis plus accrued dividends, then in such event the holders were to receive the face value of their investment plus accrued dividends and were also entitled to participate on an "as if converted" basis in all remaining net proceeds of the Company. As consideration for the Series C preferred stock sale, the Company received $7,928,968 in cash, and promissory notes from two of its founders and one board member amounting to $57,755. The Company incurred legal and other offering costs of $87,834 in connection with this Series C preferred stock sale. In October 1995, the Board of Directors granted each purchaser of shares of senior redeemable convertible Series C preferred stock a warrant to purchase additional shares equal to 10% of the shares owned by such purchaser, at an exercise price of $3 per share, such shares to be 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 October 1996, the Board of Directors authorized a reverse stock split whereby stockholders of common stock will receive .517 shares of common stock for every one share previously owned. The previous conversion ratio of one share of Series C Preferred Stock for one share of Common Stock was adjusted for this reverse split so that one share of Series C Preferred Stock was convertible into .517 shares of common stock. In connection with the Initial Public Offering which became effective on December 26, 1996, all of the issued and outstanding shares of the Series C Preferred Stock, and all outstanding Series C Preferred Stock warrants were converted into common stock. During the year ended December 31, 1996, the Company accrued and paid dividends on the Series C preferred stock of $795,649. The following table summarizes the 1994, 1995 and 1996 activity of Series B and Series C mandatorily redeemable preferred stock:
Redeemable Preferred Stock -------------------------------------------------- Series B Series C ---------------------- ----------------------- Shares Amount Shares Amount ------ ------ ------ ------ Balance at December 31, 1993...... 29,560 $ 2,683,615 - $ - - Shares issued in October 1994..... 25,000 2,315,844 - - Accrual of dividends.............. 4,474 421,696 - - Accretion to redemption value..... - 30,367 - - ------- ----------- ---------- ----------- Balance at December 31, 1994...... 59,034 5,451,522 - - Shares issued in 1995............. - - 2,662,241 7,986,723 Issuance costs.................... - (860) - (87,834) Accrual of dividends.............. 7,837 783,700 - - Accretion to redemption value..... - 43,464 - 4,944 ------- ----------- ---------- ----------- Balance at December 31, 1995...... 66,871 6,277,826 2,662,241 7,903,833 Accretion to redemption value..... - 43,464 - 11,380 Redemption of Series B Preferred.. (66,871) (6,321,290) - - Exercise of outstanding warrants For cash...................... - - 32,029 96,087 Under cashless tender......... - - 110,653 - Conversion to common stock........ - - (2,804,923) (8,011,300) ------- ----------- ---------- ----------- Balance at December 31, 1996...... - $ - - $ - ======= =========== ========== ===========
F-11 6. COMMON STOCKHOLDERS' EQUITY (DEFICIT) On January 27, 1993, the Company sold 768,117 shares of common stock to its founding stockholders for $44,572 ($.06 per share). These shares were subject to a stock purchase and restriction agreement under which the Company had retained a right to repurchase any "unvested" shares at the original sales price of $.06 per share. These shares became fully vested on January 26, 1997. On November 9, 1993, the Company sold 259,172 shares of common stock to its founding stockholders at $.19 per share. As consideration for the common stock sale, the Company received net proceeds of $33,587 in cash and a promissory note from one of its founders amounting to $16,543. (See Note 8). On May 24, 1995, the stockholders approved a 10-for-1 stock split of the Company's common stock. All references in this report to number of common shares outstanding reflect stock splits retroactively to inception of the Company. In October 1996, the Board of Directors authorized a reverse stock split whereby stockholders of common stock received .517 shares of common stock for every one share previously owned. The previous conversion ratio of one share of Series C Preferred Stock for one share of Common Stock was also adjusted for this reverse split so that one share of Series C Preferred Stock was convertible into .517 shares of common stock. In addition, authorized, issued, and outstanding options