-----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, FwAAJtEeIpe1nCa2jZKgkz7gQDnsnaA9G1lWkFz/jztj8y9BIplN4uREP3oRbRc4 8YyyHI21StsXq8vkAAnrGA== 0000899243-00-000702.txt : 20000331 0000899243-00-000702.hdr.sgml : 20000331 ACCESSION NUMBER: 0000899243-00-000702 CONFORMED SUBMISSION TYPE: 10KSB40 PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: 3TEC ENERGY CORP CENTRAL INDEX KEY: 0000903267 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 631081013 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10KSB40 SEC ACT: SEC FILE NUMBER: 001-14745 FILM NUMBER: 587755 BUSINESS ADDRESS: STREET 1: TWO SHELL PLZ STREET 2: 777 WALKER STE 2400 CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7132226275 MAIL ADDRESS: STREET 1: PO BOX 390 CITY: MOBILE STATE: AL ZIP: 36602 FORMER COMPANY: FORMER CONFORMED NAME: MIDDLE BAY OIL CO INC DATE OF NAME CHANGE: 19930504 10KSB40 1 FORM 10-KSB SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ---------- FORM 10-KSB ---------- 3TEC ENERGY CORPORATION (Exact name of registrant as specified in its charter) Delaware 76-0624573 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) TWO SHELL PLAZA, SUITE 2400 777 WALKER STREET HOUSTON, TEXAS 77002 (713) 821-7100 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices) ------------------------ Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange on Title of Each Class Which Registered ----------------------------- -------------------- None N/A Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.02 Par Value Series C Convertible Redeemable Preferred Stock, $.02 Par Value Check whether the Registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the past 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 [ ] Check if disclosure of delinquent filers in response to Item 405 of Regulation S-B is not contained in this form, 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-KSB or any amendment to this Form 10-KSB. [x] Revenues of Registrant for fiscal year ended December 31, 1999 are $22,020,066. The aggregate market value as of March 8, 2000 of voting and nonvoting stock held by nonaffiliates of the Registrant was $20,070,413. As of March 8, 2000 the Registrant had 6,419,022 shares of Common Stock, $.02 par value outstanding. Documents Incorporated by Reference: Related Section Document - -------------------------------------------------------------------------------- Part III Definitive Proxy Statement to be filed pursuant to Regulation 14A on or before May 1, 2000. TABLE OF CONTENTS Page ----- ITEM 1-BUSINESS Background...................................................................................... 3 Business Strategy............................................................................... 3 Our Strengths................................................................................... 4 Significant Developments Since December 31, 1998................................................ 4 Marketing....................................................................................... 5 Competition..................................................................................... 6 Regulation...................................................................................... 6 Employees....................................................................................... 8 Our Executive Offices........................................................................... 8 ITEM 2-PROPERTIES Description of Our Properties................................................................... 8 Description of Magellan Properties.............................................................. 9 Natural Gas and Oil Reserves.................................................................... 10 Volumes, Prices and Operating Expenses.......................................................... 11 Development, Exploration and Acquisition Capital Expenditures................................... 11 Drilling Activity............................................................................... 12 Productive Wells................................................................................ 12 Acreage Data.................................................................................... 12 ITEM 3-LEGAL PROCEEDINGS........................................................................ 13 ITEM 4-SUBMISSION OF MATTERS TO VOTE OF SECURITY HOLDERS........................................ 13 Forward-Looking Statements...................................................................... 13 Risk Factors.................................................................................... 14 ITEM 5-MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.................... 20 ITEM 6-MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Overview........................................................................................ 21 Results of Operations........................................................................... 23 Year Ended December 31, 1999, Compared With Year Ended December 31, 1998........................ 24 Year Ended December 31, 1998, Compared With Year Ended December 31, 1997........................ 24 ITEM 7-FINANCIAL STATEMENTS..................................................................... 27 ITEM 8-CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE..... 27 ITEM 9-DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT....................................... 27 ITEM 10-EXECUTIVE COMPENSATION.................................................................. 28 ITEM 11-SECURITY OWNERSHIP OF CERTAIN BENEFICAL OWNERS AND MANAGEMENT........................... 28 ITEM 12-CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.......................................... 28 ITEM 13-EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K........................................................................................ 28 Glossary of Certain Oil and Gas Terms........................................................... 31 Signatures...................................................................................... 33 _____________ ________________________________________________________________________________________________________ Item 13(a) includes the Index of Exhibits to be filed with the Securities and Exchange Commission relative to this Report. ________________________________________________________________________________________________________
2 PART I ITEM 1. BUSINESS BACKGROUND 3TEC Energy Corporation ("3TEC", "the Company", "we", "our" and "us") is the successor to Middle Bay Oil Company, Inc. ("Middle Bay"), an Alabama corporation formed on November 30, 1992. 3TEC was incorporated in Delaware on November 24, 1999, as a wholly owned subsidiary of Middle Bay for the sole purpose of merging with Middle Bay to effect a change in domicile to Delaware and to change our name to 3TEC Energy Corporation. Effective December 7, 1999, Middle Bay was merged into us and each share of common stock of Middle Bay was converted into one share of our common stock. We are engaged in the acquisition, development, production and exploration of oil and natural gas reserves. Our properties are concentrated in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. We also own significant properties in the Permian and San Juan basins and in the Mid-Continent region. Our management and technical staff have substantial experience in each of these areas. As of December 31, 1999, we had estimated total net proved reserves of 218.7 Bcfe, of which approximately 73% were natural gas and approximately 82% were proved developed, with an estimated PV-10 value of $198.6 million. As of December 31, 1999, our net daily production was approximately 38.1 Mmcf of natural gas and 3.1 MBbls of oil or 56.7 Mmcfe. We have increased our reserves and production principally through acquisitions. We focus on properties that have a substantial proved reserve component and which management believes to have additional exploitation opportunities. Recently, we have also acquired a number of drilling prospects covered by an extensive 3-D seismic database that we believe have exploration potential. We have assembled an experienced management team and technical staff with expertise in property acquisitions and development, reservoir engineering, exploration and financial management. BUSINESS STRATEGY Our business strategy focuses on achieving increases in the per share value of our common stock through the continued pursuit of attractive acquisitions, the further development of our existing proved properties, the drilling of exploration projects and the rationalization of our existing asset base. This strategy includes: . Pursue Strategic Acquisitions. We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects. We seek to acquire operational control of properties that we believe have significant exploitation and/or exploration potential. We also intend to increase our holdings in fields and basins in which we already own properties. . Further Develop Existing Properties. We intend to further develop our properties having proved reserves. We seek to add proved reserves and increase production through detailed technical analysis of our properties and by drilling infill locations and selective recompletions of existing wells. We also plan to drill step-out wells to expand known field limits. We intend to enhance the efficiency and quality control of these activities by operating the majority of our projects. . Utilize the Latest Available Technology. We intend to continue to utilize advanced technologies, including 3-D seismic interpretation, computer- aided exploration, horizontal drilling and advanced completion technologies, to optimize our operational and financial results. . Grow Through Exploration. We conduct an active technology driven exploration program that is designed to complement our property acquisition and development drilling efforts with moderate to high risk exploration projects that have greater reserve potential. We generate exploration prospects through the analysis of geological and geophysical data and the interpretation of 3-D seismic data. We intend to 3 manage our exploration expenditures through the optimal scheduling of our drilling program and by selectively reducing our participation in certain exploratory prospects through sales of interests to industry partners. . Rationalize Property Portfolio. We intend to actively pursue opportunities to reduce and control operating costs of our existing properties and properties we may acquire in the future through the consolidation of overlapping operations, the sale of marginal properties and by increasing the number of fields we operate as a percentage of our total properties. . Maintain Financial Flexibility. We intend to maintain a substantial unused borrowing capacity under our bank credit facility by periodically refinancing our bank debt in the capital markets when conditions are favorable. We believe our expanded base of internally generated cash flow and other financial resources provide us with the financial flexibility to pursue additional acquisitions of producing properties and leasehold acreage and to develop our project inventory in an optimal fashion. OUR STRENGTHS We believe our historical success and future performance are, and will be, directly related to the following combination of strengths: . Proven Acquisition Experience. Since the investment by W/E LLC (described below) in August 1999, through the acquisition of the Floyd Oil Properties (described below), we have added approximately 165 Bcfe of proved reserves with a PV-10 value of $146.1 million as of December 31, 1999. In addition, in early February we closed the acquisition of Magellan Exploration, L.L.C. Our acquisition efforts are managed by an experienced team of property aggregators with extensive engineering, operating and financial skills. . Experienced Technical Team. Our technical team is comprised of respected energy industry professionals with an average of over 20 years of industry experience. . Substantial Inventory of Development and Exploration Prospects. We have assembled an inventory of in excess of 90 drilling locations balanced between what we believe to be low to moderate risk development locations and higher risk, higher potential exploratory locations defined by, and supported with, 3-D seismic data. Our inventory of drilling locations and degree of operating control provide us flexibility in project selection and the timing of drilling projects. . Financial Flexibility. We have the financial flexibility to respond quickly to opportunities for growth and changing business conditions. SIGNIFICANT DEVELOPMENTS SINCE DECEMBER 31, 1998 . Acquisition of Control by W/E Energy Company L.L.C. In August 1999, W/E Energy Company L.L.C., formerly named 3TEC Energy Company L.L.C. ("W/E LLC"), which is owned by affiliates of EnCap Investments L.L.C. ("EnCap") and Floyd C. Wilson, purchased a significant interest in us for approximately $20.5 million in cash and $875,000 in producing properties. As of December 31, 1999, W/E LLC owned approximately 30% of our outstanding common stock. Concurrently with the investment by W/E LLC, Mr. Wilson was named our Chairman, President and Chief Executive Officer. . Acquisition of Floyd Oil Properties. In November 1999, we completed the acquisition of properties and interests managed by Floyd Oil Company (the "Floyd Oil Properties") for $86.8 million in cash and 503,426 shares of our common stock. The majority of these properties are located in Texas and Louisiana and, as of December 31, 1999, had estimated proved reserves of 165 Bcfe with an associated PV-10 value 4 of $146.1 million. Additionally, 76% of the acquired reserves are natural gas and 77% are classified as proved developed. We operate approximately 53% on a PV-10 value basis and, as of December 31, 1999, net daily production was approximately 41.6 Mmcfe. We plan to aggressively exploit these properties and have budgeted approximately $17 million for development drilling and exploitation activity in 2000. Floyd Oil Company was not affiliated with Floyd C. Wilson prior to its acquisition by the Company. . Credit Facility. Concurrent with our acquisition of the Floyd Oil Properties, we entered into a new $250 million credit facility with Bank One, Texas, N.A., as agent, and Union Bank of