-----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, LjQuxxcjVxvQfsYcDLvkX2M18dN2oBsBNFLeULlmrGpslrMc/eml3b/adGMb0PuG E9Koi/vpB7NnbR6QxY7zTQ== 0000930661-99-000668.txt : 19990402 0000930661-99-000668.hdr.sgml : 19990402 ACCESSION NUMBER: 0000930661-99-000668 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19981231 FILED AS OF DATE: 19990331 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TITAN EXPLORATION INC CENTRAL INDEX KEY: 0001024645 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752671582 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 000-21843 FILM NUMBER: 99581079 BUSINESS ADDRESS: STREET 1: 500 W TEXAS AVE STREET 2: STE 500 CITY: MIDLAND STATE: TX ZIP: 79701 BUSINESS PHONE: 9156826612 MAIL ADDRESS: STREET 1: 500 W TEXAS AVE STREET 2: SUITE 500 CITY: MIDLAND STATE: TX ZIP: 79701 10-K 1 FORM 10-K ================================================================================ UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 _________________________ FORM 10-K _________________________ (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1998 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ______________ to _____________ Commission file number: 000-21843 TITAN EXPLORATION, INC. (Exact name of Registrant as Specified in its Charter) Delaware 75-2671582 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 500 West Texas, Suite 500 Midland, Texas 79701 (Address of principal executive offices) (Zip Code) (915) 498-8600 (Registrant's telephone number, including area code) -------------------------------- Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Title of Each Class Which Registered -------------------------------- -------------------------------- None None Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.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 pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] As of March 1, 1999, the Registrant had outstanding 37,934,675 shares of Common Stock. The aggregate market value of the Common Stock held by non- affiliates of the Registrant, based upon the closing sale price of the Common Stock on March 1, 1999, as reported on the Nasdaq National Market, was approximately $105,000,000. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement for the Registrant's 1999 Annual Meeting of Stockholders to be held on or about May 26, 1999, are incorporated by reference in Part III of this Form 10-K. Such definitive proxy statement will be filed with the Securities and Exchange Commission not later than 120 days subsequent to December 31, 1998. ================================================================================
TABLE OF CONTENTS ----------------- Page ---- PART I Item 1. Business............................................................................. 1 Item 2. Properties........................................................................... 10 Item 3. Legal Proceedings.................................................................... 14 Item 4. Submission of Matters to a Vote of Security Holders.................................. 15 Executive Officers of the Registrant................................................. 15 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters................ 17 Item 6. Selected Financial Data.............................................................. 18 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 20 Item 7A. Quantitative and Qualitative Disclosures About Market Risk........................... 36 Item 8. Financial Statements and Supplementary Data.......................................... 38 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. 39 PART III Item 10. Directors and Executive Officers of the Registrant................................... 40 Item 11. Executive Compensation............................................................... 40 Item 12. Security Ownership of Certain Beneficial Owners and Management....................... 40 Item 13. Certain Relationships and Related Party Transaction.................................. 40 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K...................... 41 Glossary of Oil and Gas Terms........................................................ 46 Signatures........................................................................... 49 Index to Consolidated Financial Statements........................................... F-1
TITAN EXPLORATION, INC. 1998 ANNUAL REPORT ON FORM 10-K PART I ITEM 1. BUSINESS Titan Exploration, Inc. (the "Company") is an independent energy company engaged in the exploitation, development, exploration and acquisition of oil and gas properties located in the Permian Basin of West Texas and southeastern New Mexico, south Texas, Gulf Coast region and Gulf of Mexico. Since our inception in March 1995, we have increased our reserves, production and cash flow through (i) the development and exploration of our properties and (ii) the acquisition of producing properties that provide exploitation, development and exploration potential. The Company is incorporated in the State of Delaware, its principal executive offices are located at 500 West Texas, Suite 500, Midland, Texas 79701, and its telephone number is (915) 498-8600. Recent Developments Asset Divestiture In the fourth quarter of 1998, the Company approved a plan to dispose of non- strategic assets, including its Gulf of Mexico, Gulf Coast and certain Permian Basin assets. The Company's reason to dispose of these assets varied depending on the portfolio of assets being considered. The disposition will allow the Company to (a) realize full value for certain assets whose value is not fully reflected in the public valuation of the Company in the capital markets, (b) redeploy capital to higher return projects or acquisitions, (c) invest in projects that will accelerate cash flow to the Company, (d) eliminate certain administrative costs and (e) reduce the Company's debt obligations. The Company will not ultimately sell assets for which adequate consideration is not offered. Subject to adequate consideration, the Company expects to dispose of these assets by the end of the third quarter of 1999. Paragon Prospect The Company has entered into an exploitation joint venture with the Permian Gas Business Unit of Mobil Exploration & Producing U.S. Inc. ("MEPUS"). The new venture, named Paragon, will conduct a proprietary 3-D seismic program covering approximately 600 square miles in two phases of 300 square miles each in Culberson and Reeves counties in the Permian Basin of West Texas. The venture has acquired over 350,000 net acres of leasehold interests to date. The Company owns a 50% working interest in the leasehold acreage and was substantially carried in the acquisition of the leasehold interest. Additionally, the Company is substantially carried by MEPUS in the acquisition of the Phase I seismic program and, if the parties elect to acquire the Phase II seismic program, MEPUS will pay approximately 75% of the costs to acquire this additional 300 miles. The Company will pay 25% of the costs of the Phase II seismic program and will own, along with MEPUS, the proprietary 3-D seismic data over the entire 600 square miles. Once the Company has recovered its share of costs paid, MEPUS will share in the Company's revenues until such time as it has recovered its share of costs. The costs of all wells drilled and subsequent acreage acquired will be shared equally by MEPUS and the Company. Subsequently, MEPUS and the Company will share all costs and production equally. To date, approximately 200 miles of the Phase I seismic program has been acquired. Based upon the results of the initial phase, the parties may commit to the Phase II seismic program which will cover the remaining 300 square miles. It is anticipated that the acquisition of all 600 square miles of seismic data will be completed by mid-2000. Upon completion, the program should represent one of the largest proprietary contiguous 3-D seismic acquisition programs conducted within the onshore lower 48 states. Successful prospect development is expected to result in drilling activity beginning late in the first half of 1999 and continue as quality prospects are identified. - 1 - Offshore Activities In the Gulf of Mexico, the Company has drilled the Vermilion Block 253 A-1 well to a depth of 11,270 feet. Mud log shows supported by open hole logs and sidewall cores indicate potential oil and gas zones from at least 16 pay zones. Although the Company is enthusiastic about these shows and the potential of this discovery, production testing and additional drilling is necessary before the Company can more accurately determine the effect on future cash flows and reserves. The Company is the operator and has a 50% working interest (38.42% net revenue interest) in this block. The Company anticipates that it will drill subsequent wells to test deeper horizons which are highly productive in the area. This property and the Company's other Gulf of Mexico interests are included in its asset divestiture plan. The Company drilled the Vermilion Block 252 F-4 and has completed the well as a dual flowing well. The gas condensate zone has been completed and the well is flowing approximately 600 barrels of condensate per day and 500 Mcf of gas per day. The oil zone is awaiting pipeline construction to an adjacent platform and oil production is expected to commence during mid-1999. The Company is the operator of the block and owns a 41.25% working interest (31.49% net revenue interest). Onshore Activities The Eller No. 1 has been completed in the deep, downdip overpressured Austin Chalk. The well is currently producing 3,800 Mcf of gas per day to the Company's interest. The Company owns a 33% working interest in this non- operated well. The Company recently spudded three additional wells (Dierking No. 1, Titan No. 1 and Rains Trust No. 1) in the area with varying ownership percentages. Subsequently, the Titan No. 1 was determined to be a dry hole. The Company's net cost is approximately $1.7 million. The Habanero No. 1, the Company's first Webb County, Texas well, is currently flowing at a rate of approximately 155 Mcf of gas per day. The Company has a 50% working interest in the well. The rate and pressure are down from an initial rate of approximately 2.5 MMcf of gas per day and significantly higher flowing tubing pressures. The Company is currently considering additional testing to determine whether stimulation might achieve greater production levels. While the Company was disappointed in the results of this first well on its 200,000 acres, the presence of natural gas coupled with good reservoir quality supported additional drilling activities. In November 1998, the Company spudded a second well, the Jalapeno No. 1, to further test the acreage. The well did not discover any economical reserves. Primarily as a result of the drilling activities the Company has impaired a significant portion of the Webb County acreage. The Company believes there still is potential in the future but has no current drilling activity planned. Other The Company recently reduced its staff in its Gulf Coast and Gulf of Mexico regions as part of integrating the December 1997 OEDC and Carrollton acquisitions, described below, and as part of its plans to divest non-strategic assets in these regions. The Company will further reduce its administrative costs in these regions upon completion of the dispositions. However, the full impact of these cost reductions may not be visible until the third quarter of 1999. - 2 - Overview The Company's strategy is to grow reserves, production and net income per share through (i) the exploitation and development of its reserve base, (ii) the acquisition of producing properties that provide significant development and exploratory drilling potential, (iii) the exploration for oil and gas reserves, (iv) capitalization on advanced technology to identify, explore and exploit projects, (v) financial flexibility, and (vi) a low overhead and operating cost structure. As of December 31, 1998, the Company estimated net proved reserves of approximately 23.0 MMBbls of oil and 332.0 Bcf of natural gas, or an aggregate of 470.0 Bcfe with a PV-10 of $242.2 million. Approximately 60% of these reserves were classified as proved developed. The Company acquired, explored for and developed its reserves for an average reserve replacement cost of approximately $.77 per Mcfe from inception of the Company through December 31, 1998. The Company prefers to acquire properties over which it can exercise operating control. As of December 31, 1998, the Company operated 825 gross productive wells (740 net productive wells) and these operated properties represented approximately 84% of its proved developed PV-10 and 83% of the Company's PV-10 attributable to proved reserves as of such date. The Company's emphasis on controlling the operation of its properties enables the Company to better manage expenses, capital allocation and other aspects of development and exploration. The Company's proved oil and gas properties are located in more than 90 fields in the Permian Basin and in 24 lease blocks in the Gulf of Mexico and, to a lesser extent, in north and south Louisiana. Approximately 56% of the Company's PV-10 of total proved reserves is concentrated in 7 principal fields located in the Permian Basin. The Permian Basin is characterized by complex geology with numerous known producing horizons and provides significant opportunities to increase reserves, production and ultimate recoveries through development, exploratory and horizontal drilling, recompletions, secondary and tertiary recovery methods, and use of 3-D seismic and other advanced technologies. The Company was formed in 1996 for the purpose of becoming the holding company for Titan Resources, L.P. ("TRLP") pursuant to the terms of an exchange agreement dated September 30, 1996. TRLP was formed in March 1995 and grew primarily through acquisitions of oil and gas properties and the exploitation of those properties. Under the exchange agreement, effective September 30, 1996, (i) the limited partners of TRLP transferred all their limited partnership interests to the Company in exchange for an aggregate of 19,318,199 shares of Common Stock, and (ii) the shareholders of Titan Resources I, Inc., a Texas corporation that is the general partner of TRLP, transferred all the issued and outstanding stock of that corporation to the Company in exchange for an aggregate of 231,814 shares of Common Stock. These transactions are referred to as the "Conversion." As a result of the Conversion, Titan Exploration, Inc. owns, directly or indirectly, all the partnership interests in TRLP and conducts its active business operations through TRLP. References to the "Company" are to Titan Exploration, Inc. and its predecessors and subsidiaries, including TRLP. Acquisitions The Company's strategy is to make acquisitions with exploitation potential. The following four paragraphs outline the Company's significant acquisitions since the inception of the Company. In December 1995, the Company acquired a concentrated group of Permian Basin producing oil and gas properties from a large independent Company for a purchase price of approximately $41.0 million (the "1995 Acquisition"). On October 31, 1996, the Company acquired additional Permian Basin producing properties from a major integrated company for a purchase price of approximately $136.0 million (the "1996 Acquisition"). In December 1997, the Company issued 5,486,734 shares of Common Stock in connection with its acquisition of all of the issued and outstanding shares of common stock of Offshore Energy Development Corporation ("OEDC"), an independent energy company that focuses on the acquisition, exploration, development and production of natural gas and on natural gas gathering, processing and marketing activities (the "OEDC - 3 - Acquisition"). OEDC's integrated operations are conducted in the Gulf of Mexico, where OEDC had an interest in 24 lease blocks, all of which are operated by OEDC. In December 1997, the Company issued 899,965 shares of Common Stock in connection with its acquisition of all of the issued and outstanding units of membership interests in Carrollton Resources, L.L.C., a small independent energy company engaged in the exploration, development and acquisition of onshore oil and gas properties located primarily in the Gulf Coast region (the "Carrollton Acquisition"). In December 1997, the Company completed the acquisition of certain oil and gas producing properties from Pioneer Natural Resources USA, Inc., a wholly-owned subsidiary of Pioneer Natural Resources Company ("Pioneer"), for a purchase price of approximately $55.8 million (the "Pioneer Acquisition"). The Company regularly pursues and evaluates acquisition opportunities (including opportunities to acquire oil and gas properties or related assets or entities owning oil and gas properties or related assets and opportunities to engage in mergers, consolidations or other business combinations with entities owning oil and gas properties or related assets) and at any given time may be in various stages of evaluating these opportunities. These stages may take the form of internal financial and oil and gas property analysis, preliminary due diligence, the submission of an indication of interest, preliminary negotiations, negotiation of a letter of intent, or negotiation of a definitive agreement. While the Company is currently evaluating a number of potential acquisition opportunities (some of which would be material in size to the Company), it has not signed a letter of intent with respect to any material acquisition and currently has no assurance of completing any particular material acquisition or of entering into negotiations with respect to any particular material acquisition. Oil and Gas Marketing and Major Customers The revenues generated by the Company's operations are highly dependent upon the prices of, and demand for, oil and gas. The price received by the Company for its oil and gas production depends on numerous factors beyond the Company's control including seasonality; the condition of the United States and world economy, particularly the manufacturing sector; foreign imports; political and economic conditions in other oil-producing and gas-producing countries; the actions of OPEC and domestic government regulation, legislation and policies. Decreases in the prices of oil and natural gas could have a material adverse effect on the carrying value of the Company's proved reserves and the Company's revenues, profitability and cash flow. Although the Company is not currently experiencing any significant involuntary curtailment of its oil or gas production, market, economic and regulatory factors may in the future materially affect the Company's ability to sell its oil or gas production. During, 1998, sales to Enron Corp., and its subsidiaries and affiliates, Dynegy Inc. and Western Gas Resources, Inc. were approximately 31%, 13% and 13% of the Company's oil and gas revenues, respectively. Due to the availability of other markets and pipeline connections, the Company does not believe that the loss of any single crude oil or gas customer would have a material adverse effect on the Company's results of operations. Competition The oil and gas industry is highly competitive. The Company encounters competition from other oil and gas companies in all areas of its operations, including the acquisition of producing properties. The Company's competitors include major integrated oil and gas companies and numerous independent oil and gas companies, individuals and drilling and income programs. Many of its competitors are large, well established companies with substantially larger operating staffs and greater capital resources than the Company and which, in many instances, have been engaged in the energy business for a much longer time than the Company. Such companies may be able to pay more for productive oil and gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than the Company's financial or human resources permit. The Company's ability to acquire additional properties and to discover reserves in the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. - 4 - Operating Hazards and Uninsured Risks Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, mechanical problems, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. The Company's future drilling activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on the Company's future results of operations and financial condition. In addition, the Company's use of 3-D seismic requires greater pre-drilling expenditures than traditional drilling strategies. Although the Company believes that its use of 3-D seismic will increase the probability of success of its exploratory wells and should reduce average finding costs through the elimination of prospects that might otherwise be drilled solely on the basis of 2-D seismic data and other traditional methods, unsuccessful wells are likely to occur. There can be no assurance that the Company's drilling program will be successful or that unsuccessful drilling efforts will not have a material adverse effect on the Company. Although the Company has identified numerous potential drilling locations, there can be no assurance that such locations will ever be drilled upon or that oil or gas will be produced from them. The Company's operations are subject to hazards and risks inherent in drilling for and producing and transporting oil and gas such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, cratering, pipeline ruptures and spills. Any of the preceding risks can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to properties of the Company and others. The Company's offshore operations are also subject to the additional hazards of marine operations such as severe weather, capsizing and collision. The Company expects to drill a number of deep vertical and horizontal wells in the future. The Company's deep and/or horizontal drilling activities involve greater risk of mechanical problems than other type drilling operations. These wells may be significantly more expensive to drill than those drilled to date. The Company maintains insurance against some, but not all, of the risks described above. The Company may elect to self-insure in circumstances in which management believes that the cost of insurance, although available, is excessive relative to the risks presented. The occurrence of an event that is not covered, or not fully covered, by insurance could have a material adverse effect on the Company's financial condition and results of operations. Employees As of December 31, 1998, the Company had 94 full-time employees, none of whom is represented by a labor union. Included in the total were 29 administrative employees located in the Company's office in Midland, Texas, eight of whom are involved in the management of the Company. The Company considers its relations with its employees to be good. Office Facilities The Company currently leases approximately 50,937 square feet of office space in Midland, Texas, where its principal offices are located. This office lease is with an affiliate of Jack Hightower. The Company's principal offices are leased through March 15, 2002. The Company currently leases approximately 8,433 and 3,420 square feet of office space in The Woodlands, Texas and Baton Rouge, Louisiana, respectively, where division offices are located. - 5- Title to Properties The Company received title opinions relating to properties representing 80% of the PV-10 of the 1995 Acquisition, 90% of the PV-10 of the 1996 Acquisition and 54% of the PV-10 of the Pioneer Acquisition. The Company's land department and contract land professionals have reviewed title records of substantially all its producing properties. The title investigation performed by the Company prior to acquiring undeveloped properties is thorough but less rigorous than that conducted prior to drilling, consistent with industry standards. The Company believes it has satisfactory title to all of its producing properties in accordance with standards generally accepted in the oil and gas industry. The Company's properties are subject to customary royalty interests, liens incident to operating agreements, liens for current taxes and other burdens which the Company believes do not materially interfere with the use of or affect the value of such properties. The Company's Credit Agreement is secured by a first lien on properties that represented at least 80% of the value of the Company's proved oil and gas properties (based on PV-10 as of December 31, 1998). Presently, the Company keeps in force its leaseholds for 21% of its net acreage by virtue of production on that acreage in paying quantities. The remaining acreage is held by lease rentals and similar provisions and requires production in paying quantities prior to expiration of various time periods to avoid lease termination. Governmental Regulation The Company's oil and gas exploration, production and related operations are subject to extensive rules and regulations promulgated by federal and state agencies. Failure to comply with such rules and regulations can result in substantial penalties. The regulatory burden on the oil and gas industry increases the Company's cost of doing business and affects its profitability. Although the Company believes it is in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, the Company is unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on the Company's financial condition and results of operations. Such regulation requires permits for drilling operations, drilling bonds and reports concerning operations and imposes other requirements relating to the exploration and production of oil and gas. Such state and federal agencies have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging and abandonment of such wells. The Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas produced by the Company, as well as the revenues received by the Company for sales of such production. Since the mid-1980s, FERC has issued a series of orders, culminating in Order Nos. 636, 636-A and 636-B ("Order 636"), that have significantly altered the marketing and transportation of gas. Order 636 mandated a fundamental restructuring of interstate pipeline sales and transportation service, including the unbundling by interstate pipelines of the sale, transportation, storage and other components of the city-gate sales services such pipelines previously performed. One of FERC's purposes in issuing the orders is to increase competition within all phases of the gas industry. The United States Court of Appeals for the District of Columbia Circuit largely upheld Order 636, and the Supreme Court has declined to hear the appeal. Generally, Order 636 has eliminated or substantially reduced the interstate pipelines' traditional role as wholesalers of natural gas, and has substantially increased competition and volatility in natural gas markets. The price the Company receives from the sale of oil and natural gas liquids is affected by, among other things, the cost of transporting products to market. Effective January 1, 1995, FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. The Company is not able to predict with certainty the effect, if any, of these regulations on its operations. However, the regulations may increase transportation costs or reduce wellhead prices for oil and natural gas liquids. - 6 - Environmental Matters The Company's operations and properties are subject to extensive and changing federal, state and local laws and regulations relating to environmental protection including the generation, storage, handling, emission, transportation and discharge of materials into the environment, and their relation to safety and health. The recent trend in environmental legislation and regulation generally is moving toward stricter standards, and this trend will likely continue. These laws and regulations may require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit construction, drilling and other activities on certain lands lying within wilderness and other protected areas; and impose substantial liabilities for pollution resulting from the Company's operations. The permits required for various operations of the Company are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violators are subject to fines or injunction, or both. In the opinion of management, the Company is in substantial compliance with current applicable environmental laws and regulations, and the Company has no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant material impact on the Company, as well as the oil and gas industry in general. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA") and comparable state statutes impose strict, joint and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of "hazardous substances" found at such sites. 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. Resource Conservation and Recovery Act ("RCRA") and comparable state statutes govern the disposal of "solid waste" and "hazardous waste" and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of "hazardous substance," state laws affecting the Company's operations impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as "nonhazardous," such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements. Federal regulations require certain owners or operators of facilities that store or otherwise handle oil, such as the Company, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. The Oil Pollution Act of 1990, as amended ("OPA"), contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate $10 million in financial responsibility. In addition, the OPA currently requires persons responsible for "offshore facilities" to establish $150 million in financial responsibility to cover environmental cleanup and restoration costs likely to be incurred in connection with an oil spill in the waters of the United States. On September 10, 1996, Congress passed legislation that would lower the financial responsibility requirement under OPA to $35 million, subject to an increase of $150 million if a formal risk assessment indicates the increase is warranted. The impact of any legislation is not expected to be any more burdensome to the Company than it will be to other similarly situated companies involved in oil and gas exploration and production. OPA imposes a variety of additional requirements on "responsible parties" for vessels or oil and gas facilities related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. The "responsible parties" include the owner or operator of an onshore facility, pipeline, or vessel or the lessee or permittee of the area in which an offshore facility is located. OPA assigns liability to each responsible party for oil spill removal costs and a variety of public and private damages from oil spills. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill is caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If a party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply. OPA establishes a liability limit for offshore facilities (including pipelines) of all removal costs plus $75 million. Few defenses exist to the liability for oil spills imposed by OPA. OPA also imposes other requirements on facility operators, such as the preparation of an oil spill contingency plan. Failure to comply with ongoing requirements or inadequate cooperation in a spill event may subject a responsible party to civil or criminal enforcement actions. - 7 - In addition, the Outer Continental Shelf Lands Act ("OSCLA") authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating in the Outer Continental Shelf ("OCS"). Specific design and operational standards may apply to OCS vessels, rigs, platforms, pipelines, vehicles and structures. Violations of lease conditions or regulations issued pursuant to 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 Federal Water Pollution Control Act ("FWPCA") imposes restrictions and strict controls regarding the discharge of produced waters and other oil and gas wastes into navigable waters. Permits must be obtained to discharge pollutants into state and federal waters. The FWPCA and analogous state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of oil and other hazardous substances in reportable quantities and, along with the OPA, may impose substantial potential liability for the costs of removal, remediation and damages. State water discharge regulations and the federal National Pollutant Discharge Elimination System ("NPDES") permits prohibit or are expected to prohibit within the next year the discharge of produced water and sand, and some other substances related to the oil and gas industry, into coastal waters. Although the costs to comply with zero discharge mandates under federal or state law may be significant, the entire industry will experience similar costs and the Company believes that these costs will not have a material adverse impact on the Company's financial conditions and operations. Some oil and gas exploration and production facilities are required to obtain permits for their storm water discharges. Costs may be incurred in connection with treatment of wastewater or developing storm water pollution prevention plans. Regulations are currently being developed under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on the Company. In addition, the Clean Water Act and analogous state laws require permits to be obtained to authorize discharge into surface waters or to construct facilities in wetland areas. With respect to certain of its operations, the Company is required to maintain such permits or meet general permit requirements. The Environmental Protection Agency ("EPA") recently adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group or seek coverage under an EPA general permit. The Company believes that it will be able to obtain, or be included under, such permits, where necessary, and to make minor modifications to existing facilities and operations that would not have a material effect on the Company. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on the Company. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to significant liabilities on the part of the Company to the government and third parties and may require the Company to incur substantial costs of remediation. Moreover, the Company has agreed to indemnify sellers of producing properties purchased in each of its substantial acquisitions against environmental claims associated with such properties. No assurance can be given that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not materially adversely affect the Company's results of operations and financial condition or that material indemnity claims will not arise against the Company with respect to properties acquired by the Company. The Company has acquired leasehold interests in numerous properties that for many years have produced oil and gas. Although the previous owners of these interests may have used operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties. In addition, some of the Company's properties are operated by third parties over whom the Company has no control. Notwithstanding the Company's lack of control over properties operated by others, the failure of the operator to comply with applicable environmental regulations may, in certain circumstances, materially adversely impact the Company. Abandonment Costs The Company is responsible for payment of plugging and abandonment costs on the oil and gas properties pro rata to its working interest. Based on its experience, with the exception of its offshore oil and gas properties, the Company anticipates that the ultimate aggregate salvage value of lease and well equipment located on its properties will exceed the costs of abandoning such properties. There can be no assurance, however, that the - 8 - Company will be successful in avoiding additional expenses in connection with the abandonment of any of its properties. In addition, abandonment costs and their timing may change due to many factors including actual production results, inflation rates and changes in environmental laws and regulations. The Company establishes reserves, exclusive of salvage value, to provide for the eventual abandonment of its offshore wells and platforms. Historically, the actual cost to the Company of physically abandoning its wells has been largely offset by the proceeds from the sale of the salvaged equipment. There can be no assurance that an active secondary market in used equipment will continue to exist at the time that properties are abandoned, or that the regulatory and other costs of abandoning offshore properties will not increase. See Note 2 of Notes to Consolidated Financial Statements. The Company carries a $3 million area-wide abandonment bond with the Mineral Management Service ("MMS"). The MMS is empowered to require supplemental abandonment bonds under appropriate circumstances. While the cost to the Company of these supplemental bonds to date has not been material, no assurance may be given that the amounts will not increase, or that the availability thereof will not be restricted. - 9 - ITEM 2. PROPERTIES Oil and Natural Gas Reserves The following table summarizes the estimates of the Company's historical net proved reserves as of December 31, 1998 and 1997, and the present values attributable to these reserves at such dates. The reserve and present value data of the Company were prepared by the Company's independent petroleum consultants.