under the Company's 1994 stock option plan were revised to reflect the impact of the reverse stock split on share and option prices. All references in this report to number of common shares outstanding reflect this reverse stock split retroactively to inception of the Company. Initial Public Offering On December 26, 1996, the Company completed an Initial Public Offering for the sale of 2,400,000 shares of Common Stock. From the date of the Initial Public Offering through March 26, 1997, the net proceeds of the Offering which approximated $23.6 million, have been used (1) to redeem all the issued and outstanding shares of the Series B Preferred Stock, (2) for capital and exploration expenditures, (3) to pay dividends accrued on the issued and outstanding Series C Preferred Stock and (4) for general corporate purposes, including expenses associated with hiring additional personnel. The Company plans to use the remaining proceeds to fund future capital and exploration programs and general corporate purposes. F-12 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 for employees over four years (annually for the first two years and monthly the last two years) and for directors and consultants over three years (annually with 50% in year one) and certain of these options are eligible for accelerated vesting upon a change of control of the Company. At December 31, 1996 the Company had reserved 1,501,813 shares of common stock for issuance under this Plan. The following table summarizes option balances and activity for the Plan: Year Ended December 31, -------------------------- 1994 1995 1996 ---- ---- ---- Option shares: Outstanding at beginning of year................... - 438,783 686,943 Granted during year..... 438,783 248,160 267,806 Exercised during year... - - (3,124) Canceled during year.... - - (157,146) -------- -------- -------- Outstanding at end of year. 438,783 686,943 794,479 Options exercisable at end of year................... - - - Shares available for grant at end of year............ 549,154 300,994 190,334 Weighted average price of options: Granted during year....... $ 0.22 $ 0.56 $ 2.81 Exercised during year..... - - $ 0.19 Outstanding at end of year... $ 0.22 $ 0.42 $ 0.70 Weighted average fair value of options granted during year............... - $ 3.72 $ 8.95
At December 31, 1996 At December 31, 1996 ----------------------------------- ------------------------------------ Weighted- Weighted- Weighted - Range of average average average exercise prices Number outstanding exercise price contractual life Number exercisable exercise price - --------------- ------------------ --------------- ---------------- ----------------- -------------- $0.19-0.58 761,908 $ 0.37 8.0 337,980 $0.28 $7.95 27,401 $ 7.95 9.8 - - $11.00 5,170 $ 11.00 9.8 - - ------- ------- Total Options 794,479 $ 0.70 8.1 337,980 $0.28 ======= =======
In connection with stock options granted within one year of the Initial Public Offering, the Company has recorded deferred compensation as additional paid in capital and an offsetting contra-equity account. Such compensation accrual is based on the difference between the option price and the $11.00 per share Initial Public Offering common stock price. Such deferred compensation is being recorded as compensation over the period during which the options become vested. F-13 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 grants of 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: 1995 1996 ---- ---- Net Loss As Reported $(2,488,375) $(2,735,364) Pro forma (2,480,893) (2,450,298) Primary and Fully Diluted Earnings per Share As Reported $ (1.14) $ (1.16) Pro forma $ (1.14) $ (1.07) Pro forma Assumptions: Risk Free Interest Rate: Maximum 5.98% 6.68% Minimum 5.59% 5.35% Expected Option Life: Maximum 5.0 years 4.5 years Minimum 4.6 years 3.7 years Volatility was not considered in the above calculation as the Company was not publicly traded until December 26, 1996. 8. NOTES RECEIVABLE FROM STOCK SALES During 1994, 1995 and 1996, two officers and one member of the Board of Directors purchased common or preferred stock for notes, which are reflected as an offset to equity in the accompanying financial statements. The notes were full recourse promissory notes bearing interest at a fixed rate of 6% per annum. The notes from the two employees were collateralized by certain vested stock options the individuals hold from their former employer. The principal and all accrued interest on the notes held at December 31, 1995 were repaid in 1996. 