California, N.A., Wells Fargo Bank, CIBC, Inc. and The Bank of Nova Scotia as participating lenders. Our borrowing base, which is redetermined semi-annually, has been initially set at $95.0 million with $87.5 million outstanding as of December 31, 1999. One-for-Three Reverse Stock Split. We held a Special Meeting of Shareholders on January 14, 2000, at which meeting our shareholders approved an Amendment to the Company's Certificate of Incorporation which effected a 1-for-3 reverse stock split of our common stock. The reverse stock split became effective on January 18, 2000. Among the reasons we proposed the reverse stock split was an effort to increase the trading price of our common stock to a level above $5 per share, which is the minimum trading price for admission of the common stock for trading on the Nasdaq National Market. We have applied for the listing of our common stock on the Nasdaq National Market. . Recent Acquisition of Magellan Exploration, LLC. On February 3, 2000, we completed the acquisition of Magellan Exploration, LLC ("Magellan"), from certain affiliates of EnCap and other third parties for consideration consisting of (a) 1,085,934 shares of common stock, (b) four year warrants to purchase up to 333,333 shares of common stock at $30.00 per share, (c) 617,008 shares of 5% Series D Convertible Preferred Stock with a redemption value of $24.00 per share and (d) the assignment of a performance based "back-in" working interest of 5% of Magellan's interest in 12 exploration prospects. The acquisition cost, applying the purchase method of accounting, was $18.3 million. Magellan's properties are located both onshore and in the shallow waters of south Louisiana and consist of over 20,000 gross (11,650 net) acres in three prospective areas. As of December 31, 1999, Ryder Scott Company ("Ryder Scott"), estimated that Magellan's net proved reserves were 26.6 Bcfe with an associated PV-10 value of $40.1 million. These proved reserves are approximately 66% natural gas and 80% of the volumes are classified as proved undeveloped. Magellan operates approximately 80% of its properties on a PV-10 value basis. In addition to the proved reserves, the Magellan properties contain several exploratory drilling locations that have been identified using 3-D seismic data. YEAR 2000 COMPLIANCE We had undertaken various initiatives to ensure that our hardware, software and equipment functioned properly with the rollover of the date to January 1, 2000. We experienced no problems as a result of rollover of the dates to January 1, 2000, and the costs incurred for Year 2000 compliance were immaterial to our financial position and results of operations. Although we can provide no assurance, we anticipate any future costs associated with Year 2000 compliance to be immaterial to our financial position and results of operations. MARKETING We have marketed the natural gas and oil produced from our properties through typical channels for these products. We generally sell our oil at local field prices paid by the principal purchasers of oil. The majority of our natural gas production is sold at spot prices. Both natural gas and oil are purchased by marketing companies, pipelines, major oil companies, public utilities, industrial customers and other users and processors of petroleum products. We are not confined to, or dependent upon, any one purchaser or small group of purchasers. Accordingly, the loss of a single purchaser, or a few purchasers, would not have a long-term material effect on our business because there are numerous purchasers in the areas in which we sell our production. 5 COMPETITION We face competition from other oil and gas companies in all aspects of our business, including acquisition of producing properties and oil and gas leases, marketing of oil and gas, and obtaining goods, services and labor. Many of our competitors have substantially larger financial and other resources. Factors that affect our ability to acquire producing properties include available funds, available information about the property and our standards established for minimum projected return on investment. Competition is also presented by alternative fuel sources, including heating oil and other fossil fuels. We believe that we are competing and will compete effectively as a result of our expertise in the acquisition, exploration, and development of oil and gas reserves and our financial ability to take advantage of such opportunities. REGULATION Federal Regulation of Transportation of Natural Gas. Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated by the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978, and the regulations promulgated by the Federal Energy Regulatory Commission. In the past, the federal government has regulated the prices at which natural gas could be sold. Deregulation of natural gas sales by producers began with the enactment of the Natural Gas Policy Act. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting producer sales of natural gas effective January 1, 1993. Congress could, however, reenact price controls in the future. Our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal regulation. Beginning in April 1992, the Federal Energy Regulatory Commission issued Order No. 636 and a series of related orders, which required interstate pipelines to provide open- access transportation on a basis that is equal for all natural gas suppliers. The Federal Energy Regulatory Commission has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. Although Order No. 636 does not directly regulate our production and marketing activities, it does affect how buyers and sellers gain access to the necessary transportation facilities and how we and our competitors sell natural gas in the marketplace. The courts have largely affirmed the significant features of Order No. 636 and the numerous related orders, although some appeals remain pending and the Federal Energy Regulatory Commission continues to review and modify its regulations regarding the transportation of natural gas. One broad and significant pending review involves examination of several questions, including whether the transportation regulations should be changed to better operate together with changes in state law that are introducing competition in retail natural gas markets, whether the historical method of setting transportation rates based on cost should be changed for certain transportation, whether short term transportation capacity should be allocated based only on auctions, and whether additional changes need to be made to long term transportation policies to prevent a market bias in favor of short term transportation. We cannot predict what action the Federal Energy Regulatory Commission will take on these matters, nor can we accurately predict whether the Federal Energy Regulatory Commission's actions will achieve the goal of increasing competition in markets in which our natural gas is sold. However, we do not believe that any action taken will affect us in a way that materially differs from the way it affects other oil and natural gas producers. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the Federal Energy Regulatory Commission and the courts. The natural gas industry historically has been very heavily regulated; therefore, we cannot assure you that the less stringent regulatory approach recently pursued by the Federal Energy Regulatory Commission and Congress will continue. Federal Regulation of Transportation of Oil. Oil and sales of oil, condensate and natural gas liquids by us are not currently regulated and are made at market prices. Effective as of January 1, 1995, the Federal Energy Regulatory Commission implemented regulations establishing an indexing system for transportation rates for interstate common carrier oil pipelines. These rates are generally indexed to inflation, subject to conditions and limitations. These regulations may, over time, tend to increase transportation costs or reduce wellhead prices for oil. 6 However, we do not believe that these regulations affect us any differently than other oil and gas producers, gatherers and marketers. State Regulation. Our oil and gas operations are subject to various types of regulation at the state and local levels. These regulations require drilling permits, regulate the methods for developing new fields and the spacing and operating of wells and waste prevention, and sometimes impose production limitations. These regulations may limit our production from wells and the number of wells or locations we can drill. Some states have adopted regulations with respect to gathering systems. These regulations have not had a material effect on the operation of our gathering systems, but we cannot predict whether any future regulations in this area may have a material impact on our gathering systems. Federal, State and Indian Leases. Our operations on federal, state or Indian oil and gas leases are subject to numerous restrictions, including nondiscrimination statutes. We must conduct our operations on these leases pursuant to permits and authorization and other regulations issued by the Bureau of Land Management, Minerals Management Service and other agencies. The Minerals Management Service currently has under consideration a proposal to change the manner in which crude oil is valued for purposes of calculating royalty due the government. If adopted, these changes would decrease reliance on historical valuation methods and instead adopt an indexing method intended to better reflect market value, but which may not reflect the proceeds actually received in the sale of the oil. We cannot predict what action the Minerals Management Service may ultimately take or how it will affect royalty payable on our production from federal leases, however, if adopted the changes may tend to increase costs of royalty payments. Environmental Regulations. Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Our exploration and production operations and facilities for gathering, treating, processing and handling hydrocarbons and related exploration and production wastes are subject to stringent environmental regulation. These laws and regulations sometimes require government approvals before activities occur, limit or prohibit activities because of protected areas or species, impose substantial liabilities for pollution and provide penalties for noncompliance. As with the industry generally, compliance with existing and anticipated regulations increases our overall cost of business. These regulations, however, generally affect us and our competitors similarly. Environmental laws and regulations are subject to frequent change, and we are not able to predict the costs or other impacts of environmental regulation on our future operations. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on some classes of persons that are considered to have contributed to the release or threat of release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and 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. Our operations are also subject to regulation of air emissions under the Clean Air Act and comparable state and local requirements. Implementation of these laws could lead to the gradual imposition of new air pollution control requirements on our operations. As a result, we may incur capital expenditures over the next several years to upgrade our air pollution control equipment. We do not believe that our operations would be materially affected by any such requirements, nor do we expect such requirements to be any more burdensome to us than to other companies our size involved in natural gas and oil exploration and production activities. In addition, legislation has been proposed in Congress from time to time that would reclassify some natural gas and oil exploration and production wastes as "hazardous wastes," which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If Congress were to enact this legislation, it 7 could increase our operating costs, as well as those of the natural gas and oil industry in general. Initiatives to further regulate the disposal of natural gas and oil wastes are also pending in some states, and these various initiatives could have a similar impact on us. The Clean Water Act imposes restrictions and controls on the discharge of oil and gas wastes and other forms of pollutants into waters of the United States. Federal law also imposes strict liability on owners of facilities for consequences of an oil spill where the spill is in navigable waters or along shorelines. These laws impose penalties for unauthorized discharges and substantial liability for costs of removal and damages resulting from an unauthorized discharge. State laws for the control of water pollution provide similar penalties and liabilities. The cost of compliance with water pollution laws has not historically been material to our operations. There can be no assurance that changes in federal, state or local water pollution laws and programs will not materially adversely affect our operations in the future. Our management believes that we are in substantial compliance with current environmental laws and regulations that affect us and that continued compliance with these requirements will not have a material adverse impact on us. EMPLOYEES At December 31, 1999, we had 46 full-time employees. We believe that our relationships with our employees are satisfactory. None of our employees is covered by a collective bargaining agreement. From time to time, we use the services of independent consultants and contractors to perform various professional services, particularly in the areas of construction, design, well- site surveillance, permitting and environmental assessment. OUR EXECUTIVE OFFICES Our principal executive offices are located at Two Shell Plaza, 777 Walker Street, Suite 2400, in Houston, Texas 77002, and our telephone number is (713) 821-7100. ITEM 2. PROPERTIES DESCRIPTION OF OUR PROPERTIES We present information regarding our natural gas and oil reserves, properties, and operating results below. We separately describe the properties of Magellan, which we acquired on February 3, 2000, under the caption "Description of Magellan Properties." Except as set forth following the caption "Description of Magellan Properties", we have not otherwise included information for the properties of Magellan in any of the information that follows.