December 31, ------------------------------ 1998 1997 ------------ ------------ (dollars in thousands) Estimated proved reserves: Oil (MBbls).................................................... 23,011 30,275 Gas (MMcf)..................................................... 331,970 345,372 MMcfe (6 Mcf per Bbl).......................................... 470,036 527,022 Proved developed reserves as a percentage of proved reserves....... 60% 68% PV-10 (a).......................................................... $242,170 $435,127 Standardized Measure of Discounted Future Net Cash Flows (b)....... $236,628 $349,050
____________ (a) The present value of future net revenue attributable to the Company's reserves was prepared using prices and costs in effect at the end of the respective periods presented, discounted at 10% per annum on a pre-tax basis. These amounts reflect the effects of the Company's hedging activities. (b) The Standardized Measure of Discounted Future Net Cash Flows prepared by the Company represents the present value of future net revenues after income taxes discounted at 10%. These amounts reflect the effects of the Company's hedging activities. In accordance with applicable requirements of the Securities and Exchange Commission ("SEC"), estimates of the Company's proved reserves and future net revenues are made using sales prices and costs estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties (except to the extent a contract specifically provides for escalation). The average realized prices for the Company's reserves as of December 31, 1998 were $9.49 per Bbl of oil and $1.57 per Mcf of natural gas, compared to average realized prices for the Company's reserves as of December 31, 1997 of $16.11 per Bbl of oil and $1.83 per Mcf of natural gas. Estimated quantities of proved reserves and future net revenues therefrom are affected by crude oil and natural gas prices, which have fluctuated widely in recent years. There are numerous uncertainties inherent in estimating oil and gas reserves and their estimated values including many factors beyond the control of the producer. The reserve data set forth in this report represents only estimates. Reservoir engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers, including those used by the Company, may vary. In addition, estimates of reserves are subject to revision based upon actual production, results of future development and exploration activities, prevailing oil and gas prices, operating costs and other factors, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered and are highly dependent upon the accuracy of the assumptions upon which they are based. The Company's estimated proved reserves have not been filed with or included in reports to any federal agency. 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. - 10 - Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. Productive Wells and Acreage Productive Wells The following table sets forth the Company's productive wells as of December 31, 1998:
Actual ---------- Gross Net ---------- ---------- Oil....................................................... 2,109 720 Gas....................................................... 643 251 ----- ---- Total Productive Wells.................................... 2,752 971 ===== ====
Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed in more than one producing horizon are counted as one well. Acreage Data Undeveloped acreage includes leased 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. A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres expressed as whole numbers and fractions thereof. The following table sets forth the approximate developed and undeveloped acreage in which the Company held a leasehold mineral or other interest as of December 31, 1998.
Developed Acres Undeveloped Acres Total Acres --------------- ----------------- ----------- Gross Net Gross Net Gross Net --------- --------- ---------- ---------- ---------- ---------- Total......... 290,012 130,544 757,777 476,064 1,047,789 606,608
Drilling Activities The following table sets forth the drilling activity of the Company on its properties for 1998, 1997 and 1996.
Year Ended December 31, -------------------------------------------------------------------- 1998 1997 1996 --------------------- -------------------- ---------------------- Gross Net Gross Net Gross Net --------- --------- --------- --------- --------- --------- Exploratory Wells: Productive....................... 8.0 3.6 2.0 1.0 - - Nonproductive.................... 3.0 2.5 2.0 1.8 1.0 0.2 --- --- --- --- --- --- Total.......................... 11.0 6.1 4.0 2.8 1.0 0.2 ==== === === === === === Development Wells: Productive....................... 22.0 18.8 48.0 17.2 7.0 3.9 Nonproductive.................... 4.0 3.7 6.0 4.5 1.0 0.2 --- --- --- --- --- --- Total.......................... 26.0 22.5 54.0 21.7 8.0 4.1 ==== ==== ==== ==== === ===
- 11 - Net Production, Unit Prices and Costs The following table presents certain information with respect to oil and gas production, prices and costs attributable to all oil and gas property interests owned by the Company for 1998, 1997 and 1996.
Year Ended December 31, -------------------------------------------------------- 1998 1997 1996 ----------------- ----------------- ---------------- Production Oil (MBbls).................................................. 2,492 1,880 714 Gas (MMcf)................................................... 26,731 22,104 5,787 Total (MMcfe)................................................ 41,683 33,385 10,071 Average sales price (a): Oil (per Bbl)................................................ $ 12.05 $ 18.67 $ 19.16 Gas (per Mcf)................................................ $ 1.60 $ 1.75 $ 1.75 Total (per Mcfe)............................................. $ 1.75 $ 2.21 $ 2.37 Production costs, excluding production and other taxes (per Mcfe)......................................................... $ .65 $ .48 $ .72 Production and other taxes (per Mcfe).......................... $ .14 $ .17 $ .19 General and administrative costs (per Mcfe).................... $ .22 $ .16 $ .23 Depletion, depreciation and amortization expenses (per Mcfe)... $ .65 $ .60 $ .57
_____________ (a) Reflects results of hedging activities in 1998, 1997 and 1996. Transportation, Gathering and Processing Assets (All included in asset divestiture plan) Dauphin Island Gathering Partners The Company owns a 1% interest in Dauphin Island Gathering Partners ("DIGP"), which owns the Dauphin Island Gathering System (DIGS). DIGS consists of a FERC regulated offshore transmission system and non-regulated offshore gathering system which delivers gas to two market outlets. One market outlet is via delivery of gas to Texas Eastern ("TETCO") at Main Pass Block No. (MP) 164, and the other outlet is the delivery of gas to a location near Coden in Mobile County, Alabama where deliveries can be made to each of three pipelines, (Transco, Florida Gas Transmission, and Koch). DIGS system consists primarily of 24 inch and 20 inch pipelines. Once the Mobile Bay Processing Plant, discussed herein, is in service, the transmission system will have the dual purpose of delivering rich and lean gas streams onshore Alabama. The gathering system consists primarily of 12 inch pipeline. DIGS has a current throughput capacity of up to approximately 1,200 MMcf per day, depending on where gas enters the system, which could be expanded with looping and onshore compression. At December 1998, DIGS was transporting approximately 500 MMcf per day. The Company's interest can increase from 1% up to 11.15% when the other partners of DIGP receives the return of their investment in DIGP plus a moderate rate of return. The back-in is subject to a reduction from 10.15% to 8.15% if the Company does not exercise the option to increase its interest in MBPP. Mobile Bay Processing Partners The Company owns an .86% interest in Mobile Bay Processing Partners ("MBPP"), which is constructing the natural gas processing plant. The Company has an option from certain of the partners of MBPP to purchase an additional 27.9% interest in MBPP for a 3-year period beginning with the plant start-up, which would increase its interest to 28.8%. The Mobile Bay Processing Plant is currently near completion. The plant is scheduled to start up during the first quarter 1999. At start-up, the plant is expected to process approximately 550 MMcf per day. - 12 - Gulf Coast NGL Pipeline The Company owns an .86% interest in Gulf Coast NGL Pipeline L.L.C. ("Gulf Coast") (as a result of its ownership in MBPP), which owns a 16.67% interest in Tri-States NGL Pipeline, L.L.C. ("Tri-States"), the entity that is constructing a natural gas liquids pipeline. The Company has an option to purchase an additional 27.9% interest in Gulf Coast for a 3-year period beginning with the liquids pipeline start-up, which would bring its total partnership interest to 28.8%. The initial pipeline design capacity for the Tri-States is 80,000 Bbls per day. This capacity is expandable to 150,000 Bbls per day. - 13 - ITEM 3. LEGAL PROCEEDINGS The following is a brief description of certain litigation to which the Company is subject, as a result of assuming the obligations of Offshore Energy Development Corporation ("OEDC"). The Company believes it has meritorious defenses to the claims and intends to vigorously defend against such claims. The Company does not believe that it has a probable and estimable loss with respect to any such litigation in excess of currently provided reserves, if any. If such loss becomes probable and estimable, the amount of any recorded liability could have a material adverse effect on the Company's (i) results of operations for the period in which such liability is recorded, (ii) consolidated financial position as a whole and (iii) liquidity and capital resources. However, the Company does not expect that any such liability will have a material adverse effect on its consolidated financial position as a whole or on its liquidity or capital resources. Due to the uncertainties inherent in litigation, no assurance can be given to the ultimate outcome of these matters. OEDC and certain of its officers and directors, as well as Natural Gas Partners, L.P. ("NGP"), the managing underwriters of OEDC's initial public offering and an analyst from each of the managing underwriters, have been named as defendants in a suit styled Eric Baron and Edward C. Allen, on behalf of Themselves and all Others Similarly Situated, v. David B. Strassner, Douglas H. Kiesewetter, David R. Albin, Natural Gas Partners, L.P., David Garcia, John J. Myers, Offshore Energy Development Corporation, Morgan Keegan & Company, Inc. and Principal Securities Inc., which was filed October 20, 1997, in the Texas State District Court of Harris County, Southern District of Texas. Plaintiffs motion to have the case remanded to the state court was granted by the federal judge in April 1998. The suit seeks class certification on behalf of certain holders of common stock of denied class certification at this time, in deference to a parallel federal court action, which is described below. The suit alleges generally that the defendants wrongfully made false or misleading statements or omissions relating to OEDC's business and prospects in the course of OEDC's initial public offering and subsequent thereto. The state court suit seeks rescission of sales of common stock of OEDC and unspecified monetary damages, including punitive damages. OEDC and certain of its officers and directors, as well as NGP, have also been named defendants in a suit styled John W. Robertson, et al. v. David B. Strassner, Douglas H. Kiesewetter, David R. Albin, Natural Gas Partners, L.P. and Offshore Energy Development Corporation, which was filed February 6, 1998, in the United States Southern District of Texas, Houston Division. This suit mirrors the allegations of the foregoing matter, but adds request for relief under federal securities laws. It, too, seeks certification of a class of certain purchasers of common stock OEDC. The suit seeks compensatory damages, including rescissory damages, where applicable. Discovery on the two previously discussed cases has commenced. A mediation hearing, of all parties, has been set for April 20, 1999. The Company is involved in other various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company's financial position, results of operations or liquidity. - 14 - ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS (a) Inapplicable. (b) Inapplicable. (c) Inapplicable. (d) Inapplicable. EXECUTIVE OFFICERS OF THE REGISTRANT Pursuant to Instruction 3 to Item 401(b) of the Regulation S-K and General Instruction G(3) to Form 10-K, the following information is included in Part I of this report. The following table sets forth certain information concerning the executive officers of the Company as of December 31, 1998:
Name Age Position ---- --- -------- Jack D. Hightower.................. 50 President and Chief Executive Officer George G. Staley................... 64 Executive Vice President, Exploration Rodney L. Woodard.................. 43 Vice President, Engineering Thomas H. Moore.................... 54 Vice President, Business Development Dan P. Colwell..................... 54 Vice President, Land William K. White................... 56 Vice President, Finance and Chief Financial Officer John L. Benfatti................... 53 Vice President, Accounting and Controller Susan D. Rowland................... 38 Vice President, Administration and Corporate Secretary
Set forth below is a description of the backgrounds of each executive officer of the Company, including employment history for at least the last five years. Jack D. Hightower has served as President, Chief Executive Officer and Chairman of the Board of Directors of the Company since he founded the Company in March 1995. Prior to founding the Company, from 1986 to January 1996, Mr. Hightower served as Chairman of the Board and Chief Executive Officer of United Oil Services, Inc., a complete oil field service Company serving customers in the Permian Basin. From 1978 to 1995, Mr. Hightower served as Chairman of the Board and President of Amber Energy, Inc., a Company formed to identify oil and gas exploration prospects. From 1991 to 1994, Mr. Hightower served as Chairman of the Board, Chief Executive Officer and President of Enertex, Inc., which served as the operator of record for several oil and gas properties involving Mr. Hightower and other nonoperators, including Selma International Investment Limited. Since 1990, Mr. Hightower has served on the Board of Directors of Texas Commerce Bank, N.A., Midland. George G. Staley has served as Executive Vice President, Exploration and Director of the Company since its formation. From 1975 until 1995, Mr. Staley served as President and Chief Executive Officer of Staley Gas Co., Inc. and Staley Operating Co., which are oil and gas exploration and operating companies. Rodney L. Woodard has served as Vice President, Engineering for the Company since its formation. From 1985 to 1995, Mr. Woodard served as Vice President of Selma International Investment Limited. Thomas H. Moore has served as Vice President, Business Development of the Company since its formation. From 1992 to 1995, Mr. Moore served as Managing Partner of Magnum Energy Corporation, L.L.C. From 1991 until 1992, Mr. Moore served as Executive Vice President -- Exploration and Production, Chief Operating Officer and - 15 - Director of Clayton Williams Energy, Inc. From 1985 to 1991, Mr. Moore served as President, Chief Operating Officer and Director of Clayton W. Williams, Jr. Inc. Dan P. Colwell has served as Vice President, Land for the Company since its formation. From 1993 to 1995, Mr. Colwell served as Vice President of Land for Enertex, Inc. Mr. Colwell was employed by ARCO as Director of Business Development from 1991 to 1993 and Area Land Manager from 1987 to 1991. William K. White has served as Vice President, Finance and Chief Financial Officer of the Company since September 1996. From 1994 to September 1996, Mr. White was Senior Vice President of the Energy Investment Group of Trust Company of The West. From 1991 to 1994, Mr. White was President of the Odessa Associates, a private firm engaged in the practice of providing financial consulting services to the oil and gas industry. John L. Benfatti has served as Vice President, Accounting and Controller of the Company since its formation. From 1980 to 1995, Mr. Benfatti served as Controller and Treasurer of Staley Gas Co., Inc. Susan D. Rowland has served as Vice President, Administration and Corporate Secretary of the Company since its formation. From 1986 to 1996, Ms. Rowland served as a corporate officer and administrative manager of a number of companies, including Amber Energy, Inc., Enertex, Inc., Haley Properties, Inc. and United Oil Services, Inc. - 16 - PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Company's Common Stock has been publicly traded on the Nasdaq National Market under the symbol "TEXP" since the Company's initial public offering effective December 16, 1996. The following table summarizes the high and low reported sales prices on Nasdaq for each quarterly period since the Company's initial public offering:
Common Stock ---------------------- High Low ---------- ---------- 1997: First Quarter..................................... $14.750 $8.125 Second Quarter.................................... 12.125 6.750 Third Quarter..................................... 13.000 9.500 Fourth Quarter.................................... 13.875 8.875 1998: First Quarter..................................... $ 9.625 $6.688 Second Quarter.................................... 9.500 7.500 Third Quarter..................................... 9.125 5.500 Fourth Quarter.................................... 8.938 5.375 1999: First Quarter (through March 1, 1999)............. $ 7.188 $4.625
As of March 1, 1999, the Company estimates that there were more than 150 record holders and more than 3,400 beneficial holders of the Company's Common Stock. No dividends have been declared or paid on the Company's Common Stock to date. Currently, the Company plans to retain all future earnings for the development of its business. - 17 - ITEM 6. SELECTED FINANCIAL DATA The following selected consolidated financial data should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's consolidated financial statements and related notes included in "Item 8. Consolidated Financial Statements and Supplementary Data."