9. SAVINGS PLAN The Company has joined with Landmark in offering its employees an employee 401-K 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 15% of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. While the Plan allows for employer matching of a portion of the employee contributions, the Company has elected not to match contributions. 10. COMMITMENTS Effective March 1, 1995, the Company entered into a 5-year office facilities operating lease agreement which required an 18-month rent prepayment at inception, and contains typical renewal options and escalation clauses. Future minimum payments under non-cancelable office facilities and office equipment operating leases having initial terms of one year or more are as follows at December 31, 1996: 1997.......................................... $ 99,681 1998.......................................... 99,870 1999.......................................... 99,374 2000.......................................... 18,037 Thereafter.................................... 189 -------- Total minimum lease payments.................. $317,151 ======== Rental expense under these operating leases was approximately $61,000 in 1994, $90,370 in 1995, and $106,825 in 1996. F-14 11. SALE OF ASSETS 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. 12. SUPPLEMENTAL CASH FLOW INFORMATION The following table summarizes cash paid for interest and taxes as well as non-cash transactions for the indicated years: 1994 1995 1996 ---- ---- ---- Cash paid during the year for interest... $ - $ - $ 289 Non-cash Transactions: Dividends declared but not paid.......... $ - $275,256 $ - Accretion on preferred stock............. 30,367 48,408 54,844 Sale of Series B preferred and common stock in exchange for promissory note from one of the founders (October 24, 1994)...................... 12,492 - - Stock dividend on Series B preferred stock................................... 421,699 783,700 - Sale of Series C preferred stock in exchange for promissory notes from two of the founders......................... - 57,755 - 10 for 1 common stock split (Note 6)..... - - - Exercise of outstanding warrants......... - - 572 13. SUBSEQUENT EVENTS In January 1997, the Company's underwriters exercised their 30-day option to purchase 375,000 additional shares of Common Stock at the Offering price of $11.00 per share, less underwriting discounts and commissions. The Company received net proceeds of approximately $3.8 million upon issuance of these shares. This option was granted to the underwriters to cover over-allotments in connection with the Initial Public Offering and sale of 2,400,000 shares of the Company's common stock which became effective on December 26, 1996. On January 21, 1997, the Company entered into an agreement with Esenjay Petroleum Corp., one of 3DX's active partners, to increase the 3DX working interest in three active projects in the Texas Gulf Coast trend and one active project in the Mississippi/Alabama trend for a consideration of $1,337,500. On March 5, 1997, the Company, along with Santa Fe Energy Resources, Inc., one of 3DX's active partners, was the successful bidder on four offshore blocks offered in the Federal Lease Sale No. 166, Central Gulf of Mexico. These successful bids are subject to final review and approval by the Minerals Management Service, and are not final until approval is obtained. The Company has incurred pre-lease costs of $260,000 and has committed an additional $839,765 for this acreage. F-15 14. 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, 1994, 1995 and 1996. 1994 1995 1996 ---- ---- ---- Oil and gas revenues................ $ 303,836 $ 274,511 $ 851,827 Lease operating costs............... 14,225 60,877 49,016 Production taxes.................... 19,812 17,656 58,660 Impairment of oil and gas properties......................... - 1,627,321 1,476,690 Depletion, depreciation and amortization....................... 90,672 158,336 422,839 ---------- ----------- ----------- Income (loss) before income taxes... 179,127 (1,589,679) (1,155,378) Income tax expense (credit)......... - - - ---------- ----------- ----------- Net income (loss)................... $ 179,127 $(1,589,679) $(1,155,378) ========== =========== =========== Amortization per physical unit of production (equivalent Mcf of gas). $ 0.64 $ 1.15 $ 1.31 ========== =========== =========== 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. 15. 