As of December 31, 1999 ------------------------------------------------------- Budgeted Estimated Net Proved Reserves Percent 2000 ------------------------------- PV-10 Total Identified Capital Gas Oil Total Value PV-10 Drilling Expenditures (Mmcf) (MBblS) (Mmcfe) ($000) Value Locations ($000) ------- ------ ------- ------- -------- --------- ------------- East Texas............................. 61,595 669 65,608 44,189 22.2% 53 7,605 Gulf Coast Area........................ 50,661 1,543 59,929 59,771 30.0% 19 7,530 Permian/San Juan Area.................. 20,766 4,793 49,521 55,021 27.7% 2 35 Mid-Continent Area..................... 26,590 2,398 40,978 36,162 18.3% 16 830 Other Areas............................ 87 432 2,676 3,472 1.8% 0 0 ------- ----- ------- ------- ----- ----- ------ Total................................. 159,699 9,835 218,712 198,615 100.0% 90 16,000 ======= ===== ======= ======= ===== ===== ======
East Texas. Our properties in the East Texas region produce primarily from the Cotton Valley and Travis Peak Formations which range in depth from 7,000 feet to 10,500 feet. As of December 31 1999, our estimated net daily production from this area was 10.6 Mmcfe per day. The producing 8 formations of this area tend to contain multiple producing horizons and are typically low permeability sands that require fracture stimulation to achieve optimal producing rates. This type of fracture stimulation usually results in relatively high initial production rates that decline rapidly during the first year of production and subsequently stabilize at fairly low, more easily predictable annual decline rates. Much of our production in this area is from wells that have been producing for several years and are in their latter, more stable stage of production, resulting in a relatively long reserves to production ratio. Additionally, reservoirs with multiple producing horizons typically provide numerous recompletion and workover opportunities to enhance proved reserves and production. We have identified 53 proved undeveloped drilling locations in this area. Many of these development drilling locations are based on a change in regulatory field rules that now permit wells to be drilled on 80 acre spacing as opposed to 160 acre spacing. This type of infill drilling is generally effective in low permeability sands, such as the Cotton Valley, where one wellbore is only capable of draining an area less than the permitted spacing. Drilling infill wells on 80 acre spacing has been successful throughout the area in such notable Cotton Valley fields as Carthage, Oak Hill and Willow Springs. For 2000 we have budgeted approximately $7.6 million for the drilling of development wells and various exploitation activities. Gulf Coast Area. We have established a substantial base of proved reserves and undeveloped acreage with significant exploration potential along the Gulf Coast of Texas and Louisiana. As of December 31, 1999, our estimated net daily production from this area was 17.8 Mmcfe per day. Onshore in southern Louisiana and southeast Texas our production is mainly from the Hackberry, Miogyp and Vicksburg formations which range from 13,000 feet to 17,000 feet in depth. Along the central and southern Texas coast we are active in two main areas, the Stuart City field in the Edwards Reef Trend and the Segundo Olmos field in Webb County, Texas. The Edwards Reef Trend extends from the Mexican border through the Texas Gulf Coast into southern Louisiana and has been extensively drilled since the late 1950s. The Edwards Reef Trend formation is a very thick section of low permeability limestone that requires fracture stimulation to achieve optimal production rates and even then will only drain a limited area. Our acreage has seven producing wells that were drilled on 320 acre spacing and we have identified seven additional proved undeveloped locations on this acreage based on drilling infill locations on 120 acre spacing. Infill drilling has been successful throughout this trend. We are also evaluating the drilling of new horizontal legs in existing wells and conducting additional fracture stimulations, both of which have been successful in the Edwards Reef Trend. The Segundo Olmos field produces from the Olmos formation, a relatively low permeability sandstone, at a depth of 7,000 feet. This field was originally drilled on 160 acre spacing and has been successfully drilled on 80 acre spacing throughout the trend. We have identified an additional five proved undeveloped locations in this field. In 2000, we have budgeted approximately $7.5 million for the drilling of development wells and associated exploitation activity in these areas. Permian, San Juan and Mid-Continent Areas. We own interests in numerous fields in the Anadarko, Arkoma, Permian and San Juan basins in the states of Kansas, Oklahoma, Texas and New Mexico and our estimated net daily production as of December 31, 1999, was 28.3 Mmcfe per day. These fields are generally characterized as mature producing fields that have very stable low rates of decline and a relatively small amount of development drilling and exploitation potential. In 2000, we have budgeted approximately $900,000 for the drilling of wells and associated exploitation projects in these areas. DESCRIPTION OF MAGELLAN PROPERTIES Through the acquisition of Magellan, we acquired interests in Breton Sound Block 34 in Louisiana state waters and the Bay De Chene and Garden City fields in south Louisiana. While there is a relatively small amount of existing production, all three fields have had 3-D seismic surveys and in the aggregate have substantial proved undeveloped and proved developed non-producing reserves. Management believes these properties also have additional exploration potential. Several experienced engineers and geoscientists at Magellan, who developed many of the exploration prospects and have extensive experience in south Louisiana, have joined our technical staff. Breton Sound Block 34 is located in 12 feet to 15 feet of water east of the Main Pass area of the Mississippi River delta. This field is currently producing 0.8 Mmcfe per day net to our interest and has significant proved developed non-producing and proved undeveloped reserves in the Krumbar and Hollywood formations at approximately 15,000 feet to 17,000 feet in depth. Additionally, we have identified a proved undeveloped location supported by 3-D seismic data in Breton Sound Block 34 ("Alpha Prospect") that is structurally high to an offsetting well drilled by 9 Conoco. In addition to our Alpha Prospect, we have identified four additional exploration prospects in untested fault blocks that have similar characteristics to the Alpha Prospect based on the interpretation of the 3-D seismic data. In 2000, we have budgeted approximately $3.7 million for development drilling and recompletions. The Bay De Chene field and the Garden City field are older fields that have produced substantial amounts of oil and gas which we believe to have further development and exploration potential. The Bay De Chene field is a highly faulted, geologically complex salt dome based structure that has produced over 100 MBbls of oil and 230 Bcf of gas from over 67 different reservoirs. In 1997, Western Geophysical conducted a 72 square mile 3-D seismic survey resulting in the identification of numerous potential development drilling locations and exploitation projects and several exploration drilling prospects. The majority of these opportunities are between 7,000 feet and 10,000 feet in depth and are in reservoirs that have been productive throughout the field. This field is currently producing 1.0 Mmcfe per day net to our interest. The Garden City field has produced over 2 Tcfe since its discovery and contains one proved undeveloped drilling location and several exploration prospects. All of these drilling opportunities have been evaluated with 3-D seismic and subsurface data. In 2000, we have budgeted approximately $2.8 million for the Bay De Chene and Garden City fields for development drilling and recompletions. We will continue to evaluate our exploration projects in these fields. NATURAL GAS AND OIL RESERVES The following table presents our estimated net proved natural gas and oil reserves and the PV-10 value of our reserves as of December 31, 1999 and 1998. The period end prices of oil and natural gas at December 31, 1999 and 1998, used in the PV-10 calculation were $23.64 and $9.50 per barrel of oil and $2.23 and $2.10 per thousand cubic feet of natural gas, respectively. Our estimated net proved natural gas and oil reserves and the PV-10 value of our reserves as of December 31, 1999, are based on a reserve report prepared by Ryder Scott Company for our properties. In 1998 such estimates for our properties were prepared by Lee Keeling and Associates, Inc. and H.J. Gruy and Associates, Inc. The PV-10 values shown in the table are not intended to represent the current market value of the estimated natural gas and oil reserves we own. For further information concerning the PV-10 values of these proved reserves, please read note 15 of the notes to our December 31, 1999 consolidated financial statements. The information set forth below does not include reserve information of Magellan which we acquired in February 2000. See "Description of Magellan Properties."