Year Ended December 31, Period March 31, 1995 -------------------------------------------------- (date of inception) through 1998 1997(a) 1996 (a) December 31, 1995(a) -------------- -------------- -------------- ------------------------ (in thousands, except per share amounts and operating data) Consolidated Statement of Operations Data: Revenues- Operating revenues............................ $ 72,876 $ 73,827 $ 23,824 $ 743 Expenses: Oil and gas production........................ 27,078 16,298 7,312 265 Production and other taxes.................... 5,725 5,548 1,887 39 General and administrative.................... 9,163 5,372 2,270 1,546 Amortization of stock option awards........... 5,055 5,053 1,839 576 Exploration and abandonment................... 17,596 3,055 184 490 Depletion, depreciation and amortization...... 27,090 19,972 5,789 299 Impairment of long-lived assets............... 25,666 68,997 -- -- Restructuring costs........................... 625 -- -- -- Interest...................................... 8,648 1,524 2,965 97 Other......................................... (1,172) (258) (503) (1,038) -------- --------- --------- -------- Total expenses............................. 125,474 125,561 21,743 2,274 -------- --------- --------- -------- Income (loss) before income taxes............. (52,598) (51,734) 2,081 (1,531) Income tax expense (benefit).................. (5,381) (18,267) 3,484 -- -------- --------- --------- -------- Net loss...................................... $(47,217) $ (33,467) $ (1,403) $ (1,531) ======== ========= ========= ======== Net loss per common share..................... $ (1.22) $ (.99) $ (.07) $ (.11) Net loss per common share - assuming dilution............................. $ (1.22) $ (.99) $ (.07) $ (.11) Weighted average common shares outstanding.... 38,808 33,942 19,605 14,066 Consolidated Statement of Cash Flows Data: Net cash provided by (used in): Operating activities.......................... $ 18,448 $ 46,563 $ 7,710 $ (1,805) Investing activities.......................... (58,413) (114,302) (144,998) (47,522) Financing activities.......................... 38,972 63,052 137,365 55,540 Other Consolidated Financial Data: Capital expenditures............................ $ 63,235 $ 114,377 $ 150,119 $ 43,770 Consolidated Operating Data: Production: Oil (MBbls)..................................... 2,492 1,880 714 30 Gas (MMcf)...................................... 26,731 22,104 5,787 245 Total (MMcfe)................................... 41,683 33,385 10,071 425 Average Sales Prices Per Unit(b): Oil (per Bbl)................................... $ 12.05 $ 18.67 $ 19.16 $ 16.80 Gas (per Mcf)................................... 1.60 1.75 1.75 .97 Total (per Mcfe)................................ 1.75 2.21 2.37 1.75 Expenses per Mcfe: Production costs, excluding production and...... other taxes.................................... $ .65 $ .48 $ .72 $ .63 Production and other taxes...................... .14 .17 .19 .09 General and administrative...................... .22 .16 .23 3.64 Depletion, depreciation and amortization........ .65 .60 .57 .70
- 18 -
December 31, ------------------------------------------------- 1998 1997(a) 1996(a) 1995(a) -------- ----------- ----------- ---------- (in thousands) Consolidated Balance Sheet Data: Cash and cash equivalents................. $ 610 $ 1,603 $ 6,290 $ 6,213 Working capital (c)....................... 105,697 28 8,124 11,946 Oil and gas assets, net................... 209,177 271,920 190,062 42,861 Total assets.............................. 341,022 352,583 207,179 57,487 Total debt................................ 144,200 85,450 6,500 20,000 Stockholders' equity and predecessor capital.................................. 171,354 232,421 187,186 34,585
____________ (a) Certain reclassifications have been made to the 1997, 1996 and 1995 amounts to conform to the 1998 presentation. (b) Reflects results of hedging activities. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations." (c) The 1998 amount includes $109.5 million of assets held for sale. - 19 - ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS General The Company is an independent energy company engaged in the exploitation, development, exploration and acquisition of oil and gas properties. The Company's strategy is to grow reserves, production and net income per share through (i) the exploitation and development of its reserve base, (ii) the acquisition of producing properties that provide significant development and exploratory drilling potential, (iii) the exploration for oil and gas reserves, (iv) capitalization on advanced technology to identify, explore and exploit projects, (v) financial flexibility, and (vi) a low overhead and operating cost structure. The Company has grown rapidly through the acquisition and exploitation of oil and gas properties, consummating the 1995 Acquisition for a purchase price of approximately $41.0 million, the 1996 Acquisition for approximately $136.0 million and the Pioneer Acquisition, in 1997, for approximately $55.8 million. In addition, the Company issued, in 1997, 5,486,734 shares and 899,965 shares of the Company's common stock in connection with the OEDC Acquisition and the Carrollton Acquisition, respectively. The Company's growth from acquisitions has impacted its financial results in a number of ways. Acquired properties may not have received focused attention prior to sale. After acquisition, certain of these properties required extensive maintenance, workovers, recompletions and other remedial activity that while not constituting capital expenditures may initially increase lease operating expenses. The Company may dispose of certain of the properties it determines are outside the Company's strategic focus. The increased production and revenue resulting from the rapid growth of the Company has required it to recruit and develop operating, accounting and administrative personnel compatible with its increased size. As a result, the Company has incurred increases in its general and administrative expense levels. The Company believes that with its current inventory of drilling locations and the additional staff it will be well positioned to follow a more balanced program of exploration and exploitation activities to complement its acquisition efforts. The Company uses the successful efforts method of accounting for its oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that result in proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not result in proved reserves, and geological and geophysical costs are expensed. Costs of significant nonproducing properties, wells in the process of being drilled and significant development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. The Company's predecessor was classified as a partnership for federal income tax purposes. Therefore, no income taxes were paid by the Company prior to the Conversion. Future tax amounts, if any, will be dependent upon several factors, including, but not limited to, the Company's results of operations. Impact of Crude Oil Prices During 1998, the posted price of West Texas intermediate crude oil (the "West Texas Crude Oil Price") ranged from $15.75 to $8.00 per barrel. These low prices are thought to be caused primarily by an oversupply of crude oil inventory created, in part, by an unusually warm winter in the United States and Europe, the apparent unwillingness of Organization of Petroleum Exporting Countries ("OPEC") to abide by their respective crude oil production quotas and a decline in demand in certain Asian markets. If the West Texas Crude Oil Price worsens or persists for a protracted period, it will adversely affect the Company's revenues, net income and cash flows from operations. Also, if these prices maintain their present level for an extended time period or decline further, the Company may delay or postpone certain of its capital projects. If the posted West Texas Crude Oil Price continues to decline, the Company would expect that it may be required to record an impairment to its oil and gas properties in 1999. The extent of an impairment, if any, cannot be determined. - 20 - It is the Company's expectation that it will not have positive earnings in 1999 or the near term future unless oil and gas commodity prices improve above their current levels, especially the price of crude oil. Year 2000 Issues Many computer software systems, as well as certain hardware and equipment using date-sensitive data, were structured to use a two-digit date field meaning that they may not be able to properly recognize dates in the year 2000. The Company is addressing this issue through a process that entails evaluation of the Company's critical software and, to the extent possible, its hardware and equipment to identify and assess Year 2000 issues and to remediate, replace or establish alternative procedures addressing non-Year 2000 complaint systems, hardware and equipment. The Company has substantially completed an inventory of its systems and equipment including computer systems and business applications. Based upon this review, the Company currently believes that all of its critical software and computer hardware systems are either Year 2000 compliant or will be within the next six months. The Company continues to inventory its equipment and facilities to determine if they contain embedded date-sensitive technology. If problems are discovered, remediation, replacement or alternative procedures for non-compliant equipment and facilities will be undertaken on a business priority basis. This process will continue and, depending upon the equipment and facilities, is scheduled for completion during the first three quarters of 1999. As of December 31, 1998, the Company had not incurred any material amount of expense related to its Year 2000 compliance efforts. These costs are currently being expensed as they are incurred. However, in certain instances the Company may determine that replacing existing equipment may be more efficient, particularly where additional functionality is available. These replacements may be capitalized and therefore would reduce the estimated 1999 expenses associated with the Year 2000 issue. The Company currently expects total out- of-pocket costs to become Year 2000 compliant to be less than $100,000. The Company currently expects that such costs will not have a material adverse effect on the Company's financial condition, operations or liquidity. The foregoing timetable and assessment of costs to become Year 2000 compliant reflect management's current best estimates. These estimates are based on many assumptions, including assumptions about the cost, availability and ability of resources to locate, remediate and modify affected systems, equipment and facilities. Based upon its activities to date, the Company does not currently believe that these factors will cause results to differ significantly from those estimated. However, the Company cannot reasonably estimate the potential impact on its financial condition and operations if key third parties including, among others, suppliers, contractors, joint venture partners, financial institutions, customers and governments do not become Year 2000 compliant on a timely basis. The Company is contacting many of these third parties to determine whether they will be able to resolve in a timely fashion their Year 2000 issues as they may affect the Company. In the event that the Company is unable to complete the remediation or replacement of its critical systems, facilities and equipment, establish alternative procedures in a timely manner, or if those with whom the Company conducts business are unsuccessful in implementing timely solutions, Year 2000 issues could have a material adverse effect on the Company's liquidity and results of operations. At this time, the potential effect in the event the Company and/or third parties are unable to timely resolve their Year 2000 problems is not determinable; however, the Company currently believes that it will be able to resolve its own Year 2000 issues in a timely manner. The disclosure set forth in this section is provided pursuant to Securities Act Release No. 33-7558. As such it is protected as a forward-looking statement under the Private Securities Litigation Reform Act of 1995. See "Forward- Looking Statements." This disclosure is also subject to protection under the Year 2000 Information and Readiness Disclosure Act of 1998, Public Law 105-271, as a "Year 2000 Statement" and "Year 2000 Readiness Disclosure" as defined therein. - 21 - Operating Data The following sets forth the Company's historical operating data:
Year ended December 31, -------------------------------------------- 1998 1997 1996 ------------ ------------- ------------- Production: Oil (MBbls).................................... 2,492 1,880 714 Gas (MMcf)..................................... 26,731 22,104 5,787 Total (MMcfe).................................. 41,683 33,385 10,071 Average sales price per unit (excluding the effects of hedging): Oil (per Bbl).................................. $11.97 $18.38 $21.26 Gas (per Mcf).................................. $ 1.51 $ 1.75 $ 1.92 Total (per Mcfe)............................... $ 1.68 $ 2.19 $ 2.61 Average sales price per unit (including the effects of hedging): Oil (per Bbl).................................. $12.05 $18.67 $19.16 Gas (per Mcf).................................. $ 1.60 $ 1.75 $ 1.75 Total (per Mcfe)............................... $ 1.75 $ 2.21 $ 2.37 Expenses per Mcfe: Production costs, excluding production and other taxes................................... $ .65 $ .48 $ .72 Production and other taxes..................... $ .14 $ .17 $ .19 General and administrative..................... $ .22 $ .16 $ .23 Depletion, depreciation and amortization....... $ .65 $ .60 $ .57
Results of Operations The Company began operations on March 31, 1995. As a result of the Company's limited operating history and rapid growth, its financial statements are not readily comparable and may not be indicative of future results. The 1996 Acquisition, which closed on October 31, 1996, did not contribute fully to the Company's 1996 operating results. The OEDC Acquisition, the Carrollton Acquisition and the Pioneer Acquisition, did not close until the end of December 1997 which did not contribute to the 1997 operating results. Year ended 1998 as compared to 1997 The Company's revenues from the sale of oil and gas (excluding the effects of hedging activities) were $29.8 million and $40.3 million in 1998 and $34.6 million and $38.7 million in 1997, respectively. Realized oil and gas prices decreased $6.41 per Bbl and $.24 per Mcf, respectively. In 1998, the 1997 Acquisitions contributed oil sales of $8.0 million and gas sales of $9.7 million with associated production of approximately 649 Mbls of oil and 5,038 Mmcf of gas, respectively. The decrease in oil revenues due to price was offset by an increase in production primarily attributable to the 1997 Acquisitions. Gas revenues increased as a result of increased production, primarily the result of the 1997 Acquisitions, despite a decrease in gas prices. Excluding the 1997 Acquisitions, the 1998 oil and gas production was relatively flat compared to 1997. The increase in production, assuming 1997 - 22 - prices, would have resulted in additional revenues to the Company of $18.2 million while the decrease in prices reduced revenues by $21.4 million. The Company's hedging activities in 1998 increased both oil and gas revenues $206,000 ($.08 per Bbl) and $2.6 million ($.09 per Mcf), respectively, as compared to 1997, when hedging activities increased oil and reduced gas revenues $551,000 ($.29 per Bbl) and $62,000 ($.003 per Mcf), respectively. At December 31, 1998 the Company had no oil hedges in place, however, gas hedges for 12,499 Mmcf of the Company's production through early 2000 were outstanding. The hedges will allow the Company to realize, at a minimum, a price of $1.81 per Mcf on the volumes hedged. The outstanding gas hedges had a fair value of approximately $1.7 million at December 31, 1998. The Company's oil and gas production costs were $27.1 million ($.65 per Mcfe) and $16.3 million ($.48 per Mcfe) in 1998 and 1997, respectively. In 1998, productions costs attributable to the 1997 Acquisitions were $11.9 million ($1.32 per Mcfe). Thus, the increase in production costs is primarily related to the 1997 Acquisitions. Excluding the 1997 Acquisitions, the Company's production costs would have decreased slightly on an absolute and Mcfe basis. Initially, acquired properties generally incur significant rework expenses, which are costs incurred to perform required maintenance, workovers and other remedial activities. The properties acquired in the Pioneer Acquisition were primarily oil in nature and generally have a higher per unit production cost as compared to gas properties. The Company expects that going forward, with its existing asset base, the per unit production costs should decrease below 1998 levels. Depletion, depreciation and amortization expense (DD&A) was $27.1 million ($.65 Mcfe) and $20.0 million ($.60 per Mcfe) in 1998 and 1997, respectively. In 1998 and 1997, DD&A included $.03 per Mcfe and $.01 per Mcfe, respectively, of depreciation and amortization of other property and equipment and other assets. In the fourth quarter of 1997 the Company recorded an impairment of $69.0 million which acted to reduce the DD&A rate going forward. This effect was offset by the higher finding costs for the properties acquired in the 1997 Acquisitions as compared to previous acquisitions. Through the first three quarters of 1998, the Company's DD&A rate was slightly below the rates for the prior comparable quarters. In the fourth quarter of 1998, the Company lost proved reserves due to the decrease primarily in oil prices, which had an adverse effect on the fourth quarter DD&A rate. The fourth quarter DD&A rate caused the annual DD&A rate for 1998 to slightly exceed that of 1997. The Company recognized an impairment of $25.7 million and $69.0 million in 1998 and 1997, respectively. The 1997 impairment was primarily related to significantly depressed commodity prices as compared to the expected commodity prices on which most of the properties were acquired. The 1998 impairment was comprised of three components (a) $22.2 million related to oil and gas properties, (b) $2.2 million related to impairment of an investment in a partnership and (c) $1.3 million related to assets held for sale. The 1998 impairment related to the oil and gas properties is primarily attributable to loss of proved reserves associated with below expectation developmental drilling results and downhole mechanical problems primarily from the Company's Gulf Coast and Gulf of Mexico regions. The Company's exploration and abandonment expense was $17.6 million and $3.1 million in 1998 and 1997, respectively. The increase is due primarily to (a) increased geological and geophysical staff, (b) impairment of unproved properties, (c) uneconomical exploratory wells and (d) delay rentals. Increase in the geological and geophysical staff was due to the Company's exploratory efforts primarily associated with the OEDC and Carrollton acquisitions in the Gulf Coast and Gulf of Mexico regions. With the Company's planned divestitures in these regions, there should be a reduction in the 1999 geological and geophysical staff costs. The Company's Webb County prospect, previously discussed, is the significant contributing factor to the increase due to (a) $1.1 million uneconomical exploratory well, (b) $9.1 million impairment of the unproved acreage and (c) approximately $1.3 million in delay rentals paid in 1998 to hold leases. The Company's general and administrative expense (G&A) was $9.2 million ($.22 per Mcfe) and $5.4 million ($.16 per Mcfe) in 1998 and 1997, respectively. G&A attributable to the OEDC and Carrollton acquisitions was over $2.2 million (over $.54 per Mcfe) in 1998. Excluding the OEDC and Carrollton acquisitions, G&A would have been approximately $.19 per Mcfe. After excluding the OEDC and Carrollton - 23 - acquisitions, the remainder of the increase in G&A from 1997 to 1998 is primarily the result of a full year's effect of the increase in staff in 1997 necessitated by the Company's growth. With the planned disposition of assets in 1999, and other cost cutting measures taken, the Company expects a decrease in its 1999 G&A on both an absolute and per Mcfe basis. In the fourth quarter of 1998, the Company recognized a restructuring charge of $625,000. This charge relates to the severance and related benefits that will be provided to individuals whose positions are being eliminated as a result of the planned disposition of assets in 1999. The 1998 equity in net loss of affiliates is attributable to the Company's ownership in DIGP and MBPP acquired in the OEDC acquisition. Included in the equity loss is approximately $632,000 of amortization of the Company's cost basis in excess of the underlying historical net assets of DIGP. The amortization of the Company's cost basis in excess of the underlying historical net assets of MBPP will commence being recorded when the underlying assets commence operations, which is expected to be the first quarter of 1999. The Company's interest expense was $8.6 million and $1.5 million in 1998 and 1997, respectively. The increase is primarily due to the increase in debt levels between years. In 1997, the average debt outstanding was lower as a result of the December 1996 initial public common stock offering. In 1998, the average outstanding debt obligation increased primarily due to (a) the Pioneer acquisition in December 1997, (b) the purchase of treasury stock, (c) the assumption of $15.8 million in debt from the OEDC and Carrollton acquisitions, (d) the Company's capital expenditure program and (e) the reduction in operating cash flow due to significantly depressed commodity prices. The Company's effective income tax rates were 10% and 35% for 1998 and 1997, respectively. The decrease in rate is due to the Company's inability in 1998 to recognize the income tax benefit associated with a loss before income taxes because it is more likely than not that the Company will not be able to utilize all its available loss carryforwards prior to their ultimate expiration. Due to the Company's inability to potentially use its loss carryforwards, the Company has provided a valuation allowance of approximately $14.0 million against its deferred tax assets. In 1999 and in future years, the Company will not be able to recognize an income tax benefit until the Company begins to generate an adequate level of earnings before income taxes. Year Ended December 31, 1996 For the year ended December 31, 1996, the Company's revenues from the sale of oil and gas (excluding the effects of hedging activities) were $15.1 million and $11.1 million, respectively. Of total gross oil and gas revenues, $16.2 million and $9.5 million are attributable to the 1995 Acquisition and the 1996 Acquisition, respectively. During the year, the Company produced 714 MBbls of oil (514 MBbls attributable to the 1995 Acquisition and 186 MBbls attributable to the 1996 Acquisition) and 5,787 MMcf of gas (3,401 MMcf attributable to the 1995 Acquisition and 2,124 MMcf attributable to the 1996 Acquisition), with total oil and gas production of 10,071 MMcfe. The revenues and production are primarily attributable to the 1995 Acquisition since the 1996 Acquisition did not close until October 31, 1996. As a result of hedging activities in the year ended December 31, 1996, oil revenues were reduced $1.5 million ($2.10 per Bbl) and gas revenues were reduced $995,000 ($.17 per Mcf) for a total reduction of $2,495,000. Oil and gas production costs, including production taxes, were $9.2 million ($.91 per Mcfe) for the year ended December 31, 1996. These costs included $2.2 million ($.22 per Mcfe) of rework expenses of which $945,000 were attributable to the 1995 Acquisition and $1.2 million were attributable to the 1996 Acquisition. Exploration and abandonment costs were $184,000 for the year ended December 31, 1996. General and administrative expenses were $2.3 million ($.23 per Mcfe) for the year ended December 31, 1996. - 24 - For the year ended December 31, 1996, depletion, depreciation and amortization expense was $5.8 million ($.57 per Mcfe). This represents a full year of depletion, depreciation and amortization relating to production for the 1995 Acquisition and two months of depletion, depreciation and amortization relating to production for the 1996 Acquisition. Interest expense was $2,965,000 for the year ended December 31, 1996. The interest expense was attributable to bank financing incurred primarily to fund the 1995 Acquisition and the 1996 Acquisition. Liquidity and Capital Resources The Company's primary sources of capital have been its initial capitalization, private equity sales, bank financing, cash flow from operations and the Company's initial public offering. The 1996 Acquisition was principally funded with bank financing, which was repaid with the proceeds from the Company's initial public offering. The OEDC Acquisition and the Carrollton Acquisition were completed by issuing common stock in exchange for the equity interest in each entity. The Pioneer Acquisition was funded with bank financing. Net Cash Provided by Operating Activities. Net cash provided by operating activities, before changes in operating assets and liabilities, was $20.2 million for the year ended December 31, 1998, compared to $43.3 million for the year ended December 31, 1997. The decrease was primarily attributable to an increase in operating and interest costs with a slight decrease in revenues. Revenues were significantly below expectation due to depressed commodity prices. Capital Expenditures. In 1998, the Company budgeted $83.8 million for capital expenditures and had actual cash expenditures of $63.2 million. The Company did not spend all of its 1998 budget primarily as a result of deferring some of its exploration and production projects (mainly oil) and the $16 million pipeline and processing project investments due to uncertainties over future commodity price levels. Cash expenditures for investing in oil gas properties were $57.4 million for the year ended December 31, 1998. This includes $5.4 million for the acquisition of oil and gas leases and $52.0 million for development and exploratory drilling. The Company requires capital primarily for the exploration, development and acquisition of oil and gas properties, the repayment of indebtedness and general working capital needs. The following table sets forth costs incurred by the Company in its exploration, development and acquisition activities.