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, 1994, 1995 and 1996 were as follows: 1994 1995 1996 ---- ---- ---- Unproved properties................. $ 828,321 $ 1,375,145 $ 4,403,165 Proved properties................... 1,575,146 2,648,724 7,164,397 --------- ----------- ----------- Total capitalized costs............. 2,403,467 4,023,869 11,567,562 Less-accumulated depletion, depreciation and amortization...... (90,672) (1,876,329) (3,775,858) ---------- ----------- ----------- $2,312,795 $ 2,147,540 $ 7,791,704 ========== =========== =========== Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $828,321, $1,375,145, and $4,403,165 at December 31, 1994, 1995 and 1996, respectively. The projects represented by these costs were at such dates undergoing exploration or development activities or projects in which the Company intends to commence such 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 the unevaluated properties at December 31, 1996 will be fully evaluated in 24 to 36 months. The following table represents an analysis of remaining unevaluated oil and gas property costs at December 31, 1996, and the years in which they were incurred: 1994 1995 1996 ========== =========== =========== Acquisition costs.................. $ 13,075 $ 70,865 $ 3,512,948 Exploration costs.................. 7,114 3,617 795,546 ---------- ----------- ----------- Total............................ $ 20,189 $ 74,482 $ 4,308,494 ========== =========== =========== F-16 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: 1994 1995 1996 ---- ---- ---- Property acquisition costs- Proved $ - $ - $ - Unproved 372,134 490,141 1,171,217 Exploration costs 1,618,149 1,611,192 6,269,266 Development costs - - 103,210 ---------- ---------- ---------- $1,990,283 $2,101,333 $7,543,693 ========== ========== ========== 16. 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 Company began its exploration program in 1993, by participating in an exploration program as a royalty owner. The Company did not produce any discovered oil and gas reserves in 1993. The Company added proved oil and gas reserves in 1994 as a result of exploration efforts on one prospect. In 1995, the Company added proved reserves from one additional well in the 1994 prospect, and drilled one additional successful well in a new prospect. In addition, there was a significant downward revision in oil and gas reserves associated with the Bright Falcon project. The primary factors contributing to the reserve revision include (1) the premature loss of a well due to mechanical reasons which was unanticipated at the time of the initial estimate, and (2) the removal of proved, undeveloped reserves attributable to a well location, which the project partners elected not to drill. In the year ended December 31, 1996, the Company added proved reserves from ten successful wells from drilling on various prospects. The Company also made certain downward revisions to its previous estimates. Such revisions result from additional production and performance information which became available during 1996. F-17 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 independent petroleum engineers, Ryder Scott Company. The following table sets forth the changes in the Company's total proved reserves (all of which are developed) for the years ended December 31, 1994, 1995 and 1996.
Year Ended December 31, ----------------------------------- 1994 1995 1996 --------- ---------- --------- Oil (Bbls) ----------------------------------- Proved reserves at the beginning of the year................................... 4,000 39,886 41,193 Extensions, discoveries, and other additions.............................. 42,000 26,000 9,797 Revisions of previous estimates......... - (18,000) (10,079) Production.............................. (6,114) (6,693) (8,483) --------- -------- -------- Proved reserves at the end of the year.. 39,886 41,193 32,428 ========= ======== ======== Gas (Mcf) ----------------------------------- Proved reserves at the beginning of the year................................... 20,000 1,236,915 442,795 Extensions, discoveries, and other additions.............................. 1,322,000 104,000 2,284,482 Revisions of previous estimates......... - (801,000) 7,661 Production.............................. (105,085) (97,120) (271,202) --------- --------- --------- Proved reserves at the end of the year.. 1,236,915 442,795 2,463,736 ========= ========= =========
F-18 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):