December 31, 1999 1998 -------- ------- Proved reserves: Natural gas (Mmcf)............................................... 159,699 43,483 Oil (MBbls)...................................................... 9,835 3,342 Natural gas equivalents (Mmcfe).................................. 218,711 63,535 Proved developed reserves: Natural gas (Mmcf)............................................... 122,914 36,731 Oil (MBbls)...................................................... 9,358 3,118 Natural gas equivalents (Mmcfe).................................. 179,062 55,439 Estimated future net cash flows before income taxes, in thousands... $370,258 $71,464 PV-10 value, in thousands........................................... 198,615 38,894
There are numerous uncertainties in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond our control. The reserve data herein are only estimates. Although we believe these estimates to be reasonable, reserve estimates are imprecise and may be expected to change as additional information becomes available. Estimates of oil and natural gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of this data, as well as the projection of future rates of production and the timing of development expenditures. Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be exactly measured. Therefore, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of the reserves based on risk of recovery and the estimates are a function of the quality of available data and of engineering and geological interpretation and judgment and the future net cash flows expected therefrom, prepared by different engineers or by 10 the same engineers at different times may vary substantially. There also can be no assurance that the reserves set forth herein will ultimately be produced or that the proved undeveloped reserves will be developed within the periods anticipated. Actual production, revenues and expenditures with respect to our reserves will likely vary from estimates, and the variances may be material. In addition, the estimates of future net revenues from our proved reserves and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct. We emphasize with respect to the estimates prepared by independent petroleum engineers that PV-10 value should not be construed as representative of the fair market value of our proved oil and natural gas properties since discounted future net cash flows are based upon projected cash flows which do not provide for changes in oil and natural gas prices or for escalation of expenses and capital costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they are based. Actual future prices and costs may differ materially from those estimated. Volumes, Prices and Operating Expenses The following table presents information regarding the production volumes of, average sales prices received for, and average production costs associated with, our sales of oil and natural gas for the periods indicated. The oil and natural gas production from the properties acquired in the Floyd Oil Acquisition, during the period November 23, 1999 to December 31, 1999, was 75 thousand barrels of oil and 1,112 Mmcf of natural gas.
Years Ended December 31, ---------------------------------------------- 1999 1998 1997 ------------- --------------- ------------ Production volumes: Natural gas (Mmcf)..................................... 4,737 3,847 1,929 Oil (MBbls)............................................ 532 581 254 Natural gas equivalents (Mmcfe)........................ 7,928 7,333 3,453 Average sale prices: Natural gas ($ per Mcf)................................ $ 2.18 $ 2.00 $ 2.39 Oil ($ per Bbl)........................................ 16.88 11.52 18.06 Natural gas equivalents ($ per Mcfe)................... 2.43 1.96 2.82 Average costs ($ per Mcfe): Lease operating and production taxes................... $ 0.85 $ 1.06 $ 1.11 General and administrative............................. 0.60 0.58 0.68 Depreciation, depletion and amortization............... 0.84 0.97 1.32
DEVELOPMENT, EXPLORATION AND ACQUISITION CAPITAL EXPENDITURES The following table presents unaudited information regarding our net costs incurred in the purchase of properties and in exploration and development activities.
Years Ended December 31, --------------------------- 1999 1998 ---------- ------------ (in thousands) Acquisition.................................... $91,424 $29,215 Exploration.................................... 824 1,802 Development.................................... 2,154 3,041 ------- ------- Total costs incurred...................... $94,402 $34,058 ======= =======
11 DRILLING ACTIVITY The following table shows our drilling activity for the years ended December 31, 1999, 1998 and 1997. In the table, "gross" refers to the total wells in which we have a working interest and "net" refers to gross wells multiplied by our working interest in these wells.
Years Ended December 31 ------------------------------------------------------------- 1999 1998 1997 ------------------- ------------------ ------------------ Gross Net Gross Net Gross Net -------- -------- ------- -------- ------- -------- Exploration Wells: Productive................ 0 0.000 1 0.125 8 0.452 Non-Productive............ 5 0.900 8 0.793 11 1.280 -- ----- -- ----- -- ----- Total.................. 5 0.900 9 0.918 19 1.732 == ===== == ===== == ===== Development Wells: Productive................ 21 5.667 12 1.508 17 5.627 Non-Productive............ 0 0.000 2 1.100 6 4.150 -- ----- -- ----- -- ----- Total.................. 21 5.667 14 2.608 23 9.777 == ===== == ===== == =====
Productive Wells The following table sets forth the number of productive natural gas and oil wells in which we owned an interest as of December 31, 1999.
Total Productive Wells ---------------------- Gross Net ------- ---------- Natural Gas................ 677 252 Oil........................ 1,478 395 ----- --- Total................. 2,155 647 ===== ===
Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. At December 31, 1999, we operated approximately 425 wells, located primarily in Texas. ACREAGE DATA The following table presents information regarding our developed and undeveloped lease acreage as of December 31, 1999. Developed acreage refers to acreage within producing units and undeveloped acreage refers to acreage that has not been placed in producing units.
Developed Undeveloped ------------------------- --------------------------- Acreage Acreage Total ------------------------- --------------------------- --------------------------- Gross Net Gross Net Gross Net ----------- ----------- ------------ ------------ ------------- ----------- Texas............. 169,924 53,245 6,575 1,315 176,499 54,560 Louisiana......... 23,031 2,691 2,568 983 25,599 3,674 Kansas............ 20,579 13,171 6,507 6,507 27,086 19,678 Oklahoma.......... 79,256 22,846 205 205 79,461 23,051 Other............. 164,857 60,258 560 490 165,417 60,748 ------- ------- ------ ----- ------- ------- Total........ 457,647 152,211 16,415 9,500 474,062 161,711 ======= ======= ====== ===== ======= =======
Excluded from the acreage data are approximately 35,214 net mineral acres owned by us, primarily in La Fourche, St. Mary and Terrebonne parishes of Louisiana, all of which we believe have potential for oil and natural gas exploration. CURRENT ACTIVITIES As of March 29, 2000, five wells (1.486 net wells) were being drilled. Three wells are in Louisiana, one in Texas and one in Oklahoma. 12 ITEM 3. LEGAL PROCEEDINGS From time to time, we are party to various routine litigation proceedings incidental to our business. We currently are not a party to any material litigation. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS On October 28, 1999, a proxy was mailed to shareholders of record on October 1, 1999, soliciting their vote at a Special Meeting of Shareholders of the Company on November 18, 1999. The following matters were submitted to a vote of shareholders (Shares Eligible to Vote on All Matters: 4,453,744): 1. To approve a change in the Company's state of incorporation from Alabama to Delaware by means of a merger of the Company with and into a wholly-owned subsidiary, 3TEC Energy Corporation, a Delaware corporation, which the Company formed for this purpose. The reincorporation to Delaware was approved. For Against Abstain 3,823,583 1,919 964 2. To approve a change of the Company's name to 3TEC Energy Corporation. The name change was approved. For Against Abstain 4,093,954 5,336 1,357 3. To approve an increase in the number of authorized shares of common stock of the Company from 40,000,000 to 60,000,000 The increase in the authorized shares of common stock was approved. For Against Abstain 4,091,636 7,243 1,081 4. To consider and approve the Company's 1999 Stock Option Plan The 1999 Stock Option Plan was approved. For Against Abstain 3,816,955 7,392 2,119 FORWARD-LOOKING STATEMENTS This information herein and the information incorporated by reference contain statements that constitute "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements appear in a number of places and include statements regarding our plans, beliefs, intentions or current expectations, including those plans, beliefs, intentions and expectations of our officers and directors with respect to, among other things: . budgeted capital expenditures; . increases in oil and gas production; . our outlook on oil and gas prices; 13 . estimates of our oil and gas reserves; . our future financial condition or results of operations; and . our business strategy and other plans and objectives for future operations. More specifically, some of the statements contained herein under "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties" that relate to our business and the industry in which we operate are forward-looking. Statements or assumptions related to or underlying these forward-looking statements include, without limitation, statements regarding: . the quality or value of our properties with regard to, among other things, the existence of reserves in economic quantities; . our ability to increase our reserves through exploration and development activities; . the number of locations to be drilled and the time frame within which they will be drilled; . future prices of oil and natural gas; . anticipated domestic demand for oil and natural gas; and . the adequacy of our capital resources and liquidity. Actual results may differ materially from those suggested by the forward-looking statements for various reasons, including those discussed under "Risk Factors". RISK FACTORS OIL AND GAS PRICES ARE VOLATILE, AND LOW PRICES HAVE IN THE PAST AND COULD IN THE FUTURE HAVE A MATERIAL ADVERSE IMPACT ON OUR BUSINESS. Our revenues, profitability and future growth and the carrying value of our properties depend substantially on prevailing oil and gas prices. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital. The amount we will be able to borrow under our credit facility will be subject to periodic redetermination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil and gas that we can economically produce. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile in the future. For example, natural gas and oil prices declined significantly in late 1997 and 1998. These declines had a significant negative impact on our financial results for 1997, 1998 and the first two quarters of 1999, contributing to our losses for those periods. Among the factors that can cause volatility are: . the domestic and foreign supply of natural gas and oil; . the ability of members of the Organization of Petroleum Exporting Countries to agree upon and maintain oil prices and production levels; . political instability or armed conflict in oil or gas producing regions; . the level of consumer product demand; . weather conditions; . the price and availability of alternative fuels; . the price of foreign imports; and . worldwide economic conditions. These external factors and the volatile nature of the energy markets make it difficult to estimate future prices of oil and gas. WE MAY NOT SUCCESSFULLY INTEGRATE THE OPERATIONS OF THE PROPERTIES WE HAVE ACQUIRED OR MAY ACQUIRE OR ACHIEVE THE BENEFITS WE ARE SEEKING. Our success will partially depend upon the integration of the operations and selected personnel relating to the Floyd Oil Properties and the acquisition of Magellan. Our management team does not have experience with the 14 combined activities of 3TEC, the Floyd Oil Properties and Magellan. In addition, our new management team, including personnel formerly with Magellan and Floyd Oil Company, has not previously worked together as a single team and thus is subject to the personnel and other risks experienced by newly combined operations. We may not be able to integrate these operations without loss of important employees, loss of revenues, increases in operating or other costs, or other difficulties. In addition, we may not be able to realize the operating efficiencies and other benefits sought from our acquisitions. WE MAY NOT BE ABLE TO REPLACE PRODUCTION WITH NEW RESERVES THROUGH OUR DRILLING OR ACQUISITION ACTIVITIES. In general, the volume of production from oil and gas properties declines as reserves are depleted. Our reserves will decline as they are produced unless we acquire properties with proved reserves or conduct successful development and exploration activities. Our future natural gas and oil production is highly dependent upon our level of success in finding or acquiring additional reserves. However, we cannot assure you that our future acquisition, development and exploration activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Our recent growth is due largely to acquisitions of producing properties. The successful acquisition of producing properties requires an assessment of a number of factors. These factors include recoverable reserves, future oil and gas prices, operating costs and potential environmental and other liabilities, title issues and other factors. Such assessments are inexact and their accuracy is inherently uncertain. In connection with such assessments, we perform a review of the subject properties that we believe is generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, the review will not permit a buyer to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Although the increased availability of properties has caused a decrease in the prices paid for these properties, we cannot assure you that we will be able to acquire properties at acceptable prices because the competition for producing oil and gas properties is intense and many of our competitors have financial and other resources which are substantially greater than those available to us. OUR LEVEL OF BORROWINGS MAY MATERIALLY AFFECT OUR OPERATIONS. As of December 31, 1999, our long-term debt was $87.5 million and we had $7.5 million of additional available borrowing capacity under our bank credit facility. The borrowing base limitation under our credit facility is semi- annually redetermined. Upon a redetermination, we could be forced to repay a portion of our bank debt. We may not have sufficient funds to make such repayments. We intend to finance our development, acquisition and exploration activities with cash flow from operations, bank borrowings and other financing activities. In addition, we may significantly alter our capitalization in order to make future acquisitions or develop our properties. These changes in capitalization may significantly increase our level of debt. We may also be able to incur substantial additional indebtedness in the future. If we incur additional debt for these or other purposes, the related risks that we now face could intensify. A higher level of debt also increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of debt depends on our future performance. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. Our level of debt affects our operations in several important ways, including the following: . a portion of our cash flow from operations is used to pay interest on borrowings; . the covenants contained in the agreements governing our debt limit our ability to borrow additional funds, dispose of assets or issue shares of preferred stock and otherwise may affect our flexibility in planning for, and reacting to, changes in business conditions; . a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes; . a leveraged financial position would make us more vulnerable to economic downturns and could limit our ability to withstand competitive pressures; and 15 . any debt that we incur under our credit facility will be at variable rates which makes us vulnerable to increases in interest rates. WE HAVE INCURRED LOSSES FROM OPERATIONS IN THE PAST, AND OUR FAILURE TO ACHIEVE OR SUSTAIN PROFITABILITY IN THE FUTURE COULD ADVERSELY AFFECT THE MARKET PRICE OF OUR COMMON STOCK. We incurred net losses of $4.0 million in 1999 and $6.7 million in 1998. On a pro forma basis, giving effect to the acquisition of the Floyd Oil Properties, we would have earned a profit of $2.4 million for the year ended December 31, 1999, but the pro forma results may not be indicative of actual operating results had we acquired the Floyd Oil Properties at the beginning of the period. We cannot assure you that we will achieve or sustain profitability in the future. Our failure to achieve or sustain profitability in the future could adversely affect the market price of our common stock. PRICES OF OUR COMMON STOCK MAY BE VOLATILE. The market price of our common stock may be subject to significant fluctuations in response to events beyond our control. Normal fluctuations in the prices of our stock may be increased by our trading volumes, which have been historically low. Our trading volumes may be further reduced by the 1-for-3 reverse split of our common stock effected on January 18, 2000. OUR ABILITY TO FINANCE OUR BUSINESS ACTIVITIES WILL REQUIRE US TO GENERATE SUBSTANTIAL CASH FLOW. Our business activities require substantial capital. We have budgeted total capital expenditures for 2000 of approximately $23 million. We intend to finance our capital expenditures in the future through cash flow from operations, the incurrence of additional indebtedness and/or the issuance of additional equity securities. We cannot be sure that our business will continue to generate cash flow at or above current levels. Future cash flow and the availability of financing will be subject to a number of variables, such as: . the level of production from existing wells; . prices of oil and natural gas; . our results in locating and producing new reserves; and . general economic, financial, competitive, legislative, regulatory and other factors beyond our control. If we are unable to generate sufficient cash flow from operations to service our debt, we may have to obtain additional financing. We cannot be sure that any additional financing will be available to us on acceptable terms. Issuing equity securities to satisfy our financing requirements could cause substantial dilution to our existing stockholders. The level of our debt financing could also materially affect our operations. See "Our level of borrowings may materially affect our operations." If our revenues were to decrease due to lower oil and natural gas prices, decreased production or other reasons, and if we could not obtain capital through our credit facility or otherwise, our ability to execute our development and acquisition plans, replace our reserves or maintain production levels could be greatly limited. DRILLING WELLS IS SPECULATIVE, OFTEN INVOLVES SIGNIFICANT COSTS AND MAY NOT RESULT IN ADDITIONS TO OUR PRODUCTION OR RESERVES. Developing and exploring for oil and gas reserves involves a high degree of operating and financial risk. The budgeted costs of drilling, completing and operating wells are often exceeded and can increase significantly when drilling costs rise due to a tightening in the supply of various types of oilfield equipment and related services. Drilling may be unsuccessful for many reasons, including title problems, weather, cost overruns, equipment shortages and mechanical difficulties. Moreover, the successful drilling of an oil or gas well does not ensure a profit on investment. Exploratory wells bear a much greater risk of loss than development wells. A variety of factors, both geological and market-related, can cause a well to become uneconomical or only marginally economic. In addition to their cost, unsuccessful wells can hurt our efforts to replace reserves. 16 WE DO NOT INSURE AGAINST ALL POTENTIAL LOSSES AND COULD BE SERIOUSLY HARMED BY UNEXPECTED LIABILITIES. Exploration for and production of oil and natural gas can be hazardous, involving natural disasters and other unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can damage or destroy wells or production facilities, injure or kill people, and damage property and the environment. Because third party drilling contractors are used to drill our wells, we may not realize the full benefit of workmen's compensation laws in dealing with their employees. We maintain insurance against many potential losses and liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent. However, our insurance does not protect us against all operational risks. ESTIMATES OF OIL AND GAS RESERVES ARE UNCERTAIN AND INHERENTLY IMPRECISE AND ANY MATERIAL INACCURACIES IN THESE RESERVE ESTIMATES WILL MATERIALLY AFFECT THE QUANTITIES AND PV-10 VALUE OF OUR RESERVES. The information herein contains estimates of our proved oil and gas reserves and the estimated future net revenues from such reserves. These estimates are based upon various assumptions, including assumptions required by the Securities and Exchange Commission relating to oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and gas reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Therefore, these estimates are inherently imprecise. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from those estimated. Any significant variance could materially affect the estimated quantities and present value of reserves set forth herein and the information incorporated by reference. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and gas prices and other factors, many of which are beyond our control. Actual production, revenues, taxes, development expenditures and operating expenses with respect to our reserves will likely vary from the estimates used. These variances may be material. At December 31 1999, approximately 18% of our estimated proved reserves were undeveloped. The percentage of proved undeveloped properties were increased as a result of the addition of the Magellan properties. Undeveloped reserves, by their nature, are less certain than developed reserves. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data assumes that we will make significant capital expenditures to develop our reserves. Although we have prepared estimates of our oil and gas reserves and the costs associated with these 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 actual results will be as estimated. In addition, you should not construe PV-10 value as the current market value of the estimated oil and natural gas reserves attributable to our properties. We have based the estimated discounted future net cash flows from proved reserves on prices and costs as of the date of the estimate, in accordance with applicable regulations, whereas actual future prices and costs may be materially higher or lower. Many factors will affect actual future net cash flow, including: . prices for oil and natural gas; . the amount and timing of actual production; . supply and demand for oil and natural gas; . curtailments or increases in consumption by oil and natural gas purchasers; and . changes in governmental regulations or taxation. The timing of the production of oil and natural gas properties and of the related expenses affect the timing of actual future net cash flow from proved reserves and, thus, their actual PV-10 value. In addition, the 10% discount factor, which we are required to use in calculating PV-10 value for reporting purposes, is not necessarily the most appropriate discount factor given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. 17 A SMALL NUMBER OF EXISTING STOCKHOLDERS CONTROL OUR COMPANY, WHICH COULD LIMIT YOUR ABILITY TO INFLUENCE THE OUTCOME OF STOCKHOLDER VOTES. W/E LLC, an affiliate of EnCap and Floyd C. Wilson, our President and Chief Executive Officer, Kaiser-Francis Oil Company, C. J. Lett, III, Weskids, L.P., Alvin V. Shoemaker and EnCap and its affiliates collectively own approximately 68% of our outstanding common stock as of December 31, 1999. These stockholders have entered into an agreement pursuant to which they have agreed to vote all their shares to elect three members of the board of directors designated by W/E LLC and two members of the board of directors designated collectively by Kaiser- Francis Oil Company, C.J. Lett III, Weskids, L.P. and Alvin V. Shoemaker. As a result, these entities will have a significant voice in the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our charter or bylaws and the approval of mergers and other significant corporate transactions so long as they maintain their current holdings of common stock. COMPETITION IN OUR INDUSTRY IS INTENSE, AND WE ARE SMALLER AND HAVE A MORE LIMITED OPERATING HISTORY THAN MANY OF OUR COMPETITORS. We compete with major integrated oil and gas companies and independent oil and gas companies in all areas of operation. In particular, we compete for property acquisitions and for the equipment and labor required to operate and develop these properties. Most of our competitors have substantially greater financial and other resources than we have. In addition, larger competitors may be able to absorb the burden of any changes in federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. These competitors may be able to pay more for exploratory prospects and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment. In addition, most of our competitors have operated for a much longer time than we have and have demonstrated the ability to operate through industry cycles. HEDGING TRANSACTIONS MAY LIMIT OUR POTENTIAL GAINS. In order to manage our exposure to price risks in the marketing of our oil and natural gas production, we have in the past and may in the future enter into oil and gas price hedging arrangements with respect to a portion of our expected production. Our hedging arrangements may include futures contracts on the New York Mercantile Exchange. While intended to reduce the effects of volatile oil and gas prices, such transactions may limit our potential gains if oil and gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which: . our production is less than expected; . there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; . the counterparties to our future contracts fail to perform the contracts; and . a sudden, unexpected event materially impacts oil or gas prices. THE LOSS OF KEY PERSONNEL COULD ADVERSELY AFFECT OUR ABILITY TO OPERATE. Our management changed significantly with W/E LLC's investment. We have three new directors, a new chief executive officer and a number of other new management and professional personnel. Our operations will be dependent upon retaining this group of key management and technical personnel. Recognizing their importance, we have entered into employment agreements with Floyd C. Wilson and Stephen W. Herod. We cannot assure you that such individuals will remain with us for the immediate or foreseeable future. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. WE ARE SUBJECT TO COMPLEX LAWS AND REGULATIONS, INCLUDING ENVIRONMENTAL REGULATIONS, THAT CAN ADVERSELY AFFECT THE COST, MANNER OR FEASIBILITY OF DOING BUSINESS. 18 Our operations are subject to numerous laws and regulations governing the operation and maintenance of our facilities and the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may: . require that we acquire permits before commencing drilling; . restrict the substances that can be released into the environment in connection with drilling and production activities; . limit or prohibit drilling activities on protected areas such as wetlands or wilderness areas; and . require remedial measures to mitigate pollution from former operations, such as plugging abandoned wells. Under these laws and regulations, we could be liable for personal injury and clean-up costs and other environmental and property damages, as well as administrative, civil and criminal penalties. We maintain limited insurance coverage for some but not all of the environmental damages for which we could be liable. Moreover, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability or we may be required to cease production from properties in the event of environmental damages. These laws and regulations have been changed frequently in the past. In general, these changes have imposed more stringent requirements that increase operating costs or require capital expenditures in order to remain in compliance. It is also possible that unanticipated developments could cause us to make environmental expenditures that are significantly different from those we currently expect. Existing laws and regulations could be changed, and any changes could have an adverse effect on our business. 19 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS MARKET INFORMATION Our common stock is currently quoted on the Nasdaq SmallCap Market under the market symbol "TTEN." We have applied for inclusion of the common stock on the Nasdaq National Market. We held a Special Meeting of Shareholders on January 14, 2000, at which meeting our shareholders approved an Amendment to the Company's Certificate of Incorporation which effected a 1-for-3 reverse stock split of our common stock. The reverse stock split became effective on January 18, 2000. Among the reasons we proposed the reverse stock split was an effort to increase the trading price of our common stock to a level above $5 per share, which is the minimum trading price for admission of the common stock for trading on the Nasdaq National Market. Our trading price has remained above $5 per share since January 18, 2000. All share and share related numbers in this report have been prepared, unless otherwise indicated, based on the number of shares outstanding after the reverse split. The following table sets forth the high and low bid prices per share of our common stock for the periods indicated on the Nasdaq SmallCap Market, as reported by the National Quotation Bureau, LLC. The high and low bid amounts for periods prior to January 18, 2000, have been adjusted to reflect the 1-for-3 reverse split of our common stock effective on that date. The bid information below reflects inter-dealer prices, without retail mark-ups, mark-downs or commissions and may not necessarily represent actual transactions.
Period High Low ------ -------- -------- 1998 First Quarter.............................................................. $30.00 $17.25 Second Quarter............................................................. 23.25 15.19 Third Quarter.............................................................. 15.38 9.00 Fourth Quarter............................................................. 9.75 5.25 1999 First Quarter.............................................................. 8.63 4.13 Second Quarter............................................................. 8.06 5.25 Third Quarter.............................................................. 14.44 7.50 Fourth Quarter............................................................. 13.59 7.13 2000 First Quarter (through March 13, 2000)..................................... 10.68 7.50
On March 13, 2000, the last reported sale price of our common stock on the Nasdaq SmallCap Market was $8.00 per share. On March 13, 2000, there were 916 holders of record of our common stock. Our transfer agent is American Stock Transfer and Trust Company located at 40 Wall Street, New York, New York 10005. You may call them toll free at 800-937-5449 to answer any questions about transferring your stock. We have never declared or paid any cash dividends on our common stock. We currently intend to retain future earnings, if any, for the operation and development of our business and do not anticipate paying any cash dividends on our common stock in the foreseeable future. In addition, our credit facility prohibits us from paying cash dividends on our common stock. Any future dividends are also restricted by the terms of our outstanding preferred stock and may be restricted by any debt agreements which we may enter into from time to time. We are obligated to pay net cash dividends in the amount of approximately $570,000 per year on our Series C Preferred Stock and dividends of $740,000 per year on our Series D Preferred Stock which may be paid, at our option, in cash or in additional shares of Series D Preferred Stock during the three years ending February 1, 2003. Our credit facility permits the payment of dividends on our Series C Preferred Stock. We currently do not have a 20 waiver under the credit facility to pay cash dividends on Series D Preferred Stock. However, we expect to pay dividends on the Series D Preferred Stock in additional Series D shares. EQUITY PLACEMENT NOT REGISTERED UNDER THE SECURITIES ACT On October 19, 1999, we closed a transaction exempt under Section 4 of the Securities Act of 1933, as amended (the "Act"), with the Prudential Insurance Company of America ("Prudential"), an accredited investor, pursuant to which Prudential purchased 351,681 shares of our common stock and five-year warrants (the "Warrants") to purchase 266,226 shares of our common stock at an exercise price of $3.00 per share for a total purchase price of $2.4 million. Additionally, we issued Prudential a five-year senior subordinated convertible promissory note in the principal amount of $2,373,844 (the "Note"). The Note is convertible at any time into our common stock at $9.00 per share (a total of 263,760 shares of our common stock). Interest at nine percent (9%) per annum is payable on the Note quarterly. We may defer fifty percent (50%) of the first eight interest payments and add them to the principal due at maturity. The Note is subordinate to our bank credit facility. Prudential (as noteholder) must approve certain changes including changes in the credit facility and corporate structure of 3TEC until the Note is paid. Sixty percent (60%) of the Warrants may be exercised by Prudential at any time. The remaining forty percent (40%) may be exercised incrementally over the five-year term of the Warrants. If the entire principal balance of Note is converted to common stock , all of the outstanding warrants immediately become exercisable. The Warrants may be exercised for cash or reduction of the Note principal. On November 23, 1999, we closed a transaction to purchase properties and interests owned by a group of private accredited investors which were managed by Floyd Oil Company (the "Floyd Oil Properties"). The transaction had an adjusted purchase price of approximately $86.8 million in cash and 503,426 shares of our common stock. The source of the funds used to purchase the Floyd Oil Properties was existing working capital and our credit facility. The transaction was exempt under Section 4 of the Act. ITEM 6. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS You should read the following discussion and analysis in conjunction with our audited consolidated financial statements. The following information contains forward-looking statements. See "Forward-Looking Statements". Overview - -------- We are engaged in the acquisition, development, production and exploration of oil and natural gas reserves. Our properties are concentrated in East Texas and the Gulf Coast region, both onshore and in the shallow waters of the Gulf of Mexico. We also own significant properties in the Permian and San Juan basins and in the Mid-Continent region. Our management and technical staff have substantial experience in each of these areas. As of December 31, 1999, we had estimated total net proved reserves of 218.7 Bcfe, of which approximately 73% were natural gas and approximately 82% were proved developed, with an estimated PV-10 value of $198.6 million. As of December 31, 1999, our net daily production was approximately 38.1 Mmcf of natural gas and 3.1 MBbls of oil or 56.7 Mmcfe. We have increased our reserves and production principally through acquisitions. We focus on properties that have a substantial proved reserve component and which management believes to have additional exploitation opportunities. In early 2000, we acquired a number of drilling prospects covered by an extensive 3-D seismic database that we believe have exploration potential. We have assembled an experienced management team and technical staff with expertise in property acquisitions and development, reservoir engineering, exploration and financial management. Formerly known as Middle Bay Oil Company, Inc., an entity formed under the laws of the state of Alabama in 1992, we underwent a change of control in August 1999, in a transaction in which W/E Energy Company, LLC (formerly 3TEC Energy Company, LLC) invested $21.4 million in cash and oil and gas properties for common stock representing at that time approximately 36% of our then outstanding common stock. Since our formation in 1992, we have grown principally through several acquisitions of proved properties in the Gulf Coast and Mid-Continent regions. Acquisitions made in 1997 and 1998 significantly increased our reserves and production but were primarily nonoperated properties with high per Mcfe lease operating costs. Following the change in control discussed above, during the second half of 1999, we closed several transactions that changed our senior management team, capitalization and our property base. In addition, we added several experienced professionals to our technical staff. Because of these recent transactions, our historical results of operations and cash flows will differ materially from, and will not be representative of, our future results. 21 We increased our asset base substantially and decreased our operating cost per Mcfe on a pro forma basis with the acquisition of the Floyd Oil Properties in November 1999. The Floyd Oil Properties had estimated net proved reserves at December 31, 1999, of 165 Bcfe with a PV-10 value of $146.1 million. On a pro forma basis, the Floyd Oil Properties resulted in additional pro forma EBITDAX of $17.9 million and $20.6 million and additional pro forma revenues of $34.1 million and $33.8 million for the years ended 1998 and 1999, respectively. Compared to our historical operating cost per Mcfe, on a pro forma basis, after giving effect to the Floyd Oil Properties, our total operating cost per Mcfe for the years ended 1998 and 1999 declined 10% and 1% to $0.95 and $0.84, respectively. Compared to our historical general and administrative cost per Mcfe, on a pro forma basis, general and administrative cost per Mcfe for the same periods declined 45% and 50% to $0.32 and $0.30, respectively. Revenues and expenses from the Floyd Oil Properties are included in our historical operating results only for the period from November 23, 1999, the date of acquisition, through December 31, 1999. Additionally, in early 2000 we closed the acquisition of Magellan Exploration, LLC ("Magellan"), which owns primarily proved undeveloped reserves, with significant 3-D seismic data. We plan to fund a development program of Magellan's undeveloped properties, which we believe could increase future reserves and production. In addition, we are continually seeking and reviewing acquisitions of properties and companies which we believe will be accretive to our reserves and production, and expect our acquisition program to continue to be a significant source of growth for us, depending, of course, on the market for oil and gas properties, and industry conditions generally. Certain Accounting Practices - ---------------------------- We use the successful efforts method of accounting for our investments in oil and natural gas properties. Under this method, we capitalize all direct costs incurred in connection with the acquisition, drilling and development of productive oil and natural gas properties. Costs associated with unsuccessful exploration are expensed as incurred. Geological and geophysical costs and costs of carrying and retaining unevaluated properties are expensed as incurred. Depreciation, depletion and amortization of capitalized costs are computed separately for each field based on the unit of production method using only proved oil and gas reserves. We review our oil and gas properties on a field level for impairment when circumstances indicate that the capitalized costs less accumulated depreciation, depletion and amortization (the "Carrying Value") of the property may not be recoverable. If the Carrying Value of the property exceeds the expected future undiscounted cash flows, an amount equal to the excess of the Carrying Value over the fair value of the property is charged to operations. An impairment results in a non-cash charge to earnings but does not affect cash flows. Liquidity and Capital Resources - ------------------------------- CASH FLOW. We believe that our cash flows from operations are adequate to meet the requirements of operating our business. However, future cash flows are subject to a number of variables, including our level of production and prices, and we cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. Our principal operating sources of cash include sales of natural gas and oil. Our pro forma EBITDAX, including the Floyd Oil Properties, for the years ended December 31, 1999 and 1998, was $29.2 million and $21.4 million, respectively. For the year 2000, we have budgeted approximately $23 million for capital expenditures, including an estimated $7 million with respect to the properties acquired in the Magellan acquisition. We are obligated to pay dividends of approximately $570,000 per year on the Series C Preferred Stock in cash and dividends of $740,000 per year on the Series D Preferred Stock which we may pay in either cash or in additional shares of Series D Preferred Stock during the three years ending February 1, 2003. We are obligated to pay interest on the convertible subordinated notes of approximately $1.2 million per year. 22 Our primary source of financing for acquisitions has been borrowing under our credit facility, discussed below. We believe we will have sufficient cash flow from operations and borrowings under our credit facility to meet our obligations and operating needs for the coming year. However, future cash flows are subject to a number of variables, including our level of production and prices, and we cannot assure you that operations and other capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. CREDIT FACILITY. In connection with our acquisition of the Floyd Oil Properties on November 23, 1999, we entered into a credit facility with Bank One, Texas, N.A. and certain other financial institutions. Our then existing bank debt of $26.6 million was paid in full with proceeds from the new facility. The credit facility provides for a borrowing base which is adjusted periodically on the basis of the discounted present value attributable to our proved producing oil and gas reserves, as determined by our lenders. The credit facility currently provides for a $95 million borrowing base. The borrowing base will be redetermined semi-annually on May 1 and November 1 of each year. Interest under the facility accrues at our option at a rate calculated as either the bank's prime rate plus 25 basis points or LIBOR plus basis points increasing from a low of 125 to a high of 187.5 as loans outstanding increase as a percentage of the borrowing base. We are currently paying 7.63% per annum interest on the entire principal balance of the facility of $85 million. The loan matures on November 30, 2002. Prior to maturity, no payments of principal are required so long as the borrowing base exceeds the loan balance. The borrowings under the facility are secured by substantially all of our properties. At December 31, 1999, the amount available to be borrowed under the credit facility was approximately $7.5 million. In connection with this credit facility, we are required to adhere to certain affirmative and negative covenants. The loan agreement contains a number of dividend restrictions and restrictive covenants which, among other things, require the maintenance of minimum current and interest coverage ratios. MARKET RISK. We generally sell our oil at local field prices paid by the principal purchasers of oil. The majority of our natural gas production is sold at spot prices. Accordingly, we are generally subject to the commodity prices for these resources as they vary from time to time. Prices since mid-1998 have generally followed an increasing trend, but the market continues to have considerable volatility. We are engaged in certain hedging transactions with respect to our activities. INFLATION AND CHANGES IN PRICES. Our revenues and the value of our oil and gas properties have been and will be affected by changes in natural gas and crude oil prices. Our ability to maintain current borrowing capacity and to obtain additional capital on attractive terms is also substantially dependent on natural gas and crude oil prices. These prices are subject to significant seasonal and other fluctuations that are beyond our ability to control or predict. During 1999, we received an average of $16.88 per barrel of crude oil and $2.18 per Mcf of gas. Although some costs and expenses are affected by the level of inflation, inflation has not had a significant effect in recent years. Should conditions in the industry continue to improve, causing an increase in competition resulting in a relative shortage of oilfield supplies and/or services, inflationary cost pressures may resume. Results of Operations - --------------------- Our revenue, profitability, and future rate of growth are dependent upon prevailing prices for oil and gas, which, in turn, depend upon numerous factors such as economic, political, and regulatory developments as well as competition from other sources of energy. The energy markets historically have been highly volatile, and future decreases in prices could have an adverse effect on our financial position, results of operations, quantities of reserves that may be economically produced, and access to capital. 