Year Ended December 31, --------------------------------------------- 1998 1997 1996 ------------- ------------- ------------- Development costs.............................. $30,663 $44,896 $12,468 Exploration costs.............................. 21,316 2,856 129 Acquisition costs: Unproved properties........................... 4,994 24,532 802 Proved properties............................. 404 100,871 139,110 ------- ------- ------- Total..................................... $57,377 $173,155 $152,509 ======= ======== ========
For 1999, the Company, currently, expects to spend (i) approximately $15.4 million on developmental projects, (ii) approximately $28.4 million on exploratory and probable projects, of which $11.0 million relates to contingent projects following successful exploratory and probable projects, (iii) approximately $6.4 million to acquire additional acreage and seismic data and (iv) $.7 million on other items. The final - 25 - determination with respect to the drilling of any well, including those currently budgeted, will depend on a number of factors, including (i) the results of exploration efforts and the review and analysis of the seismic data, (ii) the availability of sufficient capital resources by the Company and other participants for drilling prospects, (iii) economic and industry conditions at the time of drilling, including prevailing and anticipated prices for natural gas and oil and the availability and costs of drilling rigs and crews, (iv) the financial resources and results of the Company, and (v) the availability of leases on reasonable terms and permitting for the potential drilling location. There can be no assurance that the budgeted wells will encounter, if drilled, recompleted or worked over, reservoirs of commercial quantities of natural gas or oil. While the Company regularly engages in discussions relating to potential acquisitions of oil and gas properties, the Company has no present agreement, commitment or understanding with respect to any such acquisition, other than the acquisition of oil and gas properties and interests in its normal course business. Any future acquisitions may require additional financing and will be dependent upon financing which may be required in the future to fund the Company's acquisition and drilling programs. Capital Resources. The Company's primary capital resources are net cash provided by operating activities and the availability under the Credit Agreement, of which $60 million was available at December 31, 1998. Credit Agreement. The Credit Agreement established a four year revolving credit facility, up to a maximum amount of $250 million, subject to a borrowing base to be redetermined semi-annually by the lenders based on certain proved oil and gas reserves and other assets of the Company. The borrowing base at December 31, 1998 was $200 million. To the extent that the borrowing base is less than the aggregate principal amount of all outstanding loans and letters of credit under the Credit Agreement, such deficiency must be cured by the Company ratably within 180 days, by either prepaying a portion of the outstanding amounts under the Credit Agreement or pledging additional collateral to the lenders. A portion of the credit facility is available for the issuance of up to $15.0 million of letters of credit, of which $144,000 was outstanding at December 31, 1998. All outstanding amounts under the Credit Agreement are due and payable in full on January 1, 2001. The Company's outstanding debt under the Credit Agreement was $140 million on December 31, 1998. The Company will undergo a borrowing base review in April 1999. In light of the depressed commodity prices and the related effect on the Company's oil and gas reserves, the Company cannot be reasonably assured that it will be able to maintain its current $200 million borrowing base. At the Company's option, borrowings under the Credit Agreement bear interest at either the "Base Rate" (i.e., the higher of the applicable prime commercial lending rate, or the federal funds rate plus .50% per annum) or the Eurodollar rate, plus 1.00% to 1.50% per annum, depending on the level of the Company's aggregate outstanding borrowings. In addition, the Company is committed to pay quarterly in arrears a fee of .300% to .375% of the unused borrowing base. The Credit Agreement contains certain covenants and restrictions that are customary in the oil and gas industry. In addition, the line of credit is secured by a majority of the Company's proved oil and gas properties. At December 31, 1998, the Company was not in compliance with a coverage test required by the Credit Agreement. The Company has requested and received written consents from its banks to amend this coverage test of the Credit Agreement, and the Company believes this amendment will be fully documented on or before April 30, 1999. The Company believes it will be able to comply with the amended covenants of the Credit Agreement for the foreseeable future. Liquidity and Working Capital. At December 31, 1998, the Company had $610,000 of cash and cash equivalents as compared to $1.6 million at December 31, 1997. The Company's ratio of current assets to current liabilities was 6.23 at December 31, 1998, compared to 1.00 at December 31, 1997. The Company's working capital ratio increased due to $109.5 million of assets held for sale at December 31, 1998. Excluding the assets held for sale the Company would have a working capital deficit of $3.8 million. The working capital deficit is due partially to the Company maintaining low cash levels for cash management purposes. The Company, at December 31, 1998, has availability under its Credit Agreement to fund any working capital deficit. - 26 - Unsecured Credit Agreement. In April 1997, the Company entered into a credit agreement (the "Unsecured Credit Agreement") with Texas Commerce Bank National Association (the "Bank"), which establishes a revolving credit facility, up to the maximum of $5 million. All outstanding amounts pursuant to the Unsecured Credit Agreement are due and payable in full on or before December 31, 1999. Proceeds of the Unsecured Credit Agreement are utilized to fund short-term needs (less than thirty days). The Company had $4.2 million outstanding principal under the Unsecured Credit Agreement at December 31, 1998. The interest payable on amounts outstanding under the Unsecured Credit Agreement is at a rate determined by agreement between the Company and the Bank. The rate may not exceed the maximum interest rate permitted under applicable laws. Interest rates generally are the bank's cost of funds plus 1% per annum. Other Matters Stock Options and Compensation Expense In connection with the Conversion, the Company issued options to purchase 3,631,350 shares of Common Stock to certain of its officers and employees in substitution for options issued by Titan Resources, L.P. Of the options issued by the partnership approximately 93% were issued on March 31, 1995, the date of inception, and approximately 7% were issued as of September 30, 1996. The options issued by the Company have an exercise price of $2.08 per share. Options to purchase 3,032,717 shares of Common Stock are currently vested and an additional 426,451 shares will vest on March 31, 1999. Based in part on selling prices of interests in the partnership in December 1995 and September 1996, the Company expected to record a noncash compensation expense of approximately $421,000 per month for a period of 39 months beginning in October 1996 to reflect the estimated value of the revised option plan on September 30, 1996. Noncash compensation expense recorded for the years ended December 31, 1998, 1997 and 1996 was $5,055,000, $5,053,000 and $1,839,000, respectively. During the years ended December 31, 1998, 1997 and 1996, the Company issued additional options for aggregates of 389,499, 259,000 and 85,000 shares, respectively, for which no deferred compensation was recorded as these options had no implicit value when issued. Hedging Activities The Company uses swap agreements and other financial instruments in an attempt to reduce the risk of fluctuating oil and gas prices and interest rates. The Company is party to various agreements with numerous counterparties for purposes of utilizing financial instruments, of which the Company assesses the creditworthiness of its counterparties. Among other counterparties, the Company has utilized Enron Capital & Trade Resources Corp. (an affiliate of a significant stockholder of the Company) as a counterparty. Settlement of gains or losses on the hedging transactions was generally based on the difference between the contract price and a formula using New York Mercantile Exchange ("NYMEX") or other major indices related prices and was reported as a component of oil and gas revenues as the associated production occurs. The Company, at December 31, 1998, had entered into hedging transactions with respect to approximately 11,134 and 1,365 MMcfe of its 1999 and 2000 estimated production. See "Risk Factors-Risk of Hedging Activities." Crude Oil The Company reports average oil prices per Bbl including the net effect of oil hedges. In 1998, 1997 and 1996, the Company received (paid) related to its oil hedges $206,000 ($.08 per Bbl), $551,000 ($.29 per Bbl) and ($1.5 million) ($2.10 per Bbl), respectively. Natural Gas The Company reports average gas prices per Mcf including the net effect of gas hedges. In 1998, 1997 and 1996, the Company received (paid) related to its gas hedges $2.6 million ($.09 per Mcf), ($62,000) ($.003 per Mcf) and ($995,000) ($.17 per Mcf), respectively. - 27 - Natural Gas Balancing In the natural gas industry, various working interest partners produce more or less than their entitlement share of natural gas from time to time. The Company's net underproduced position at December 31, 1998 was approximately 81,000 Mcf. Under terms of typical natural gas balancing agreements, the underproduced party can take a certain percentage, typically 25% to 50% of the overproduced party's entitled share of gas sales in future months, to eliminate such imbalances. During the make-up period, the overproduced party's cash flow will be adversely affected. The Company recognizes revenue and imbalance obligations under the entitlements method of accounting, which means that the Company recognizes the revenue to which it is entitled and records a liability with respect to the value of the overproduced gas. Environmental and Other Laws and Regulations The Company's business is subject to certain federal, state and local laws and regulations relating to the exploration for and the development, production and transportation of oil and gas, as well as environmental and safety matters. Many of these laws and regulations have become more stringent in recent years, often imposing greater liability on a larger number of potentially responsible parties. Although the Company believes it is in substantial compliance with all applicable laws and regulations, the requirements imposed by such laws and regulations are frequently changed and subject to interpretation, and the Company is unable to predict the ultimate cost of compliance with these requirements or their effect on its operations. The Company has no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws or in interpretations thereof could have a significant adverse impact on the operating costs of the Company, as well as the oil and gas industry in general. See "Risk Factors- Compliance with Environmental Regulations," "Business and Environmental Matters" and "Business and Abandonment Costs." Recently Issued Accounting Standards In June 1997, the Financial Accounting Standards Board (the "FASB") issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information" which establishes standards for reporting information about operating segments in annual financial statements and requires selected information about operating segments in interim financial reports issued to shareholders. It also establishes standards for related disclosures about products and services, geographic areas and major customers. SFAS No. 131 is effective for financial statements for periods beginning after December 15, 1997, but the statement need not be applied to interim financial statements in the initial year of application. SFAS No. 131 did not materially affect the Company's reporting practices. In June 1998, the FASB issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" which establishes standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. It establishes conditions under which a derivative may be designated as a hedge and establishes standards for reporting changes in the fair value of a derivative. SFAS No. 133 is required to be implemented for the first quarter of the fiscal year ended 2000. Early adoption is permitted. The Company has not evaluated the effects of implementing SFAS No. 133. - 28 - Risk Factors Volatility of Oil and Gas Prices; Marketability of Production Our revenues, operating results and future rate of growth are highly dependent upon the prices we receive for our oil and gas. Historically, the markets for oil and gas have been volatile and may continue to be volatile in the future. Various factors which are beyond our control such as the worldwide and domestic supplies of oil and gas, the ability of the members of the OPEC to agree to and maintain oil price and production controls, political instability or armed conflict in oil-producing regions, the price and level of foreign imports, the level of consumer demand, the price and availability of alternative fuels, the availability of pipeline capacity, weather conditions, domestic and foreign governmental regulations and taxes and the overall economic environment will affect prices of oil and gas. We are unable to predict the long-term effects of these and other conditions on the prices of oil. Lower oil and gas prices may reduce the amount of oil and gas we produce economically which may adversely affect our revenues and operating income and may require a reduction in the carrying value of our oil and gas properties. We make substantially all of our sales of oil and gas in the spot market or pursuant to contracts based on spot market prices and not pursuant to long-term fixed price contracts. We try to reduce price risk by entering into hedging transactions with respect to a portion of our expected future production. We cannot assure you, however, that such hedging transactions will reduce risk or mitigate the effect of any substantial or extended decline in oil or natural gas prices. The marketability of our production depends in part upon the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Most of our natural gas is delivered through gas gathering systems and gas pipelines that we do not own. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions all could adversely affect our ability to produce and market our oil and gas. Any dramatic change in market factors could have a material adverse effect on our business, financial condition and results of operations. Substantial Capital Requirements We make, and will continue to make, substantial capital expenditures for the exploration, development, acquisition and production of our oil and gas reserves. We intend to finance these capital expenditures primarily with funds provided by operations, the incurrence of debt, the issuance of equity and the sale of non-core assets. Our direct capital expenditures for oil and gas producing activities were $52.0 million, $47.8 million and $12.6 million for the years ended December 31, 1998, 1997 and 1996, respectively, and $2.0 million for the nine months ended December 31, 1995. If revenues decrease as a result of lower oil or gas prices or otherwise, we may have limited ability to expend the capital necessary to replace our reserves or to maintain production at current levels, resulting in a decrease in production over time. If our cash flow from operations and availability under our credit agreement are not sufficient to satisfy our capital expenditure requirements, we cannot assure you that we will be able to obtain additional debt or equity financing to meet these requirements. Uncertainty of Reserve Information and Future Net Revenue Estimates There are numerous uncertainties inherent in estimating quantities of proved reserves and their values, including many factors beyond our control. The reserve information contained in our filings with the SEC represents estimates only. Although we believe such estimates are reasonable, reserve estimates are imprecise and you should expect them to change as additional information becomes available. Estimates of oil and gas reserves, by necessity, are projections based on the evaluation of available geological, geophysical, economic and engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. Estimates of economically recoverable oil and gas reserves and of future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulations - 29 - by governmental agencies and assumptions concerning future oil and gas prices, future operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom may vary substantially from those estimated in our filings with the SEC. Moreover, we cannot assure you that our reserves will ultimately be produced or that our proved undeveloped reserves, the recovery of which requires significant capital expenditures and successful drilling operations, will be developed within the periods anticipated. Any significant variance in the assumptions could materially affect the estimated quantity and value of our reserves. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. Approximately 40% of our total proved reserves on December 31, 1998 were undeveloped, which are by their nature less certain. Recovery of these reserves will require significant capital expenditures and successful drilling operations. The reserve data set forth in our estimates assumes that we will expend substantial capital to develop these reserves. Although we have prepared our cost and reserve estimates attributable to our oil and gas reserves in accordance with industry standards, we cannot assure you that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. In addition, you should not construe the PV-10 referred to in this report to be the current market value of the estimated oil and gas reserves attributable to our properties. In accordance with applicable requirements, we generally base the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. The amount and timing of actual production, supply and demand for oil and gas, curtailments or increases in consumption by gas purchasers, changes in governmental regulations or taxation and other factors will also affect actual future net cash flows. The timing of both the production and the incurrence of expenses in connection with development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus also affect their actual present value. In addition, the 10% discount factor, which the SEC requires us to use in our calculation of the discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general. Reserve Replacement Risk Our future success depends upon our ability to find, develop or acquire additional oil and gas reserves that are economically recoverable. Our proved reserves will generally decline as a result of continued production, except to the extent that we conduct successful exploration or development activities or acquire properties containing proved reserves, or both. In order to increase reserves and production, we must continue our development and exploration drilling and recompletion programs or undertake other replacement activities. Exploratory drilling and, to a lesser extent, development drilling involve a high degree of risk that we will not obtain commercial production or that our production will be insufficient to recover drilling and completion costs. We cannot state the costs of drilling, completing and operating wells with certainty. Numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment may curtail, delay or cancel our drilling operations. Furthermore, there is no guarantee that we will recognize a profit on the investment or that we will recover our drilling, completion and operations cost upon the completion of a well. There are certain risks associated with secondary recovery operations, especially the use of waterflooding techniques. Part of our inventory of development prospects consists of waterflood projects. Waterflooding involves significant capital expenditures and uncertainty as to the total amount of secondary reserves that we can recover. In waterflood operations, there is generally a delay between the initiation of water injection into a formation containing hydrocarbons and any resulting increase in production. The operating cost per unit of production of waterflood projects is generally higher during the initial phases of such projects due to the purchase of injection water and related costs, as well as during the later stages of the life of the project as production declines. The - 30 - degree of success, if any, of any secondary recovery program depends on a large number of factors, including the porosity of the formation, the technique used and the location of injector wells. Our current strategy includes increasing our reserve base through acquisitions of producing properties, continued exploitation of our existing properties and exploration of new and existing properties. We cannot assure you, however, that our planned development and exploration projects and acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells at low finding and development costs. Furthermore, while our revenues may increase if prevailing oil and gas prices increase significantly, our finding costs for additional reserves could also increase. Acquisition Risks We expect to continue to evaluate and pursue acquisition opportunities available on terms that our management considers favorable to us. The successful acquisition of producing properties involves an assessment of recoverable reserves, future oil and gas prices, operating costs, potential environmental and other liabilities and other factors beyond our control. This assessment is necessarily inexact and its accuracy is inherently uncertain. In connection with such an assessment of the subject properties, we perform a review that we believe is generally consistent with industry practices. This review, however, will not reveal all existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections may not be performed on every well, and structural and environmental problems are not necessarily observable even upon inspection. We generally assume preclosing liabilities, including environmental liabilities, and generally acquire interests in the properties on an "as is" basis. With respect to our acquisitions to date, we have no material commitments for capital expenditures to comply with existing environmental requirements. In addition, volatile oil and gas prices make it difficult to estimate the value of producing properties for acquisition and often cause disruption in the market for oil and gas producing properties, as buyers and sellers have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and development and exploration projects. We cannot assure you that our acquisitions will be successful. Any unsuccessful acquisition could have a material adverse effect on us. Limited Operating History; Rapid Growth We began operations in March 1995, and our brief operating history includes three years of net losses and rapid growth. As a result, our historical results are not readily comparable to and may not be indicative of future results. We cannot assure you that we will continue to experience growth in, or maintain our current level of, revenues, oil and gas reserves or production. Future tax amounts, if any, will depend on several factors, including, but not limited to, our results of operations. Our rapid growth has placed significant demands on our administrative, operational and financial resources. Any future growth of our oil and gas reserves, production and operations would place significant further demands on our financial, operational and administrative resources. Our future performance and profitability will depend in part on our ability to successfully integrate the administrative and financial functions of acquired properties and companies into our operations, to hire additional personnel and to implement necessary enhancements to our management systems to respond to changes in our business. We cannot assure you that we will be successful in these efforts. Our inability to integrate acquired properties and companies, to hire additional personnel or to enhance our management systems could have a material adverse effect on our results of operations. Effects of Leverage We have certain debt obligations that may affect our operations, including (i) our need to dedicate a substantial portion of our cash flow from operations to the payment of interest on our indebtedness which prevents these funds from being available for other purposes; (ii) the covenants contained in our credit facility limit our ability to borrow additional funds or to dispose of assets and may affect our flexibility in planning for, and reacting to, changes in business conditions; and (iii) our potential inability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes. Moreover, future acquisition or development activities may require us to alter our capitalization significantly. These changes in - 31 - capitalization may significantly alter our leverage structure. Our ability to meet our debt service obligations and to reduce our total indebtedness will depend on our future performance, which will be subject to general economic conditions and to financial, business and other factors affecting our operations, many of which are beyond our control. We cannot assure you that economic conditions and financial, business and other factors will not adversely affect our future performance. Drilling and Operating Risks; Uninsured Risks Drilling activities are subject to many risks, including well blow outs, cratering, uncontrollable flows of oil, natural gas or well fluids, fires, formations with abnormal pressures, pollution, releases of toxic gases and other environmental hazards and risks, any of which could result in substantial losses to us. Our offshore operations are also subject to the additional hazards of marine operations such as severe weather, capsizing and collision. In addition, we incur the risk that we will not encounter any commercially productive reservoirs through our drilling operations. We cannot assure you that the new wells we drill will be productive or that we will recover all or any portion of our investment in wells drilled. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce net reserves to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. Numerous factors, many of which are beyond our control, including economic conditions, mechanical problems, title problems, weather conditions, compliance with governmental requirements and shortages and delays in the delivery of equipment and services may curtail, delay or cancel our drilling operations. In accordance with industry practices, we maintain insurance against some, but not all, of these risks. We cannot assure you that any of our insurance will be adequate to cover losses or liabilities. Risk of Hedging Activities Our use of energy swap arrangements and financial futures to reduce our sensitivity to oil and gas price volatility is subject to a number of risks. If we do not produce reserves at the rates we estimated due to inaccuracies in the reserve estimation process, operational difficulties or regulatory limitations, we would be required to satisfy obligations we may have under fixed price sales and hedging contracts on potentially unfavorable terms without the ability to hedge that risk through sales of comparable quantities of our own production. Further, the terms under which we enter into fixed price sales and hedging contracts are based on assumptions and estimates of numerous factors such as cost of production and pipeline and other transportation costs to delivery points. Substantial variations between the assumptions and estimates we used and actual results we experience could materially adversely affect our anticipated profit margins and our ability to manage the risk associated with fluctuations in oil and gas prices. Additionally, fixed price sales and hedging contracts limit the benefits we will realize if actual prices rise above the contract prices. In addition, fixed price sales and hedging contracts are subject to the risk that the counter-party may prove unable or unwilling to perform its obligations under such contracts. Any significant nonperformance could have a material adverse financial effect on us. As of December 31, 1998, 11,134 and 1,365 MMcfe of our 1999 and 2000 production, respectively, were subject to hedging contracts. Gas Gathering, Processing and Marketing Our gas gathering, processing and marketing operations, which are currently not significant to the Company, depend in large part on our ability to contract with third party producers to acquire their gas, to obtain sufficient volumes of committed natural gas reserves, to maintain throughput in our processing plant at optimal levels, to replace production from declining wells, to assess and respond to changing market conditions in negotiating gas purchase and sale agreements and to obtain satisfactory margins between the purchase price of our natural gas supply and the sales price for such residual gas volumes and the natural gas liquids processed. In addition, our operations are subject to changes in regulations relating to gathering and marketing of oil and gas. Our inability to attract new sources of third party natural gas or to promptly respond to changing market conditions or regulations in connection with our gathering, processing and marketing operations could materially adversely affect our business, financial condition and results of operations. - 32 - Compliance with Government Regulations Our business is subject to federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of, oil and gas, as well as safety matters that change from time to time in response to economic or political conditions. Although we believe we are in substantial compliance with all applicable laws and regulations, the requirements imposed by such laws and regulations change frequently, and these laws and regulations are subject to interpretation. Consequently, we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may have to expend a significant amount of resources to comply with government laws and regulations, and these expenditures may have a material adverse effect on our business, financial condition and results of operations. Compliance with Environmental Regulations Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on our business, financial condition and results of operations. The discharge of oil, gas or other pollutants into the air, soil or water may give rise to significant liability on our part to the government and third parties and may require us to incur substantial costs of remediation. Moreover, we have agreed to indemnify sellers of producing properties purchased in each of our substantial acquisitions against environmental claims associated with these properties. We cannot assure you that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not materially adversely affect the results of our operations or our financial condition or that material indemnity claims will not arise against us with respect to properties we acquired. Competition We operate in the highly competitive areas of oil and gas exploration, development, acquisition and production with other companies, many of which have substantially larger financial resources, staffs and facilities. In seeking to acquire desirable producing properties or new leases for future exploration and in marketing our oil and gas production, we face intense competition from both major and independent oil and gas companies. Many of these competitors have financial and other resources substantially in excess of those available to us. This highly competitive environment could have a material adverse effect on us. Dependence on Key Personnel Our success has been and will continue to be highly dependent on Jack Hightower, our Chairman of the Board and Chief Executive Officer, and a limited number of other senior management personnel. Loss of the services of Mr. Hightower or any of those other individuals could have a material adverse effect on our operations. We maintain a $3.0 million key man life insurance policy on the life of Mr. Hightower, but no other senior management personnel. In addition, as a result of our acquisitions, we have increased our number of employees and employed 94 employees at December 31, 1998. We cannot assure you that we will be successful in retaining key personnel. Our failure to hire additional personnel, if necessary, or retain our key personnel could have a material adverse effect on our business, financial condition and results of operations. Control by Existing Stockholders Our directors, executive officers and principal stockholders, and certain of our affiliates, beneficially own approximately 57.7% of our outstanding common stock on a fully-diluted basis at March 1, 1999. Accordingly, these stockholders, as a group, are able to control the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our Amended Certificate of Incorporation or Bylaws and the approval of mergers and other significant corporate transactions. The existence of these levels of ownership concentrated in a few persons makes it unlikely that any other holder of common stock will be able to affect our management or direction. These factors may also have the effect of delaying or preventing a change in our management or voting control. - 33 - Anti-Takeover Provisions Delaware law includes a number of provisions that may have the effect of delaying or deterring a change in the control of our management and encouraging persons considering unsolicited tender offers or other unilateral takeover proposals to negotiate with our Board of Directors rather than pursue non- negotiated takeover attempts. These provisions may make it more difficult for our stockholders to benefit from certain transactions which are opposed by the incumbent Board of Directors. - 34 - FORWARD-LOOKING STATEMENTS Certain statements contained in or incorporated by reference into this prospectus, including, but not limited to, those regarding our financial position, business strategy and other plans and objectives for future operations and any other statements which are not historical facts constitute "forward- looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements involve known and unknown risks, uncertainties and other important factors that could cause our actual results, performance or achievements, or industry results, to differ materially from any future results, performance or achievements expressed or implied by such forward-looking statements. Although we believe that the expectations reflected in these forward-looking statements are reasonable, we cannot assure you that the actual results or developments we anticipate will be realized or, even if substantially realized, that they will have the expected effects on our business or operations. Among the factors that could cause actual results to differ materially from our expectations are inherent uncertainties in interpreting engineering and reserve data, operating hazards, delays or cancellations of drilling operations for a variety of reasons, competition, fluctuations and volatility in oil and gas prices, our ability to successfully integrate the business and operations of acquired companies, compliance with government and environmental regulations, increases in our cost of borrowing or inability or unavailability of capital resources to fund capital expenditures, dependence on key personnel, changes in general economic conditions and/or in the markets in which we compete or may, from time to time, compete and other factors including but not limited to those set forth in "Risk Factors" or in "Item 1" in this report. These factors expressly qualify all subsequent oral and written forward-looking statements attributable to us or persons acting on our behalf. We assume no obligation to update any of these statements. - 35 - ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The following quantitative and qualitative information is provided about financial instruments to which the Company is a party as of December 31, 1998, and from which the Company may incur future earnings gains or losses from changes in market interest rates and commodity prices. The Company does not enter into derivative or other financial instruments for trading purposes. Quantitative Disclosures Commodity Price Sensitivity: The following table provides information about the Company's derivative financial instruments that are sensitive to changes in natural gas commodity prices. See notes 2, 3 and 17 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of the accounting procedures followed by the Company for commodity derivative financial instruments and for specific information regarding the terms of the Company's commodity derivative financial instruments that are sensitive to natural gas commodity prices. Fair 1999 2000 Total Value ---- ---- ----- ----- (dollars in thousands, except volumes and prices) Natural Gas Hedge Derivatives (a) Collar option contracts: Notional volumes (MMBtu) 11,134 1,365 12,499 $ 2,729 Weighted average short call MMBtu strike price (b) $ 2.111 $2.200 Weighted average long put MMBtu strike price (b) $ 2.724 $2.550 Basis differential contracts (c): Notional volumes (MMBtu) 10,839 1,365 12,204 $(1,056) Weighted average MMBtu strike price $ 0.227 $0.218
___________________________________ (a) See notes 3 and 17 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information related to hedging activities. (b) The strike prices are based on the prices traded on the New York Mercantile ("NYMEX"). (c) The basis differential relates to the spread between the NYMEX price and an El Paso/Permian price. - 36 - Interest Rate Sensitivity: The following table provides information about the Company's financial instruments that are sensitive to interest rates. The debt obligations are presented in the table at their contractual maturity dates together with the weighted average interest rates expected to be paid on the debt. The weighted average interest rates for the variable debt represents the weighted average interest paid and/or accrued in December 1998. See notes 3 and 4 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding the terms of the Company's debt obligations that are sensitive to interest rates. Fair 1999 2000 2001 Total Value ---- ---- ---- ----- ----- (in thousands, except interest rates) Debt (a) Variable rate debt: Chase Manhattan Bank, N.A. (Secured) $140,000 $140,000 $140,000 Average interest rate 7.08% 7.08% 7.08% Chase Bank of Texas, N.A. (Unsecured) $ 4,200 $ 4,200 $ 4,200 Average interest rate 6.42% 6.42% 6.42%
- -------------------------- (a) See notes 3 and 4 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information related to debt. Qualitative Disclosures The Company, from time to time, enters into interest rate and commodity price derivative contracts as hedges against interest rate and commodity price risk. See notes 2, 3 and 17 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for discussions relative to the Company's objectives and general strategies associated with it hedging instruments. The Company is a borrower under variable rate debt instruments that give rise to interest rate risk. See note 4 of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding the terms of the Company's debt obligations. The Company's policy and strategy, as of December 31, 1998, is to only enter into interest rate and commodity price derivative instruments that qualify as hedges of its existing interest rate or commodity price risks. As of December 31, 1998, the Company's primary risk exposures associated with financial instruments to which it is a party include natural gas price volatility and interest rate volatility. The Company's primary risk exposures associated with financial instruments have not changed significantly since December 31, 1997. - 37 - ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Company's Consolidated Financial Statements required by this item are included on the pages immediately following the Index to Consolidated Financial Statements appearing on page F-1. 38 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 39 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this item is incorporated by reference to information under the caption "Proposal 1 - Election of Directors" and to the information under the caption "Compliance with Section 16(a) of the Securities Exchange Act of 1934" in the Company's definitive Proxy Statement (the "1999 Proxy Statement") for its annual meeting of stockholders to be held on or about May 26, 1999. The 1999 Proxy Statement will be filed with the Securities and Exchange Commission (the "Commission") not later than 120 days subsequent to December 31, 1998. Pursuant to Item 401(b) of Regulation S-K, the information required by this item with respect to executive officers of the Company is set forth in Part I of this report. ITEM 11. EXECUTIVE COMPENSATION The information required by this item is incorporated herein by reference to the 1999 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1998. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this item is incorporated herein by reference to the 1999 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1998. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTION The information required by this item is incorporated herein by reference to the 1999 Proxy Statement, which will be filed with the Commission not later than 120 days subsequent to December 31, 1998. 40 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. Consolidated Financial Statements: See Index to Consolidated Financial Statements on page F-1. 2. Financial Statement Schedules: See Index to Consolidated Financial Statements on page F-1. 3. Exhibits: The following documents are filed as exhibits to this report:
Exhibit Number - --------- Description of Document 2.1 -- Exchange Agreement and Plan of Reorganization (filed as Exhibit 2.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 2.2 -- Amended and Restated Agreement and Plan of Merger, dated as of November 6, 1997, among Titan Exploration, Inc., Titan Offshore, Inc. and Offshore Energy Development Corporation (included as Appendix I to the Joint Proxy Statement/Prospectus forming a part of the Company's Registration Statement on S-4, Registration No. 333-40215, and incorporated herein by reference). 2.3 -- Agreement and Plan of Merger, dated as of November 4, 1997, among Titan Exploration, Inc., Titan Bayou Bengal Holdings, Inc. and Carrollton Resources, L.L.C. (filed as Exhibit 2.3 to the Company's Registration Statement on S-4 Registration No. 333-40215 incorporated herein by reference). 3.1 -- Certificate of Incorporation (filed as Exhibit 3.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 3.1.1 -- Certificate of Amendment of Certificate of Incorporation (filed as Exhibit 3.1.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 3.2 -- Bylaws (filed as Exhibit 3.2 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.1 -- Agreement of Limited Partnership, dated March 31, 1995, between Titan Resources I, Inc., as general partner, and Natural Gas Partners, L.P., Natural Gas Partners II, L.P. and Jack Hightower, as limited partners (filed as Exhibit 10.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.1.1 -- Amendment No. 1 to the Agreement of Limited Partnership of Titan Resources, L.P., dated December 11, 1995, by and among Titan Resources I, Inc., as the general partner, and a Majority Interest of the Limited Partners (filed as Exhibit 10.1.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.1.2 -- Amendment No. 2 to the Agreement of Limited Partnership of Titan Resources, L.P., dated September 27, 1996, by and among Titan Resources I, Inc., as the general partner, and a Majority Interest of the Limited Partners (filed as Exhibit 10.1.2 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.1.3 -- Amendment No. 3 to the Agreement of Limited Partnership of Titan Resources, L.P., dated September 30, 1996, by and among Titan Resources I, Inc., as the general partner, and a Majority Interest of the Limited Partners (filed as Exhibit 10.1.3 to the Company's Registration
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Exhibit Number - --------- Description of Document Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.2 -- Amended and Restated Voting and Shareholders Agreement, dated December 11, 1995, by and among Titan Resources I, Inc., Jack Hightower, Natural Gas Partners, L.P., Natural Gas Partners II, L.P., Joint Energy Development Investments Limited Partnership and First Union Corporation (filed as Exhibit 10.2 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.3 -- Amended and Restated Registration Rights Agreement, dated September 30, 1996, by and among Titan Exploration, Inc., Jack Hightower, Natural Gas Partners, L.P., Natural Gas Partners II, L.P., Joint Energy Development Investments Limited Partnership, First Union Corporation and Selma International Investment Limited (filed as Exhibit 10.3 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.4 -- Financial Advisory Services Contract, dated March 31, 1995, by and between Titan Resources, L.P. and Natural Gas Partners, L.P. and Natural Gas Partners II, L.P. (filed as Exhibit 10.4 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.4.1 -- First Amendment to Financial Advisory Services Contract, dated December 11, 1995, between Titan Resources, L.P., Natural Gas Partners, L.P. and Natural Gas Partners II, L.P. (filed as Exhibit 10.4.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.5 -- Employment Agreement, dated September 30, 1996, by and between Titan Exploration, Inc., Titan Resources I, Inc. and Jack Hightower (filed as Exhibit 10.5 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.6.1 -- Form of Confidentiality and Non-compete Agreement among Titan Resources, L.P., Titan Resources I, Inc. and certain of the Registrant's executive officers (filed as Exhibit 10.6.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.6.2 -- Form of Confidentiality and Non-compete Agreement among the Registrant, Titan Resources I, Inc. and certain of the Registrant's executive officers (filed as Exhibit 10.6.2 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.7 -- Titan Resources, L.P. Option Plan (filed as Exhibit 10.7 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.7.1 -- Form of Option Agreement (A Option) (filed as Exhibit 10.7.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.7.2 -- Form of Option Agreement (B Option) (filed as Exhibit 10.7.2 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.7.3 -- Form of Option Agreement (C Option) (filed as Exhibit 10.7.3 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.7.4 -- Form of Option Agreement (D Option) (filed as Exhibit 10.7.4 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.8 -- Titan Exploration, Inc., Option Plan (filed as Exhibit 10.8 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference).
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Exhibit Number - --------- Description of Document 10.8.1 -- Form of Option Agreement (A Option) (filed as Exhibit 10.8.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.8.2 -- Form of Option Agreement (B Option) (filed as Exhibit 10.8.2 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.8.3 -- Form of Option Agreement (C Option) (filed as Exhibit 10.8.3 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.8.4 -- Form of Option Agreement (D Option) (filed as Exhibit 10.8.4 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.9 -- 1996 Incentive Plan (filed as Exhibit 10.9 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.10 -- Stock and Unit Purchase Agreement, dated December 11, 1995, by and among Joint Energy Development Investments Limited Partnership, Titan Resources I, Inc. and Titan Resources, L.P. (filed as Exhibit 10.10 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.10.1 -- Designation Agreement, dated December 11, 1995, by and between Titan Resources, L.P. and Joint Energy Development Investments Limited Partnership (filed as Exhibit 10.10.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.11 -- Stock and Unit Purchase Agreement, dated December 11, 1995, by and among First Union Corporation, Titan Resources I, Inc. and Titan Resources, L.P. (filed as Exhibit 10.11 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.11.1 -- Designation Agreement, dated December 11, 1995, by and between Titan Resources, L.P. and First Union Corporation (filed as Exhibit 10.11.1 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.12 -- Advisory Services Contract, dated December 11, 1995, between Titan Resources, L.P. and ECT Securities Corp. (filed as Exhibit 10.12 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.13 -- Amended and Restated Credit Agreement, dated October 31, 1996, among Titan Resources, L.P. and Texas Commerce Bank National Association, as Agent, and Financial Institutions now or hereafter parties hereto (filed as Exhibit 10.13 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.14 -- First Amendment to Amended and Restated Credit Agreement, dated May 12, 1997, among Titan Resources, L.P., The Chase Manhattan Bank, as Administrative Agent, and Financial Institutions now or thereafter parties thereto (filed as Exhibit 10.13.1 to the Company's Form 10-Q for the quarterly period ended June 30, 1997 and incorporated herein by reference). 10.15 -- Form of Guaranty Agreement among The Chase Manhattan Bank, as Administrative Agent, Financial Institutions now or thereafter parties thereto and Titan Exploration, Inc., Titan Resources I, Inc. and Titan Resources Holdings, Inc. (filed as Exhibit 10.13.2 to the Company's Form 10-Q for the quarterly period ended June 30, 1997 and incorporated herein by reference). 10.16 -- Second Amendment to Amended and Restated Credit Agreement, dated May 12, 1997, effective as of April 1, 1997, by and among Titan Resources, L.P., The Chase Manhattan Bank, as Administrative Agent, and Financial Institutions now or thereafter parties thereto (filed as Exhibit 10.13.3 to the Company's Form 10-Q for the quarterly period ended September 30,
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Exhibit Number - --------- Description of Document 1997 and incorporated herein by reference). 10.17 -- Third Amendment to the Amended and Restated Credit Agreement, dated December 12, 1997, among Titan Resources, L.P., the Chase Manhattan Bank, as Administrative Agent and Financial Institutions now or thereafter parties thereto (filed as Exhibit 10 to the Company's Form 10-Q for the quarterly period ended June 30, 1998 and incorporated herein by reference. 10.18 -- Agreement of Sale and Purchase, dated April 19, 1995, between Enertex, Inc. and Titan Resources, L.P. (filed as Exhibit 10.14 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.19 -- Agreement of Sale and Purchase, dated April 19, 1995, between Staley Gas Co., Inc. and Titan Resources, L.P. (filed as Exhibit 10.15 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.20 -- Administrative Services Contract, dated March 31, 1995, between Staley Operating Co. and Titan Resources, L.P. (filed as Exhibit 10.16 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.21 -- Services Agreement, dated April 1, 1995, between Titan Resources I, Inc. and Titan Resources, L.P. (filed as Exhibit 10.17 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.22 -- Office Lease, dated April 10, 1997, between Fasken Center, Ltd. and Titan Exploration, Inc. (filed as Exhibit 10.17 to the Company's Registration Statement on Form S-4, Registration No. 333-40215 incorporated herein by reference). 10.23 -- Lease Amendment to the Lease Agreement dated April 4, 1997 between Fasken Center, LTD. and Titan Exploration, Inc. (filed as Exhibit 10.1 to the Company's Form 10-Q for the quarterly period ended September 30, 1998 and incorporated herein by reference). 10.24 -- Purchase and Sale Agreement, dated October 12, 1995, by and between Anadarko Petroleum Corporation and Titan Resources, L.P. (filed as Exhibit 10.19 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.25 -- Amendment No. 1 to Purchase and Sale Agreement, dated December 11, 1995, by and between Anadarko Petroleum Corporation and Titan Resources, L.P. (filed as Exhibit 10.20 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.26 -- Purchase and Sale Agreement, dated July 12, 1996, by and between Mobil Producing Texas & New Mexico Inc. and Titan Resources, L.P. (filed as Exhibit 10.21 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.27 -- Unit Purchase and Exchange Agreement, dated September 27, 1996, by and between Selma International Investment Limited and Titan Resources, L.P. (filed as Exhibit 10.22 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.28 -- Form of Indemnity Agreement between the Registrant and each of its executive officers (filed as Exhibit 10.23 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.29 -- Advisory Director Agreement, dated September 30, 1996, by and between Titan Exploration, Inc. and Joint Energy Development Investments Limited Partnership (filed as Exhibit 10.24 to the Company's Registration Statement on Form S-1, Registration No. 333-14029, and incorporated herein by reference). 10.30 -- Form of Stockholders Voting Agreement, dated November 6, 1997, between Titan
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Exhibit Number - --------- Description of Document Exploration, Inc. and the executive officers and directors of Offshore Energy Development Corporation (filed as Exhibit 10.24 to the Company's Registration Statement on S-4, Registration No. 333-40215, and incorporated herein by reference). 10.31 -- Stockholders Voting Agreement, dated November 6, 1997, between Titan Exploration, Inc. and Natural Gas Partners, L.P. (filed as Exhibit 10.25 to the Company's Registration Statement on S-4, Registration No. 333-40215, and incorporated herein by reference). 10.32 -- Master Promissory Note, dated March 6, 1997, between Titan Resources, L.P. and Chase Bank of Texas, National Association (filed as Exhibit 10 to the Company's Form 10-Q for the quarterly period ended March 31, 1998 and incorporated herein by reference). 10.33 -- Letter Agreement, dated November 6, 1997, among Titan Exploration, Inc. and certain stockholders of Titan Exploration, Inc. (filed as Exhibit 10.29 to the Company's Registration Statement on S-4, Registration No. 333-40215, and incorporated herein by reference). 10.34 -- Titan Matching Plan, effective as of September 1, 1998 (filed as Exhibit 10.2 to the Company's Form 10-Q for the quarterly period ended September 30, 1998 and incorporated herein by reference). 10.35 -- Amended and Restated Titan 401(k) Plan, effective as of September 1,1998. (filed as Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-62115, and incorporated herein by reference). 21 -- Subsidiaries of the Registrant. 23 -- Consent of independent auditors. 27 -- Financial Data Schedule.