December 31, ----------------------------- 1994 1995 1996 -------- ------- ------- Future cash inflow $ 2,997 $ 1,405 $ 9,354 Future production, development and abandonment costs (755) (329) (1,430) ------- ------- ------- Future cash flows before income taxes 2,242 1,076 7,924 Future income taxes - - - ------- ------- ------- Future net cash flows 2,242 1,076 7,924 10% Discount factor (636) (305) (1,301) ------- ------- ------- Standardized measure of discounted future net cash flow $ 1,606 $ 771 $ 6,623 ======= ======= ======= Changes in standardized measure of discounted future net cash flows: Sales of oil, gas and natural gas liquids, net of production costs $ (270) $ (196) $ (744) Extensions, discoveries and other additions 1,878 349 6,594 Revisions of estimates of reserves proved in prior years: Quantities estimated - (1,280) (200) Net changes in price and production cost - (71) 173 Accretion of discount 6 161 77 Changes in future development costs (112) 103 (82) Changes in production rates (timing) and other 44 99 34 ------ ------- ------- Net change $1,546 $ (835) $ 5,852 ====== ======= =======
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 arbitrary 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, 1996 were approximately $24.64 per barrel of oil and approximately $3.47 per Mcf of gas. The Company does not have oil and gas reserves which are committed under oil and gas contracts. F-19 EX-11.1 2 COMPUTATION OF EARNINGS PER SHARE EXHIBIT 11.1 CALCULATION OF NET LOSS PER COMMON SHARE
1993 1994 1995 1996 ---------- ---------- ------------ ----------- Net Loss $ (615,079) $ (385,013) $(2,488,375) $(2,735,364) Preferred B Dividend (52,790) (421,696) (783,700) - Preferred B Accretion (14,353) (30,367) (43,464) (43,464) Preferred B Redemption Premium - - - (365,810) Preferred C Dividend - - (275,256) (520,393) Preferred C Accretion - - (4,944) (11,380) ---------- ---------- ------------- ----------- Net Loss Attributable to Common Stock $ (682,222) $ (837,076) $(3,595,739) $(3,676,411) ========== ========== ============= =========== Avg. Weighted Shares 1,154,329 2,534,175 3,148,826 3,162,934 ========== ========== ============= =========== Net Loss Per Common Share $(0.59) $(0.33) $(1.14) $(1.16) ========== ========== ============= ===========
CALCULATION OF ACTUAL WEIGHTED AVERAGE SHARES OUTSTANDING
Annual Weighted Issue Date Actual Shares Average ---------- ------------- ---------- Inception 1/27/93 768,117 768,117 Options Issued within 12 months of IPO 1/27/93 160,917 160,917 Common Stock Sales 11/9/93 1,464,413 225,294 ------------- ---------- 1993 Ending Balance 12/31/93 2,393,447 1,154,328 ------------- ========== 1994 Beginning Balance 2,393,447 2,393,447 Common Stock Sales 10/24/94 755,378 140,728 ------------- ---------- 1994 Ending Balance 12/31/94 3,148,825 2,534,175 ------------- ========== 1995 Beginning Balance 3,148,825 3,148,826 Common Stock Sales - - ------------- ---------- 1995 Ending Balance 12/31/95 3,148,825 3,148,826 ------------- ========== 1996 Beginning Balance 3,148,825 3,148,826 Option Exercise, 9/30/96 5/15/96 3,124 1,960 Conversion of Series C 12/26/96 1,376,379 18,803 Conversion of Series C Warrants 12/26/96 73,766 1,008 IPO Shares 12/26/96 2,400,000 32,787 Exclusion of Options for Period Subsequent to 9/30/96 (160,917) (40,450) ------------- ---------- 1996 Ending Balance 6,841,177 3,162,934 ------------- ==========
EX-23.2 3 CONSENT OF RYDER SCOTT COMPANY EXHIBIT 23.2 (LETTERHEAD OF RYDER SCOTT COMPANY) CONSENT OF INDEPENDENT PETROLEUM ENGINEERS As independent petroleum engineers, we hereby consent to the use of our name in the Annual Report on Form l0-K of 3DX Technologies Inc. for the year ended December 31, 1996. We further consent to the inclusion of our estimate of reserves and present value of future net reserves dated February 6, 1997 in such Annual Report. RYDER SCOTT COMPANY PETROLEUM ENGINEERS Houston, Texas March 26, 1997 EX-27 4 FINANCIAL DATA SCHEDULE
5 YEAR YEAR DEC-31-1995 DEC-31-1996 JAN-01-1995 JAN-01-1996 DEC-31-1995 DEC-31-1996 5,704,014 17,521,745 1,595,167 0 113,704 554,210 0 0 0 0 7,498,671 18,241,050 5,278,671 13,278,627 (2,343,578) (4,702,296) 10,450,504 26,827,189 233,908 2,253,565 0 0 14,181,659 0 0 0 29,879 68,412 (4,270,198) 24,505,212 10,450,504 26,827,189 274,511 851,827 568,892 1,329,343 1,864,190 2,007,206 1,864,190 2,007,206 1,193,077 2,057,501 (2,488,375) (2,735,364) 0 0 (2,488,375) (2,735,364) 0 0 (2,488,375) (2,735,364) 0 0 0 0 0 0 (2,488,375) (2,735,364) (1.14) (1.16) 0 0
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