(b) No reports on Form 8-K were filed by the Company during the last quarter of the period covered by this Annual Report on Form 10-K: 45 GLOSSARY OF OIL AND GAS TERMS The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Unless otherwise indicated in this report, natural gas volumes are stated at the legal pressure base of the state or area in which the reserves are located and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple. BOEs are determined using the ratio of six Mcf of natural gas to one Bbl of oil. "Bbl" means a barrel of 42 U.S. gallons of oil. "Bcf" means billion cubic feet of natural gas. "Bcfe" means billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. "BOE" means barrels of oil equivalent. "Completion" means the installation of permanent equipment for the production of oil or gas. "Development well" means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. "Exploratory well" means a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. "Gross," when used with respect to acres or wells, refers to the total acres or wells in which the Company has a working interest. "Horizontal drilling" means a drilling technique that permits the operator to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and can result in both increased production rates and greater ultimate recoveries of hydrocarbons. "MBbls" means thousands of barrels of oil. "Mcf" means thousand cubic feet of natural gas. "Mcfe" means 1,000 cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. "MMBbls" means millions of barrels of oil. "MMBOE" means millions of barrels of oil equivalent on a 6:1 basis. "MMcf" means million cubic feet of natural gas. "MMcfe" means million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. "Net," when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage working interest owned by the Company. "Net production" means production that is owned by the Company less royalties and production due others. "Oil" means crude oil or condensate. 46 "Operator" means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease. "Present Value of Future Revenues" or "PV-10" means the pretax present value of estimated future revenues to be generated from the production of proved reserves calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. "Proved developed reserves" means reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery will be included as "proved developed reserves" only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved. "Proved reserves" means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. i. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. ii. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. iii. Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids that may be recovered from oil shales, coal, gilsonite and other such sources. "Proved undeveloped reserves" means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir. "Recompletion" means the completion for production of an existing well bore in another formation from that in which the well has been previously completed. "Reserves" means proved reserves. 47 "Royalty" means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. "3-D seismic" means seismic data that are acquired and processed to yield a three-dimensional picture of the subsurface. "Tertiary recovery" means enhanced recovery methods for the production of oil or gas. Enhanced recovery of crude oil requires a means for displacing oil from the reservoir rock, modifying the properties of the fluids in the reservoir and/or the reservoir rock to cause movement of oil in an efficient manner, and providing the energy and drive mechanism to force its flow to a production well. The Company injects chemicals or energy as required for displacement and for the control of flow rate and flow pattern in the reservoir, and a fluid drive is provided to force the oil toward a production well. "Working interest" means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner's royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production. "Workover" means operations on a producing well to restore or increase production. 48 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, hereunder duly authorized, as of March 30, 1999. TITAN EXPLORATION, INC. Registrant By: /s/ Jack Hightower ----------------------------------------- Jack Hightower President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of March 30, 1999, by the following persons on behalf of the Registrant and in the capacity indicated. /s/ Jack Hightower - ------------------------------- Jack Hightower President of Directors, Chief Executive Officer and Chairman of the Board /s/ George G. Staley - ------------------------------- George G. Staley Executive Vice President, Exploration and Director /s/ William K. White - ------------------------------- William K. White Vice President, Finance and Chief Financial Officer /s/ David R. Albin - ------------------------------- David R. Albin Director /s/ Kenneth A. Hersh - ------------------------------- Kenneth A. Hersh Director /s/ William J. Vaughn, Jr. - ------------------------------- William J. Vaughn, Jr. Director 49 Index To Consolidated Financial Statements
Page ---- Consolidated Financial Statements of Titan Exploration, Inc. Independent Auditors' Report F-2 Consolidated Balance Sheets as of December 31, 1998 and 1997 F-3 Consolidated Statements of Operations for the years ended December 31, 1998, 1997 and 1996 F-4 Consolidated Statements of Stockholders' Equity and Predecessor Capital for the years ended December 31, 1998, 1997 and 1996 F-5 Consolidated Statements of Cash Flows for the years ended December 31, 1998, 1997 and 1996 F-6 Notes to Consolidated Financial Statements F-7
All schedules are omitted, as the required information is inapplicable or the information is presented in the financial statements or related notes. F-1 INDEPENDENT AUDITORS' REPORT The Board of Directors and Stockholders Titan Exploration, Inc. We have audited the consolidated financial statements of Titan Exploration, Inc. (the "Company") as listed in the accompanying index. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Titan Exploration, Inc. as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 1998, in conformity with generally accepted accounting principles. KPMG LLP Midland, Texas March 5, 1999 F-2 TITAN EXPLORATION, INC. Consolidated Balance Sheets (in thousands, except share data)
December 31, ------------------------ ASSETS 1998 1997 ---------- ----------- Current assets: Cash and cash equivalents $ 610 $ 1,603 Restricted investment - 2,331 Accounts receivable: Oil and gas 13,497 13,663 Other 761 2,900 Inventories 1,276 624 Assets held for sale 109,452 - Prepaid expenses and other current assets 316 531 -------- -------- Total current assets 125,912 21,652 -------- -------- Property, plant and equipment, at cost: Oil and gas properties, using the successful efforts method of accounting 306,111 366,105 Other property and equipment 6,340 2,421 Accumulated depletion, depreciation and amortization (98,095) (94,387) -------- -------- 214,356 274,139 Investments in affiliates and others - 55,900 Other assets, net of accumulated amortization of $639 in 1998 and $413 in 1997 754 892 -------- -------- $341,022 $352,583 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable and accrued liabilities: Trade $ 14,097 $ 16,421 Accrued interest 466 307 Other (Note 19) 5,652 4,896 -------- -------- Total current liabilities 20,215 21,624 -------- -------- Long-term debt 144,200 85,450 Other liabilities (Note 19) 5,253 2,720 Deferred income tax payable - 10,368 Stockholders' equity: Preferred Stock, $.01 par value, 10,000,000 shares authorized; none issued and outstanding - - Common Stock, $.01 par value, 60,000,000 shares authorized; 40,534,675 and 40,332,497 shares issued and outstanding at December 31, 1998 and 1997, respectively 405 403 Additional paid-in capital 278,109 277,500 Treasury stock, at cost; 2,600,000 and 55,000 shares at December 31, 1998 and 1997, respectively (20,020) (504) Deferred compensation (5,053) (10,108) Accumulated deficit (82,087) (34,870) -------- -------- Total stockholders' equity 171,354 232,421 -------- -------- Commitments and contingencies (Note 7) $341,022 $352,583 ======== ========
See accompanying notes to consolidated financial statements. F-3 TITAN EXPLORATION, INC. Consolidated Statements of Operations (in thousands, except share and per share data)
Year ended December 31, ----------------------------------- 1998 1997 1996 ---------- ---------- --------- Revenues: Gas sales $ 42,844 $ 38,715 $10,138 Oil sales 30,032 35,112 13,686 -------- -------- ------- Total revenues 72,876 73,827 23,824 -------- -------- ------- Expenses: Oil and gas production 27,078 16,298 7,312 Production and other taxes 5,725 5,548 1,887 General and administrative 9,163 5,372 2,270 Amortization of stock option awards 5,055 5,053 1,839 Exploration and abandonment (Note 20) 17,596 3,055 184 Depletion, depreciation and amortization 27,090 19,972 5,789 Impairment of long-lived assets 25,666 68,997 - Restructuring costs 625 - - -------- -------- ------- Total expenses 117,998 124,295 19,281 -------- -------- ------- Operating income (loss) (45,122) (50,468) 4,543 -------- -------- ------- Other income (expense): Interest income 125 190 424 Interest expense (8,648) (1,524) (2,965) Gain (loss) on sale of assets 923 58 (65) Management fees - affiliate 8 10 144 Equity in net loss of affiliates (458) - - Other 574 - - -------- -------- ------- Income (loss) before income taxes (52,598) (51,734) 2,081 -------- -------- ------- Income tax expense (benefit) (5,381) (18,267) 3,484 -------- -------- ------- Net loss $(47,217) $(33,467) $(1,403) ======== ======== ======= Net loss per common share $ (1.22) $ (.99) $ (.07) ======== ======== ======= Net loss per common share - assuming dilution $ (1.22) $ (.99) $ (.07) ======== ======== =======
See accompanying notes to consolidated financial statements. F-4 TITAN EXPLORATION, INC. Consolidated Statements of Stockholders' Equity and Predecessor Capital (in thousands)
Additional Total Predecessor Common Paid-in Treasury Deferred Accumulated Stockholders' Capital Stock Capital Stock Compensation Deficit Equity ------- ------ ------- ------ ------------ ------- ------ Balance, December 31, 1995 $ 37,081 $ - $ - $ - $ (2,496) $ - $ 34,585 Sale of interest in predecessor 5,000 - - - - - 5,000 September 30, 1996 stock plan - - 14,504 - (14,504) - - Common stock issued - 144 147,021 - - - 147,165 Deferred compensation - - - - 1,839 - 1,839 Net loss - - - - - (1,403) (1,403) Transfer of predecessor capital and issuance of common stock pursuant to the Offering (42,081) 195 41,886 - - - - -------- ----- --------- ---------- --------- --------- --------- Balance, December 31,1996 - 339 203,411 - (15,161) (1,403) 187,186 Stock options exercised - - 9 - - - 9 Tax benefit of stock options exercised - - 6 - - - 6 Common stock issued - - (41) - - - (41) Acquisitions for common stock - 64 74,115 - - - 74,179 Purchase of treasury stock - - - (504) - - (504) Deferred compensation - - - - 5,053 - 5,053 Net loss - - - - - (33,467) (33,467) -------- ----- --------- ---------- --------- --------- --------- Balance, December 31, 1997 - 403 277,500 (504) (10,108) (34,870) 232,421 Stock options exercised - 2 546 - - - 548 Tax benefit of stock options exercised - - 63 - - - 63 Purchase of treasury stock - - - (19,516) - - (19,516) Deferred compensation - - - - 5,055 - 5,055 Net loss - - - - - (47,217) (47,217) -------- ----- --------- ---------- --------- --------- --------- Balance, December 31, 1998 $ - $ 405 $ 278,109 $ (20,020) $ (5,053) $ (82,087) $ 171,354 ======== ===== ========= ========= ========= ========= =========
See accompanying notes to consolidated financial statements. F-5 TITAN EXPLORATION, INC. Consolidated Statements of Cash Flows (in thousands)
Year ended December 31, ------------------------------------ 1998 1997 1996 ---- ---- ---- Cash flows from operating activities: Net loss $ (47,217) $ (33,467) $ (1,403) Adjustments to reconcile net loss to net cash provided by operating activities: Depletion, depreciation and amortization 27,090 19,972 5,789 Impairment of long-lived assets 25,666 68,997 - Amortization of stock option awards 5,055 5,053 1,839 Dry holes and abandonments 14,118 1,053 21 (Gain) loss on sale of assets (923) (58) 65 Equity in net loss of affiliates 458 - - Deferred income taxes (5,381) (18,267) 3,484 Restructuring costs 625 - - Other items 672 - - Changes in assets and liabilities, excluding acquisitions: Decrease (increase) in accounts receivable 1,279 (1,595) (7,311) Increase in prepaid expenses and other current assets (445) (463) (145) Decrease (increase) in other assets 36 (96) (516) Increase (decrease) in accounts payable and accrued liabilities (2,585) 5,434 5,887 --------- --------- --------- Total adjustments 65,665 80,030 9,113 --------- --------- --------- Net cash provided by operating activities 18,448 46,563 7,710 --------- --------- --------- Cash flows from investing activities: Redemption of short-term investment 2,331 - 5,000 Investing in oil and gas properties (57,432) (112,301) (149,901) Payments for acquisitions, net of cash acquired (715) Additions to other property and equipment (3,919) (1,361) (218) Contributions in equity investments of affiliates (1,884) - - Proceeds from sale of assets 2,491 75 121 --------- --------- --------- Net cash used in investing activities (58,413) (114,302) (144,998) --------- --------- --------- Cash flows from financing activities: Proceeds from debt 60,100 63,588 - Payments of debt (1,350) - (13,500) Capital contributions - - 3,700 Proceeds from initial common stock offering - - 148,376 Direct costs of initial common stock offering - (41) (1,211) Exercise of stock options 548 9 - Purchase of treasury stock (19,516) (504) - Other financing activities (810) - - --------- --------- --------- Net cash provided by financing activities 38,972 63,052 137,365 --------- --------- --------- Net increase (decrease) in cash and cash equivalents (993) (4,687) 77 Cash and cash equivalents, beginning of year 1,603 6,290 6,213 --------- --------- --------- Cash and cash equivalents, end of year $ 610 $ 1,603 $ 6,290 ========= ========= =========
See accompanying notes to consolidated financial statements. F-6 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements December 31, 1998, 1997 and 1996 (1) Organization and Nature of Operations Titan Exploration, Inc. (the "Company") a Delaware corporation, was organized on September 27, 1996 and began operations on September 30, 1996 with the combination, pursuant to the terms of an Exchange Agreement and Plan of Reorganization (the "Exchange Agreement"), of Titan Resources I, Inc. (the "General Partner"), a Texas corporation, and Titan Resources, L.P. (the "Partnership"). Under the exchange agreement, the limited partners of the Partnership transferred all of their limited partnership interests to the Company in exchange for 19,318,199 shares of common stock, and the shareholders of the General Partner transferred all of the issued and outstanding stock of that corporation to the Company in exchange for an aggregate of 231,814 shares of common stock. These transactions are referred to as the "Conversion." Prior to the Conversion, the Company had no issued or outstanding shares of common stock and there was no public market for the General Partner's common stock. All shares of the Company issued in the Conversion were issued to the shareholders of the General Partner or to the limited partners of the Partnership. The combination of the Company, the General Partner and the Partnership is treated as a combination of entities under common control because of the 100% commonality of control between the Company subsequent to the Conversion and the Partnership prior to the Conversion. All partners of the Partnership were party to the exchange of shares in the Conversion. Consequently, the accompanying consolidated financial statements have given effect to the Conversion as if it were a pooling of interests. Revenues and costs arising from transactions between the two predecessor entities (the General Partner and the Partnership) have been eliminated. The following table sets forth revenues and net income with respect to the two predecessor entities (in thousands):
Year ended December 31, 1996 ---- Revenues: General Partner $ - Partnership 23,968 Intercompany eliminations - -------- $ 23,968 ======== Net income (loss): General Partner $ (66) Partnership 1,502 The Company (2,839) -------- $ (1,403) ========
(Continued) F-7 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements The Company is an independent energy company engaged primarily in the exploration, development and acquisition of oil and gas properties. Since its inception in March 1995, the Company has experienced significant growth, primarily through the acquisition of companies and oil and gas properties and the exploitation of these properties in the Permian Basin region of west Texas and southeastern New Mexico, Gulf Coast region and the Gulf of Mexico. (2) Summary of Significant Accounting Policies Principles of Consolidation The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. Investments in corporate joint ventures and partnerships where the Company has ownership interest of 50% or less are accounted for on the equity method. All investments with an ownership interest of less than 20% and no significant control are accounted for on the cost method. All material intercompany accounts and transactions have been eliminated in the consolidation. Use of Estimates in the Preparation of Financial Statements Preparation of the accompanying consolidated 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 at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Cash and Cash Equivalents For purposes of the statements of cash flows, the Company considers all demand deposits, money market accounts and certificates of deposit purchased with an original maturity of three months or less to be cash equivalents. Inventories Inventories consist of lease and well equipment not currently being used in production and are accounted for at the lower of cost (first-in, first-out) or market. Oil and Gas Properties The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all costs associated with productive wells and nonproductive development wells are capitalized. Exploration costs are capitalized pending determination of whether proved reserves have been found. If no proved reserves are found, previously capitalized exploration costs are charged to expense. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until such time as the related project is developed and proved reserves are established or impairment is determined. The Company capitalizes interest on expenditures for significant development projects until such time as significant operations commence. (Continued) F-8 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Sales proceeds from sales of individual properties are credited to property costs. No gain or loss is recognized until the entire amortization base is sold or abandoned. Other property and equipment are recorded at cost. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to operating expenses in the period incurred. With respect to dispositions of assets other than oil and gas properties, the cost of assets retired or otherwise disposed of, and the applicable accumulated depreciation are removed from the accounts, and the resulting gains or losses, if any, are reflected in operations. Depletion, Depreciation and Amortization Provision for depletion of oil and gas properties is calculated using the unit-of-production method on the basis of an aggregation of properties with a common geologic structural feature or stratigraphic condition, typically a field or reservoir. In addition, estimated costs of future dismantlement, restoration and abandonment, if any, are accrued as a part of depletion, depreciation and amortization expense on a unit of production basis; actual costs are charged to the accrual. Other property and equipment is depreciated using the straight- line method over the estimated useful lives of the assets. Organization costs are amortized over five years, while loan costs are amortized over the life of the related loan. Impairment of Long-Lived Assets The Company follows the provisions of Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" ("FAS 121"). Consequently, the Company reviews its long-lived assets to be held and used, including oil and gas properties accounted for under the successful efforts method of accounting and other identifiable intangible assets, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, on a depletable unit basis, is less than the carrying amount of such assets. In this circumstance, the Company recognizes an impairment loss for the amount by which the carrying amount of the asset exceeds the fair value of the asset. The Company accounts for long-lived assets to be disposed of at the lower of their carrying amount or fair value less cost to sell once management has committed to a plan to dispose of the assets. Net Income (Loss) per Common Share In 1997, the Financial Accounting Standards Board issued Statement No. 128, "Earnings per Share" ("FAS 128"). FAS 128 replaced the calculation of primary and fully diluted earnings per share with basic and diluted earnings per share. Unlike primary earnings per share, basic earnings per share excludes any dilutive effects of options, warrants and convertible securities. Diluted earnings per share is very similar to the previously reported fully diluted earnings per share. All earnings per share amounts for all periods have been presented, and when appropriate, restated to conform to the FAS 128 requirements. For the periods prior to the Offering, the weighted average shares outstanding attributable to predecessor capital are the shares issued to the predecessor members upon Conversion. (Continued) F-9 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements Income Taxes The Company follows the provisions of Financial Accounting Standards No. 109, "Accounting for Income Taxes" ("FAS 109"). Under the asset and liability method of FAS 109, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. Under FAS 109, the effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. Upon Conversion, the Company recorded the tax effect of the differences between the book and tax basis of its assets and liabilities as a deferred tax liability and a corresponding charge to deferred income tax expense. Environmental The Company is subject to extensive federal, state and local environmental laws and regulations. These laws, which are constantly changing, regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and/or remediation is probable, and the costs can be reasonably estimated. Revenue Recognition The Company uses the sales method of accounting for crude oil revenues. Under this method, revenues are recognized based on actual volumes of oil sold to purchasers. The Company uses the entitlements method of accounting for natural gas revenues. Under this method, revenues are recognized based on the Company's proportionate share of actual sales of natural gas. Natural gas revenues would not have been significantly altered in any period had the sales method of recognizing natural gas revenues been utilized. The Company has a net liability of approximately $225,000 and a net asset of approximately $318,000 at December 31, 1998 and December 31, 1997, respectively, associated with gas balancing recorded. The Company recognizes marketing revenue net of the cost of gas and third- party delivery fees as service is provided. Stock-based Compensation The Company accounts for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" ("APB 25"). Accordingly, the Company has only adopted the disclosure provisions of Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"). See Note 13 for the pro forma disclosures of compensation expense determined under the fair-value provisions of FAS 123. (Continued) F-10 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements Treasury Stock Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held. Commodity Hedging The financial instruments that the Company accounts for as hedging contracts must meet the following criteria: the underlying asset or liability must expose the Company to price or interest rate risk that is not offset in another asset or liability, the hedging contract must reduce that price or interest rate risk at the inception of the contract and throughout the contract period, and the instrument must be designated as a hedge. In order to qualify as a hedge, there must be clear correlation between changes in the fair value of the financial instrument and the fair value of the underlying asset or liability such that changes in the market value of the financial instrument will be offset by the effect of price or interest rate changes on the exposed items. The Company periodically enters into commodity derivative contracts in order to hedge the effect of price changes on commodities the Company produces and sells. Gains and losses on contracts that are designed to hedge commodities are included in income recognized from the sale of those commodities. Gains and losses on derivative contracts which do not qualify as hedges are recognized in each period based on the market value of the related instrument. Interest Rate Swap Agreements The Company enters into interest rate swap agreements to effectively convert a portion of its floating-rate borrowings into fixed rate obligations. The interest rate differential to be received or paid is recognized over the lives of the agreements as an adjustment to interest expense. At December 31, 1998, the Company was not subject to any interest rate swap agreements. Reclassifications Certain reclassifications have been made to the 1997 and 1996 amounts to conform to the 1998 presentation. (Continued) F-11 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (3) Disclosures About Fair Value of Financial Instruments The following table presents the carrying amounts and estimated fair values of the Company's financial instruments (in thousands):
December 31, --------------------------------------------------------------------- 1998 1997 ------------------------------ ------------------------------ Carrying Fair Carrying Fair Amount Value Amount Value ------ ----- ------ ----- Financial assets: Cash and cash equivalents $ 610 $ 610 $ 1,603 $ 1,603 Restricted investments - - 2,331 2,331 Financial liabilities: Debt: Line of credit 140,000 140,000 84,100 84,100 Unsecured line of credit 4,200 4,200 - - Other - - 1,350 1,350 Off-balance sheet financial instruments (see Note 17): Commodity price hedges - 1,673 - 1,683
Cash and cash equivalents, restricted cash, accounts receivable, other current assets, accounts payable and other current liabilities. The carrying amounts approximate fair value due to the short maturity of these instruments. Restricted investments. The fair value of noncurrent investments is based on quoted market prices. Debt. The carrying amount of long-term debt approximates fair value because the Company's current borrowing rate does not materially differ from market rates for similar bank borrowings. Commodity price hedges. The fair market values of commodity derivative instruments are estimated based upon the current market price of the respective commodities at the date of valuation. It represents the amount which the Company would be required to pay or able to receive based upon the differential between a fixed and a variable commodity price as specified in the hedge contracts. (Continued) F-12 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (4) Debt Debt consists of the following (in thousands):
December 31, ------------------------------- 1998 1997 ---- ---- Line of credit $ 140,000 $ 84,100 Unsecured line of credit 4,200 - Other - 1,350 --------- -------- $ 144,200 $ 85,450 ========= ========
Line of Credit On October 31, 1996, the Company entered into a credit agreement, as amended, (the "Credit Agreement") with Chase Manhattan Bank, N.A. which establishes a four year revolving credit facility, up to the maximum amount of $250 million subject to a borrowing base. All amounts outstanding are due and payable in full by January 1, 2001. The borrowing base, which was $200 million at December 31, 1998, is subject to redetermination semiannually by the lenders based on certain proved oil and gas reserves and other assets of the Company with the next redetermination date scheduled for April 1, 1999. The Credit Agreement, which is secured by a majority of the Company's proved oil and gas reserves, is subject to mandatory prepayments. To the extent that the borrowing base is less than the aggregate principal amount of all outstanding loans and letters of credit under the Credit Agreement, such deficiency must be cured by the Company within 180 days, by either prepaying a portion of the outstanding amounts or pledging additional collateral. Commitment fees are due quarterly and range from .300% to .375% per annum on the difference between the commitment and the average daily amount outstanding. At the Company's option, borrowings under the Credit Agreement bear interest at either (i) the "Base Rate" (i.e. the higher of the agent's prime commercial lending rate, or the federal funds rate plus .50% per annum), or (ii) the Eurodollar rate plus a margin ranging from 1.00% to 1.50% per annum, which margin increases as the level of the Company's aggregate outstanding borrowings under the Credit Agreement increases. The interest rates in effect at December 31, 1998 ranged from 7.063% to 7.750%. The credit agreement contains various restrictive covenants and compliance requirements, which include (1) limiting the incurrence of additional indebtedness, (2) restrictions as to merger, sale or transfer of assets and transactions with affiliates without the lenders' consent, and (3) prohibition of any return of capital payments or distributions to any of its partners other than for taxes due as a result of their partnership interest. At December 31, 1998, the Company was not in compliance with a coverage test required by the Credit Agreement. The Company has requested and received written consents from its banks to amend this coverage test of the Credit Agreement, and the Company believes this amendment will be fully documented on or before April 30, 1999. The Company believes it will be able to comply with the amended covenants of the Credit Agreement for the foreseeable future. (Continued) F-13 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements Unsecured Credit Agreement In April 1997, the Company entered into a credit agreement, as amended, (the "Unsecured Credit Agreement") with Chase Bank of Texas, N.A. (the "Bank"), an affiliate of Chase Manhattan Bank, N.A., which establishes a revolving credit facility, up to the maximum of $5 million. All outstanding amounts pursuant to the Unsecured Credit Agreement are due and payable in full on or before December 31, 1999. The interest rate of each loan under the Unsecured Credit Agreement is at a rate determined by agreement between the Company and the Bank. The rate shall not exceed the maximum interest rate permitted under applicable laws. Interest rates generally are at the bank's cost of funds plus 1% per annum. Maturities of debt are as follows (in thousands):
1998 $ - 1999 - 2000 - 2001 144,200 2002 -
(5) Acquisitions On December 12, 1997, the Company completed the acquisitions of all the outstanding stock of Offshore Energy Development Corporation ("OEDC") and Carrollton Resources, L.L.C. ("Carrollton"). The acquisitions were made by the issuance of 5,486,734 and 899,965 shares of the Company's common stock to the stockholders of OEDC and Carrollton, respectively. The results of operations of OEDC and Carrollton from the closing date are not included in the Company's 1997 results of operations as the acquisitions closed in late December 1997, and the amounts are not material. The acquisitions, accounted for on the purchase method, resulted in the following noncash investing activities:
OEDC Carrollton ---- ---------- (in thousands) Recorded amount of assets acquired $ 104,312 $ 19,820 Liabilities assumed (27,102) (2,243) Deferred income tax liability (13,815) (6,078) Common stock issued (62,849) (11,330) --------- --------- Cash costs, net of cash acquired $ 546 $ 169 ========= =========
The liabilities assumed include amounts recorded for preacquisition contingencies and bank debt of OEDC and Carrollton. (Continued) F-14 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements On December 16, 1997, the Company completed the acquisition of certain oil and gas properties from Pioneer Natural Resources Company (the "Pioneer Acquisition"). The Company funded the acquisition from its debt facilities. The results of operations from the Pioneer Acquisition from the closing date are not included in the Company's 1997 results of operations as the amounts are not material. The acquisition of these oil and gas properties, accounted for using the purchase method, resulted in the following noncash investing activities: Recorded amount of assets acquired, including receivables of $2,589,817 $ 55,794,243 Liabilities assumed (1,061,330) ------------ Cash paid $ 54,732,913 ============
Included in assets recorded is a $53,919 long-term receivable recorded as a purchase price adjustment related to the Pioneer Acquisition for a gas imbalance receivable. On October 31, 1996, the Company completed the acquisition of certain oil and gas properties from a major integrated company (the "1996 Acquisition"). The Company funded the acquisition from its debt facilities. The acquisition of these oil and gas properties, accounted for using the purchase method, resulted in the following noncash investing activities: Recorded amount of assets acquired, including receivables of $300,187 $ 135,983,556 Liabilities assumed (1,570,490) ------------- Cash paid $ 134,413,066 =============
Included in receivables assumed is a $300,187 long-term receivable recorded as a purchase price adjustment related to the 1996 Acquisition for a gas imbalance. It is shown net of other gas imbalance liabilities in the consolidated financial statements. Liabilities assumed are amounts recorded as purchase price adjustments related to the 1996 Acquisition for potential environmental remediation. On December 11, 1995, the Company completed the acquisition of certain oil and gas properties from a large independent oil and gas company (the "1995 Acquisition"). The Company funded the acquisition from its debt facilities. The total consideration paid for the properties was $39,881,094. The acquisition of these oil and gas properties, accounted for using the purchase method, resulted in the following noncash investing activities: Recorded amount of assets acquired, including receivables of $396,719 $ 40,992,065 Liabilities assumed (1,110,971) ------------ Cash paid $ 39,881,094 ============
Included in liabilities assumed is a $963,898 long-term liability recorded as a purchase price adjustment related to the 1995 Acquisition for a gas imbalance liability. Pro Forma Results of Operations (Unaudited) The following table reflects the pro forma results of operations for the years ended December 31, 1997 and 1996 as though the 1996 Acquisition, the Pioneer Acquisition and the OEDC and Carrollton acquisitions had (Continued) F-15 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements occurred as of January 1, 1996 and as if the Conversion had taken place on January 1, 1996. The pro forma amounts are not necessarily indicative of the results that may be reported in the future (in thousands).
Year ended December 31, --------------------------------- 1997 1996 ---- ---- Revenues $ 105,016 $ 102,975 Net income (loss) (40,897) 17,125 Net income (loss) per common share (1.01) .43 Net income (loss) per common share - assuming dilution (1.01) .41
(6) Investments Dauphin Island Gathering Partners The Company has a one percent investment in Dauphin Island Gathering Partners ("DIGP"), which owns a natural gas gathering system in the Gulf of Mexico, that is accounted for using the equity method. The Company's investment in DIGP is the result of the acquisition of OEDC. The Company has been delegated, by the operator of DIGP, to manage the commercial development and construction activities of DIGP through November 1999, and the Company will be paid $22,910 per month plus .5% of all construction costs of DIGP. The Company's interest in DIGP will increase up to a maximum of 11.15% when its DIGP partners receive the return of their investment plus a 10% rate of return, subject to certain other conditions. The Company's cost basis in DIGP exceeds the underlying historical net assets of DIGP by approximately $18,333,000 at December 31, 1998. The excess basis will be amortized over 30 years and included in the equity loss in net loss from DIGP. The Company received distributions from DIGP of $275,433 in 1998. Mobile Bay Processing Partners The Company owns a .86% general partnership interest in Mobile Bay Processing Partners ("MBPP") which was formed for the purpose of constructing, owning and operating, or providing financing for one or more natural gas processing facilities onshore in Mobile County, Alabama. The Company's investment in MBPP is the result of the acquisition of OEDC. The Company accounts for its investment in MBPP on the equity method. According to estimates of the managing partner of MBPP the operations of the plant is expected to commence in the first quarter of 1999. The Company has an option to buy up to an additional 27.9% interest in MBPP, exercisable until the third anniversary of the commencement of commercial operations at MBPP's initial processing facility. The costs of the additional partnership interest will be equal to the historical book value of the plant reduced for depreciation on the date the option is exercised and increased by 12% per year. The Company's cost basis in MBPP exceeds the underlying historical net assets of MBPP by approximately $32,591,000 at December 31, 1998. The excess basis will be amortized over 25 years, upon commencement of the first operations of MBPP, and included in the equity loss in net loss from MBPP. (Continued) F-16 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements Other The Company has a 13.33% limited partnership interest in Asia-Pacific Refinery Investment, L.P. ("APRI"), which is carried at cost. APRI is involved in the construction and operation of a refinery unit. The Company has no responsibility to provide additional funds to APRI. In 1998, the Company impaired its investment in APRI, see Note 18. (7) Commitments and Contingencies Operating Leases The Company has non-cancelable operating leases for office facilities and certain major production equipment. The Company's non-cancellable operating lease for its Midland, Texas offices is with an entity controlled by an officer of the Company. Future minimum lease commitments under non-cancellable operating leases at December 31, 1998 are as follows (in thousands):
Total Affiliate ------ --------- 1999 $ 933 $ 433 2000 433 433 2001 433 433 2002 90 90 2003 - -
Lease expense during 1998, 1997 and 1996 was $962,986, $200,474 and $110,625, respectively. In 1998, $412,056 of the lease expense was associated with compressors and recorded as production costs. Lease expense incurred with an affiliate during 1998, 1997 and 1996 was $419,704, $200,474 and $110,625, respectively. Litigation The following is a brief description of certain litigation to which the Company is subject, as a result of assuming the obligations of Offshore Energy Development Corporation ("OEDC"). The Company believes it has meritorious defenses to the claims and intends to vigorously defend against such claims. The Company does not believe that it has a probable and estimable loss with respect to any such litigation in excess of currently provided reserves, if any. If such loss becomes probable and estimable, the amount of any recorded liability could have a material adverse effect on the Company's (i) results of operations for the period in which such liability is recorded, (ii) consolidated financial position as a whole and (iii) liquidity and capital resources. However, the Company does not expect that any such liability will have a material adverse effect on its consolidated financial position as a whole or on its liquidity or capital resources. Due to the uncertainties inherent in litigation, no assurance can be given to the ultimate outcome of these matters. OEDC and certain of its officers and directors, as well as Natural Gas Partners, L.P. ("NGP"), the managing underwriters of OEDC's initial public offering and an analyst from each of the managing underwriters, have been named as defendants in a suit styled Eric Baron and Edward C. Allen, on behalf of Themselves and all Others Similarly Situated, v. David B. Strassner, Douglas H. Kiesewetter, David R. Albin, Natural Gas Partners, L.P., David Garcia, John J. Myers, Offshore Energy Development Corporation, Morgan Keegan & Company, Inc. and Principal Securities Inc., which was filed October 20, 1997, in the Texas State District Court of Harris County, (Continued) F-17 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements Southern District of Texas. Plaintiffs motion to have the case remanded to the state court was granted by the federal judge in April 1998. The suit seeks class certification on behalf of certain holders of common stock of denied class certification at this time, in deference to a parallel federal court action, which is described below. The suit alleges generally that the defendants wrongfully made false or misleading statements or omissions relating to OEDC's business and prospects in the course of OEDC's initial public offering and subsequent thereto. The state court suit seeks rescission of sales of common stock of OEDC and unspecified monetary damages, including punitive damages. OEDC and certain of its officers and directors, as well as NGP, have also been named defendants in a suit styled John W. Robertson, et al. v. David B. Strassner, Douglas H. Kiesewetter, David R. Albin, Natural Gas Partners, L.P. and Offshore Energy Development Corporation, which was filed February 6, 1998, in the United States Southern District of Texas, Houston Division. This suit mirrors the allegations of the foregoing matter, but adds request for relief under federal securities laws. It, too, seeks certification of a class of certain purchasers of common stock OEDC. The suit seeks compensatory damages, including rescissory damages, where applicable. Discovery on the two previously discussed cases has commenced. A mediation hearing, of all parties, has been set for April 20, 1999. The Company is involved in other various claims and legal actions arising in the ordinary course of business. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company's financial position, results of operations or liquidity. Letters of Credit At December 31, 1998, the Company had outstanding letters of credit of $144,000, which are issued through the Credit Agreement. (8) Statements of Cash Flows Interest expense of $8,489,059, $1,524,576 and $3,062,656 was paid in 1998, 1997 and 1996, respectively. In 1998, the Company acquired oil and gas properties by assuming the underlying plugging obligations. The salvage value of the equipment and platforms exceeded the estimated plugging obligations. The Company recorded no basis in the oil and gas properties associated with this transaction. In 1998, the Company executed a like-kind exchange of oil and gas properties of which the Company's net basis in the property exchange was approximately $6,042,000. During 1996, a $1,300,000 noncash contribution of interests in oil and gas properties was made in exchange for interest in the Company. Also at December 31, 1996, a $341,250 noncash property addition was recorded as a purchase price adjustment related to the Conversion. (Continued) F-18 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (9) Restricted Investments The Company carries a $3.0 million Gulf of Mexico area-wide abandonment bond with the Minerals Management Service, which is secured by cash balances currently invested in certificates of deposit at a commercial bank. The sum on deposit related to this area-wide abandonment bond was approximately $2.3 million at December 31, 1997. The deposit was released to the Company in 1998. (10) Common Stock On December 16, 1996, the Company completed an initial public offering (the "Offering") of 14,391,500 shares of common stock at a price of $11.00 per share. Proceeds received, net of related expenses, were approximately $148,376,365. In May 1997, the Company announced a plan to repurchase up to $25 million of the Company's common stock. The repurchase will be made periodically, depending on market conditions, and will be funded with cash flow from operations and, as necessary, borrowings under the Credit Agreement. At December 31, 1998, the Company had purchased 2,600,000 shares of its common stock for approximately $20 million. (11) Income Taxes Upon Conversion, the Company became a tax paying entity for U.S. federal income tax purposes. At the date of Conversion, the book basis of the Company's assets and liabilities exceeded the tax basis by approximately $8,566,000, resulting in a deferred tax liability of approximately $2,998,000. Total income tax expense was allocated as follows:
Year ended December 31, -------------------------------------------------- 1998 1997 1996 ---- ---- ---- Income (loss) from continuing operations $ (5,381) $ (18,267) $ 3,484 Stockholders' equity for compensation expense for tax purposes in excess of amounts recognized for financial reporting purposes (63) (6) - -------- --------- ------- $ (5,444) $ (18,273) $ 3,484 ======== ========= =======
(Continued) F-19 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements The reconciliation between the tax expense computed by multiplying pretax income (loss) by the U.S. federal statutory rate and the reporting amounts of income tax expense (benefit) is as follows:
Year ended December 31, ---------------------------------------------------- 1998 1997 1996 ---- ---- ---- (in thousands) Income (loss) at statutory rate $ (18,409) $ (18,107) $ 728 Change in the deferred tax assets valuation allowance 14,001 - - Operations of related partnerships taxable to the respective partners, prior to the Conversion - - (242) Deferred income tax expense to record difference between book and tax basis of net assets upon Conversion - - 2,998 State income taxes, net of federal benefit (373) (167) - Other (600) 7 - --------- --------- ------- Income tax expense (benefit) $ (5,381) $ (18,267) $ 3,484 ========= ========= =======
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows:
December 31, ------------------------------- 1998 1997 ---- ---- (in thousands) Deferred tax assets (liabilities): Net operating loss $ 30,353 $ 12,953 Compensation, principally due to accrual for financial reporting purposes 3,883 2,405 Property, plant and equipment, principally due to differences in basis upon acquisition, depletion, impairment, and the deduction of intangible drilling costs for tax purposes (4,249) (6,548) Investments in affiliates (18,027) (19,178) Other 2,041 - -------- --------- Net deferred tax asset (liability) 14,001 (10,368) Valuation allowance of deferred tax assets (14,001) - -------- --------- Net deferred tax asset (liability), net of valuation allowance $ - $(10,368) ======== =========
A valuation allowance is provided when it is more likely than not that some portion of the deferred tax assets will not be realized. Due to uncertainties arising from a lack of earnings history and based on management's intention to continue its drilling program (generating intangible drilling costs which are projected to create future (Continued) F-20 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements losses for tax purposes), it does not appear more likely than not that the Company will be able to utilize all the available carryforwards prior to their ultimate expiration. At December 31, 1998, the Company had net operating loss carryforwards ("NOLs") for U.S. federal income tax purposes of approximately $86,400,000, which are available to offset future regular taxable income, if any. Of the Company's NOLs, approximately $15,100,000 related to pre-acquisition NOLs which are subject to annual limitations on their utilization. The carryforwards begin to expire in 2011. (12) Related Party Transactions During 1998, 1997 and 1996, the Company received $7,536, $9,656 and $144,167, respectively, for administrative services from a related party. Financial advisory service fees of $185,854 were paid to two shareholders during 1996. For the period March 31, 1995 (date of inception) through December 31, 1996, $428,958 were paid to two shareholders and two affiliates of shareholders. The contracts underlying the financial advisory service fees were terminated on December 16, 1996 pursuant to the contracts. Director's fees of $45,000, $45,000 and $10,000 were incurred during 1998, 1997 and 1996, respectively. Certain properties that were owned or controlled by certain shareholders were acquired by the Company for $100,000 and $21,708 in 1997 and 1996, respectively, which approximates the predecessor cost of the properties. During 1998, 1997 and 1996, the Company received (paid) approximately $2,232,000, $551,000 and ($635,000) from (to) Enron Capital and Trade Corp., an affiliate of a significant stockholder of the Company relating to financial instruments associated, primarily, with the Company's hedging activities. The Company uses certain aircraft and receives services from an entity owned by an affiliate. The Company is billed for use of such aircraft and related services by the Company. Payments made for the use of such aircraft and related services were $279, $3,371 and $17,348 for the years ended December 31, 1998, 1997 and 1996, respectively. The President, Chief Executive Officer and Chairman of the Board of the Company, and certain of his affiliates have a common ownership interest in oil and gas properties that are operated by the Company and, in accordance with a standard industry operating agreement, make payments to the Company of leasehold costs and lease operating and supervision charges. These payments were approximately $43,019, $88,473 and $229,332 in 1998, 1997 and 1996, respectively. Revenue received in connection with these oil and gas properties was $12,350, $16,098 and $6,868 in 1998, 1997 and 1996, respectively. These interests were owned by the Chief Executive Officer and his affiliates prior to the formation of the Company on March 31, 1995. During 1998, the Company received fees of $275,000 for managing the commercial and construction operations of DIGP. (Continued) F-21 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (13) Company Option Plans Stock Option Plan Prior to the consolidation of Titan Exploration, Inc., Titan Resources, L.P. established a unit option plan (the "Plan") for certain officers and key employees of the Partnership and the General Partner. On September 30, 1996, upon the consolidation of Titan Exploration, Inc., the Plan was replaced by a new stock option plan the ("Stock Plan"). The Stock Plan provides for the issuance of 3,631,350 options to acquire common stock of the Company, in four separate series with a fixed exercise price of $2.08. Option A series, covering 2,410,728 shares of common stock, was to vest at a rate of one-third of the options at each of the dates of March 31, 1996, 1997 and 1998; Option B, C, and D series cover 387,265, 406,390, and 426,967 shares of common stock, respectively. Options B, C and D series each vest on March 31, 1997, 1998 and 1999, respectively. Deferred compensation was recorded based on the value of the Company's common stock on September 30, 1996, and will be amortized to expense over a 39 month period. Deferred compensation of approximately $17,576,000 (before reduction by amounts previously amortized to expense under the Plan, as described above) was recorded at September 30, 1996. At December 31, 1998, unamortized deferred compensation was $5,053,467. 1996 Incentive Plan The Board of Directors and the stockholders of the Company approved the adoption of the Company's 1996 Incentive Plan (the "1996 Incentive Plan") as of October 1, 1996. The purpose of the 1996 Incentive Plan is to reward selected officers and key employees of the Company and others who have been or may be in a position to benefit the Company, compensate them for making significant contributions to the success of the Company and provide them with a proprietary interest in the growth and performance of the Company. Participants in the 1996 Incentive Plan are selected by the Board of Directors or such committee of the Board as is designated by the Board to administer the 1996 Incentive Plan (the Compensation Committee of the Board of Directors) from among those who hold positions of responsibility with the Company and whose performance, in the judgment of the Compensation Committee, can have a significant effect on the success of the Company. An aggregate of 850,000 shares of Common Stock have been authorized and reserved for issuance pursuant to the 1996 Incentive Plan. These options vest ratably on each of the first through fourth anniversaries of the grant date. In November 1998, 105,000 stock options of an officer, with a weighted average exercise price of $11.12 per share, were cancelled. The officer received 200,000 new stock options at an exercise price of $6.25 per share. The vesting of the new options is ratable over a four-year period from date of grant. Subject to the provisions of the 1996 Incentive Plan, the Compensation Committee will be authorized to determine the type or types of awards made to each participant and the terms, conditions and limitations applicable to each award. In addition, the Compensation Committee will have the exclusive power to interpret the 1996 Incentive Plan and to adopt such rules and regulations as it may deem necessary or appropriate in keeping with the objectives of the 1996 Incentive Plan. Pursuant to the 1996 Incentive Plan, participants will be eligible to receive awards consisting of (i) stock options, (ii) stock appreciation rights, (iii) stock, (iv) restricted stock, (v) cash or (vi) any combination of the foregoing. Stock options may be either incentive stock options within the meaning of Section 422 of the Internal Revenue Code of 1986, as amended, or nonqualified stock options. (Continued) F-22 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements OEDC Stock Awards Plan Pursuant to the OEDC merger agreement, the Company converted the outstanding stock options of OEDC to stock options of the Company at the agreed common stock exchange rate. At the date of the OEDC merger, there were 118,175 and 340,200 options to purchase shares of the Company common stock at $5.73 and $19.05 per share, respectively, and all options were exercisable. The Company applies APB 25 and related interpretations in accounting for its stock option plans. If compensation expense for the stock option plans had been determined in a manner consistent with Statement of Financial Accounting Standards 123, "Accounting for Stock-Based Compensation ("FAS 123"), the Company's net loss and net loss per share would have been adjusted to the pro forma amounts indicated below:
For the year ended December 31, ---------------------------------------------------------- 1998 1997 1996 ---- ---- ---- (in thousands, except per share amounts) Net loss $ (46,314) $ (39,676) $ (2,959) Net loss per common share (1.19) (1.17) (.15) Net loss per share - assuming dilution (1.19) (1.17) (.15)
The pro forma net loss and pro forma net loss per share amounts noted above are not likely to be representative of the pro forma amounts to be reported in future years. The pro forma amounts for 1996 reflect the initial phase-in of FAS 123. Pro forma adjustments in future years will include compensation expense associated with the options granted in 1998, 1997 and 1996 plus compensation expense associated with any options awarded in future years. As a result, such pro forma compensation expense is likely to be higher than the levels experienced in 1998, 1997 and 1996. Under FAS 123, the fair value of each stock option grant is estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions used for grants in 1998, 1997 and 1996:
1998 1997 1996 ---- ---- ---- Risk-free interest rate 4.50% 5.25% 6.15% Expected life 4.0 7.0 3.0 Expected volatility 48% 46% 52% Expected dividend yield - - -
(Continued) F-23 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements A summary of the Company's stock option plans as of December 31, 1998, 1997 and 1996, and changes during the periods ended on those dates is presented below:
Year ended Year ended Year ended December 31, 1998 December 31, 1997 December 31, 1996 ----------------------- ---------------------- ----------------------- Weighted Weighted Weighted Number Average Number Average Number Average of Shares Price of Shares Price of Shares Price ------------ -------- ------------ -------- ------------- -------- Stock options: Outstanding at beginning of year 4,429,440 $ 4.15 3,716,350 $ 2.28 3,387,674 $ 1.50 Options granted - initial plan - - - - 243,676 $ 1.50 Options canceled/forfeited (356,614) $ 15.51 - - (3,631,350) $ 1.50 OEDC options assumed - - 458,375 $ 15.61 - - Options exercised (202,178) $ 2.71 (4,285) $ 2.08 - - Options granted 389,499 $ 8.19 259,000 $ 10.95 3,716,350 $ 2.28 ----------- ----------- ------------ Outstanding at end of year 4,260,147 $ 3.64 4,429,440 $ 4.15 3,716,350 $ 2.28 =========== =========== ============ Exercisable at end of year 3,339,117 $ 3.09 2,470,133 $ 4.72 803,576 $ 2.08 =========== =========== ============ Weighted average fair value of options granted during the year $ 11.33 $ 10.95 $ 5.27 =========== =========== ============
Options outstanding as of December 31, 1998 have expected lives ranging from 2 to 9 years with exercise prices ranging from $2.08 to $19.05 per share. (Continued) F-24 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (14) Net Loss per Common Share The following table sets forth the computation of basic and diluted net loss per common share:
Year ended December 31, ------------------------------------------------------ 1998 1997 1996 ---- ---- ---- (in thousands) Numerator: Net loss and numerator for basic and diluted net loss per common share - income available to common stockholders $ (47,217) $ (33,467) $ (1,403) ========= ========= ======== Denominator: Denominator for basic net loss per common share - weighted average common shares 38,808 33,942 19,605 Effect of dilutive securities - employee stock options - - - --------- --------- -------- Denominator for diluted net loss per common share - adjusted weighted average common shares and assumed conversions 38,808 33,942 19,605 ========= ========= ======== Basic net loss per common share $ (1.22) $ (.99) $ (.07) ========= ========= ======== Diluted net loss per common share $ (1.22) $ (.99) $ (.07) ========= ========= ========
Employee stock options to purchase 4,260,147, 4,429,440 and 3,716,350 shares of common stock were outstanding during 1998, 1997 and 1996, respectively, but were not included in the computation of diluted net loss per common share because either (i) the employee stock options' exercise price was greater than the average market price of the common stock of the Company or (ii) the Company had a loss from continuing operations; and, therefore, the effect would be antidilutive. (Continued) F-25 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (15) 401(k) Plan The Company has established a qualified cash or deferred arrangement under IRS code section 401(k) covering substantially all employees. Under the plan, the employees have an option to make elective contributions of a portion of their eligible compensation, not to exceed specified annual limitations, to the plan and the Company has an option to match a portion of the employee's contribution. The Company has made matching contributions to the plan totaling $632,883, $110,981 and $23,034 in 1998, 1997 and 1996, respectively. (16) Major Customers The following purchasers accounted for 10% or more of the Company's oil and gas sales:
1998 1997 1996 ---- ---- ---- Purchaser A (a) 31% 36% 43% Purchaser B 13% 12% 7% Purchaser C 13% 9% -%
- -------------------------------- (a) Purchaser A is an affiliate of Enron Corp., a significant stockholder of the Company. (17) Derivative Financial Instruments The Company utilizes various swap contracts and other financial instruments to hedge the effect of price changes on future gas production. The following table sets forth the future volumes hedged by year and the range of prices to be received based upon the fixed price of the individual swap contracts and other financial instruments outstanding at December 31, 1998:
Gas Volume Price per Year (MMcf) Mcf ---- ------ --- Gas commodity price collars: 1999: Onshore 10,839 $1.81 to $1.98 Offshore 295 $2.05 2000 - Onshore 1,365 $1.98
(18) Impairment of Long-Lived Assets Assets Held for Use The Company, in accordance with FAS 121, estimated expected future cash flows of its oil and gas properties by amortization unit and compared the amounts determined to the carrying amount of its oil and gas properties to determine if the carrying amount was recoverable. For those oil and gas properties for which the carrying amount exceeded the estimated future cash flows, an impairment was determined to exist; therefore, the Company adjusted the carrying amount of those oil and gas properties to their estimated fair value as determined by discounting their expected future cash flows at a discount rate commensurate with the risks involved in the industry. As a result of (Continued) F-26 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements this process, the Company recognized an impairment of approximately $22.2 and $69.0 million related to its oil and gas properties during 1998 and 1997, respectively. No impairment was determined to exist in 1996. In 1998, the Company recognized an impairment of approximately $2.2 million on its investment in APRI. This impairment was due to a significant decrease in the fair value of publicly traded securities held by APRI. Assets Held for Sale In the fourth quarter of 1998, the Company approved a plan to dispose of its Gulf of Mexico, Gulf Coast and non-strategic Permian Basin assets. The Company's reason to dispose of these assets varied depending on the portfolio of assets being considered. The disposition would allow the Company to (a) realize full value for certain assets whose value is not fully reflected in the public valuation of the Company in the capital markets, (b) redeploy capital to higher return projects or acquisitions, (c) invest in projects that will accelerate cash flow to the Company, (d) eliminate certain administrative costs and (e) reduce the Company's debt obligations. The Company's basis in these assets (net of any impairment) at December 31, 1998 was approximately $110 million. The Company expects to complete the disposition of all these assets by the third quarter of 1999. In 1998, the Company recognized an impairment of approximately $1.3 million on the assets held for sale. The impairment was the result of comparing the estimated sales proceeds, less costs to sell, to the underlying net cost basis of each specific portfolio of assets. The following are the results of operations of the assets held for sale:
1998 1997 1996 ---- ---- ---- Oil and gas sales $ 12,428 $ 2,666 $ 2,316 Oil and gas production costs (6,626) (974) (893) Production and other taxes (469) (225) (180) Equity loss in net loss of affiliates (458) - - -------- ------- ------- $ 4,875 $ 1,467 $ 1,243 ======== ======= =======
(Continued) F-27 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (19) Other Liabilities The other current and noncurrent liabilities consist of the following (in thousands):
December 31, ---------------------------------- 1998 1997 ---- ---- Other current liabilities: Capital costs and operating expenses $ 2,220 $ 3,472 Gas processing obligation 564 - Restructuring costs 625 - Oil and gas payable 1,106 563 Environmental reserve 248 Other 1,137 613 ------- ------- $ 5,652 $ 4,896 ======= ======= Other noncurrent liabilities: Gas processing obligation $ 1,130 $ - Environmental reserve 824 1,223 Plugging and abandonment reserve 2,483 497 Gas and pipeline imbalances 225 - Other 591 1,000 ------- ------- $ 5,253 $ 2,720 ======= =======
(20) Exploration and Abandonments Exploration and abandonments expense consist of the following (in thousands):
1998 1997 1996 ------- ---- ---- Geological and geophysical staff $ 1,283 $ - $ - Uneconomical exploratory wells 2,593 723 - Impaired unproved properties 9,870 331 - Seismic costs 1,130 1,436 148 Delay rentals 1,685 205 14 Plugging and abandonment reserve 525 - - Other 510 360 22 -------- ------- ------ $ 17,596 $ 3,055 $ 184 ======= ======= ======
(Continued) F-28 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (21) Unaudited Supplementary Information Capitalized Costs
December 31, --------------------------------- 1998 1997 ---- ---- (in thousands) Oil and gas properties: Proved oil and gas properties $ 299,412 $ 341,072 Unproved properties 6,699 25,033 --------- --------- 306,111 366,105 Accumulated depletion (96,934) (94,185) --------- --------- Net capitalized costs for oil and gas properties $ 209,177 $ 271,920 ========= ========= Costs Incurred Year ended December 31, ------------------------------------------------------ 1998 1997 1996 ---- ---- ---- (in thousands) Property acquisition costs: Proved $ 404 $ 100,871 $ 139,110 Unproved 4,994 24,532 802 Exploration 21,316 2,856 129 Development 30,663 44,896 12,468 -------- --------- --------- $ 57,377 $ 173,155 $ 152,509 ======== ========= =========
Reserve Quantity Information The estimates of proved oil and gas reserves, which are located principally in the United States and offshore Gulf of Mexico, were prepared and/or audited (audits are of significant value properties) by independent petroleum consultants as of December 31, 1998, 1997 and 1996. Reserves were estimated in accordance with guidelines established by the SEC and FASB which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations except by contractual arrangements. The Company has presented the reserve estimates utilizing an oil price of $9.49, $16.11 and $25.09 per Bbl and a gas price of $1.57, $1.83 and $2.70 per Mcf as of December 31, 1998, 1997 and 1996, respectively. Oil and gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either an upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing (Continued) F-29 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. Oil And Gas Producing Activities
Oil and Natural Condensate (MBbl) Gas (MMcf) ----------------- ---------- Total Proved Reserves: Balance, December 31, 1995 6,146 134,995 Purchases of minerals-in-place 704 264 Revision of previous estimates 101 47,031 Production (388) (2,725) ------ ------- Balance, September 30, 1996 6,563 179,565 Purchases of minerals-in-place 12,510 109,381 Revision of previous estimates 709 15,494 Production (326) (3,062) ------ ------- Balance, December 31, 1996 19,456 301,378 Purchases of minerals-in-place 7,128 43,501 Extensions and discoveries 20 40,633 Revision of previous estimates 5,551 (18,036) Production (1,880) (22,104) ------ ------- Balance, December 31, 1997 30,275 345,372 Purchase of minerals-in-place 1,540 11,175 Sales of minerals-in-place (77) - Extensions and discoveries 2,127 12,742 Revision of previous estimates - price (7,877) (16,029) Revision of previous estimates - other (485) 5,441 Production (2,492) (26,731) ------ ------- Balance, December 31, 1998 (a) 23,011 331,970 ====== ======= Proved Developed Reserves: December 31, 1995 5,945 45,470 September 30, 1996 6,252 54,119 December 31, 1996 16,024 180,161 December 31, 1997 23,604 219,307 December 31, 1998 13,233 202,203
_____________ (a) At December 31, 1998, total proved reserves included 2,735 MBbl and 42,945 MMcf of oil and natural gas, respectively, which are associated with oil and gas properties classified as assets held for sale in the consolidated balance sheets. (Continued) F-30 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements Standardized Measure Of Discounted Future Net Cash Flows The standardized measure of discounted future net cash flows is computed by applying year-end prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on period-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on period-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
Year ended December 31, -------------------------------------------------------- 1998 1997 1996 ---- ---- ---- (in thousands) Future: Cash inflows $ 738,683 $ 1,121,526 $ 1,300,863 Production costs (241,570) (345,598) (324,551) Development costs (59,976) (46,877) (24,154) Future income taxes (34,387) (153,100) (264,904) ---------- ----------- ----------- Future net cash flows 402,750 575,951 687,254 10% annual discount for estimated timing of cash flows (166,122) (226,901) (299,391) ---------- ----------- ----------- Standardized measure of discounted net cash flows $ 236,628 (a) $ 349,050 $ 387,863 ========== =========== ===========
_____________ (a) At December 31, 1998, the standardized measure of discounted net cash flows included approximately $39.2 million which are associated with oil and gas properties classified as assets held for sale in the consolidated balance sheets. (Continued) F-31 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements
Year ended December 31, ---------------------------------------------------- 1998 1997 1996 ---- ---- ---- (in thousands) Standardized measure, beginning of period $ 349,050 $ 387,863 $ 66,352 Extensions and discoveries and improved recovery, net of future production and development costs 15,155 36,439 - Accretion of discount 34,905 38,786 6,635 Net change in sales prices, net of production, costs (106,032) (180,281) 83,823 Net change in income taxes 80,444 40,115 (126,102) Purchase of minerals-in-place 11,338 72,241 298,867 Sales of minerals-in-place (235) - - Revision of quantity estimates and revenues added by development drilling (33,892) 11,615 70,755 Sales, net of production costs (40,073) (51,846) (14,625) Changes in estimated future development costs (23,040) (7,904) Changes in production rates and other (50,992) 2,022 2,158 ---------- ---------- ---------- Standardized measure, end of period $ 236,628 $ 349,050 $ 387,863 ========== ========== ==========
(Continued) F-32 TITAN EXPLORATION, INC. Notes to Consolidated Financial Statements (22) Selected Quarterly Financial Results (Unaudited)
Quarter -------------------------------------------------------------- First Second Third Fourth ----- ------ ----- ------ (in thousands, except per share data) 1998: Total revenues $ 22,107 $ 18,361 $ 16,671 $ 15,737 Total expenses (a) 23,432 26,260 23,103 47,298 Net loss (1,325) (7,899) (6,432) (31,561) Net loss per common share (.03) (.20) (.17) (.83) Net loss per common share - assuming dilution (.03) (.20) (.17) (.83) 1997: Total revenues $ 18,032 $ 16,166 $ 17,932 $ 21,697 Total expenses (b) 15,755 14,441 15,372 61,726 Net income (loss) 2,277 1,725 2,560 (40,029) Net income (loss) per common share .07 .05 .08 (1.18) Net income (loss) per common share - assuming dilution .06 .05 .07 (1.18)
______________________ (a) Total expenses in the second, third and fourth quarter of 1998 includes impairment of long-lived assets of approximately $8.0 million, $5.1 million and $12.6 million, respectively. (b) The total expenses in the fourth quarter of 1997 include an impairment of long-lived assets of approximately $69.0 million. F-33 EX-21 2 SUBSIDIARIES OF THE REGISTRANT EXHIBIT 21 ---------- Titan Exploration, Inc. Subsidiaries
Name State of Organization Ownership ---- --------------------- --------- Titan Resources Holdings, Inc. Nevada corporation 100% Titan Resources, L.P. Texas limited partnership 100% Titan Resources I, Inc. Delaware corporation 100% Titan Offshore, Inc. Delaware corporation 100% OEDC, Inc. Delaware corporation 100% OEDC Processing, L.P. Texas limited partnership 100% Dauphin Island Gathering Company, L.P. Texas limited partnership 100% Beacon Natural Gas Company, L.P. Texas limited partnership 100% OEDC Exploration & Production, L.P. Texas limited partnership 100% Carrollton Resources, L.L.C. Louisiana limited liability company 100% Carrollton Resources Corporation Louisiana corporation 100% Dauphin Island Gathering Partners Texas general partnership 1% South Dauphin Partners II Limited Texas limited partnership 15% Mobile Bay Processing Partners Delaware general partnership .86% Asia Pacific Refinery Investment, L. P. Delaware limited partnership 13 1/3%
EX-23 3 CONSENT OF INDEPENDENT AUDITORS EXHIBIT 23 The Board of Directors Titan Exploration, Inc. We consent to incorporation by reference in the registration statements (No's. 333-62115, 333-30063, and 333-30061) on Form S-8 and No. 333-62,113 on Form S-3 of Titan Exploration, Inc. of our report dated March 5, 1999, relating to the consolidated balance sheets of Titan Exploration, Inc. and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of earnings, retained earnings, and cash flows for each of the years in the three-year period ended December 31, 1998, which report appears in the December 31, 1998, annual report on Form 10-K of Titan Exploration, Inc. KPMG LLP Midland, Texas March 30, 1999 EX-27 4 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED FINANCIAL STATEMENT OF THE COMPANY 1,000 YEAR DEC-31-1998 JAN-01-1998 DEC-01-1998 610 0 14,258 0 1,276 125,912 312,451 98,095 341,022 20,215 0 0 0 405 170,949 341,022 72,876 72,876 0 117,998 (1,172) 0 8,648 (52,598) (5,381) (47,217) 0 0 0 (47,217) (1.22) (1.22)
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