23 Due to our significant property and corporate acquisitions in 1999, our 1999 change of control and our current capitalization structure, comparisons of our historical financial position and results of operations from 1998 to 1999 are not meaningful. You should read the following discussion and analysis together with our audited consolidated financial statements and the related notes for the fiscal years ended December 31, 1999 and 1998. 1999 Compared With 1998 - ----------------------- REVENUE. Total revenue for the year ended December 31, 1999, was $22.0 million, an increase of $4.3 million (24%) over total revenue for 1998. Natural gas revenues for the 1999 period were $10.3 million, approximately 34% higher than 1998 natural gas revenues of $7.7 million. Natural gas production volumes increased 23% in 1999; oil production volumes decreased by approximately 9%, principally as a result of property sales during the period. Oil revenues for the 1999 period were $8.9 million, approximately 33% higher than 1998 oil revenues of $6.7 million. Gas plant and other product sales revenue of $648,000 increased 2% from $632,000 in 1998. Average natural gas sale prices increased 9% from the 1998 to the 1999 period, while oil prices increased 46% during the same period. For 1999, approximately 52% of the dollar amount of our product sales were natural gas. In addition, production from the Floyd Oil Properties from the date of acquisition (November 23, 1999) to year-end contributed approximately $4.5 million (approximately 20%) to our total revenues in the 1999 period. GAIN ON PROPERTY SALES, INTEREST AND OTHER INCOME. In 1999 and 1998, our property divestment resulted in gains of $1.0 million and $1.9 million, respectively. Other income for 1999 of $1.0 million, consisted principally of interest income and a lawsuit settlement EXPENSES. Total expenses for the year ended December 31, 1999 were $26.9 million, a slight decrease over the $27.1 million in 1998. Comparability of total expenses was affected by certain non-recurring expenses in 1999 of $1.7 million and additional expenses of $2.3 million attributable to the properties acquired in the Floyd Oil Acquisition. Lease operating expense of $6.7 million or approximately $0.85 per Mcfe, decreased by approximately $1.1 million from the 1998 period, reflecting the effect of property sales. Depreciation and depletion expense was $6.7 million, or approximately $0.84 per Mcfe, compared to $7.1 million or approximately $0.97 per Mcfe for 1998. An increase in depletion due to the properties acquired in the Floyd Oil Company Acquisition was offset by lower depletion due to impairments, property sales and lower production on properties owned the entire period of 1999. Impairment expense for 1999, was approximately $2.5 million, relating to impairments on fee mineral acreage, non- producing leasehold and proved oil and gas properties. More specifically, 1999 impairments were related to certain fee mineral acreage that reverted to the landowners, management's decision not to participate in additional exploration on certain prospects and new reserve engineers employed by us resulted in valuation changes on certain proved properties. The impairment expense in 1998 was principally attributable to decreasing oil prices. General and administrative expense was $4.7 million, or approximately $0.60 per Mcfe, compared to $4.3 million or approximately $0.58 per Mcfe for 1998. The general and administrative expense increase was primarily the result of increases in salary, legal and consulting expenses in 1999 offset partially by declines in certain expenses due to the closing of the Enex offices in Kingwood, Texas. Interest expense of $3.2 million, increased $1.23 million (62%) in the 1999 period, the increase reflecting increased borrowings under our credit facility for acquisitions. The non-recurring expense of $1.7 million was triggered by the change of control resulting from the sale of securities to W/E LLC and consists of stock compensation expense of $730,000, severance payment of $624,000, compensation plan payment of $292,000 and other expenses of $60,000. NET LOSS. The net loss for 1999 was approximately $3.4 million compared to a loss of approximately $6.6 million in 1998. The current period net loss decreased primarily as a result of the increased income from oil and natural gas and the lower depletion and impairment expenses. DIVIDENDS TO PREFERRED STOCKHOLDERS. Dividends to preferred stockholders of approximately $574,000 in 1999 increased 745% over 1998. The increase was due to the dividends on the Series C Preferred Stock that began to accrue dividends on December 31, 1998 and the conversion of the Series A Preferred Stock to common on January 31, 1998. 1998 COMPARED WITH 1997 For the year ended December 31, 1998, the revenues and expenses attributable to the acquisition of Enex Corp. and Enex LP are included for the period April through December, and those attributable to the Service Drilling acquisition are included for the months of May through December. For the comparable 1997 period, the revenues and expenses attributable to the acquisition of Bison Energy Corporation ("Bison") are included for the period March through December, the acquisition of Shore Oil Company ("Shore") for the period July through December, and the acquisition of properties in the Riceville Field in Vermillion Parish, Louisiana ("Riceville"), for the period August through December. 24 REVENUES. Total revenues for the year ended December 31, 1998, of $17,702,000, were $6,270,000 higher than the comparable 1997 period. The increase in total revenues was primarily the result of higher oil and gas revenues of $4,798,000 and higher gain on the sale of properties. During the year ended December 31, 1998, lease bonus and rental income on the mineral acreage acquired in the acquisition of Shore decreased $758,000 and other revenues increased $283,000 as compared to the 1997 period. Oil and gas revenues of $15,011,000 for the year ended December 31, 1998, increased $4,798,000, consisting of a $1,574,000 increase in oil revenues, a $3,071,000 increase in gas revenues and a $153,000 increase in other revenues. The increase in oil and gas revenues was the result of a 105% increase in oil production and a 99% increase in gas production as compared to the comparable 1997 period. The production increases were primarily the result of the acquisition of Riceville which closed in 1997, and the acquisitions of Enex Corp. and Service Drilling, which both closed in 1998. The gain on the sale of properties of $1,953,000 for the year ended December 31, 1998, was primarily the result of sales of non-strategic properties and was $1,946,000 higher than the comparable 1997 period. Other income decreased $474,000. We received $217,000 in lease bonus and delay rental income on the fee mineral acreage acquired in the acquisition of Shore in the year ended December 31, 1998, versus $975,000 in the comparable 1997 period. A decrease in leasing activity was the primary reason for the decline in income. This decrease was offset by other income in the year ended December 31, 1998, which increased over the comparable 1997 periods primarily as the result of a lawsuit settlement and an accounts payable settlement. COSTS AND EXPENSES. Total expenses for the year ended December 31, 1998, of $27,106,000 were $7,351,000 lower than the comparable 1997 period primarily as the result of a decrease of $16,984,000 in impairment charge to $4,164,000 versus $21,148,000 in the comparable 1997 period. The lower impairment charge was partially offset by a $3,953,000 increase in lease operating expenses, a $2,549,000 increase in depreciation, depletion and amortization, and a $1,906,000 increase in general and administrative expenses. Lease operating expenses of $7,801,000 increased by $3,952,000. The increase was primarily the result of expenses associated with the properties acquired in the Enex Corp. and Service Drilling acquisitions. G&G expenses increased $655,000. The primary G&G expenses in the current period include approximately $716,000 on the Hawkins Ranch Prospect and $135,000 on the Sherburne Prospect. Dry hole expense of $503,000 decreased by $616,000 for the year ended December 31, 1998 as a result of a decrease in drilling activity. The dry hole costs in the year ended December 31, 1998, were primarily the result of abandonment costs on two unsuccessful wells. Depreciation, depletion and amortization expense of $7,116,000 increased by $2,549,000 for the year ended December 31, 1998. Depreciation, depletion and amortization expense increased primarily as a result of the depletion associated with the properties acquired in the Enex Corp. and Service Drilling acquisitions. The impairment expense for the year ended December 31, 1998, of $4,164,000 was primarily attributable to oil and gas property impairments of $4,092,000 due to a decline in oil prices and an unsuccessful recompletion. Interest expense of $1,972,000 for the year ended December 31, 1998, increased by $1,301,000 as a result of a higher loan balance resulting from funds borrowed to finance the Enex Corp. acquisition in March and to partially finance the Service Drilling acquisition in April. Stock compensation of $266,000 increased by $64,000 for the year ended December 31, 1998, as the result of the grant of a warrant to purchase 25,000 shares of our common stock to a consultant. The warrant fully vested on January 1, 1999, and was expensed in the current period. 25 General and administrative expenses of $4,267,000 increased by $1,906,000, primarily as a result of higher salary expense of $752,000, higher professional fees of $310,000 and higher office expenses of $195,000. The increase in salary expense was the result of increases in salaries of existing employees and salaries of new employees. The increase in professional fees was the result of higher accounting and engineering expenses related to a change in auditors and increased reserve report requirements. Other expenses of $139,000 for the year ended December 31, 1998, decreased $179,000 over the comparable 1997 period. The decrease primarily reflects a reduction in 1998 in the level of integration expense associated with the Bison and Shore mergers which closed in 1997. OPERATING LOSS AND NET LOSS. We reported an operating loss before minority interest of $9,404,000 for the year ended December 31, 1998, compared to an operating loss of $23,025,000 in the comparable 1997 period. The operating loss decreased primarily due to lower dry hole and impairment expenses. As a result of the acquisition of Enex Corp., we recorded a minority interest on our income statement to remove the net income or loss attributable to the minority interest owners of Enex Corp. For the year ended December 31, 1998, the minority interest increased the operating loss by $15,000. We did not have a minority interest in the comparable period. We reported an income tax benefit of $2,830,000 for the year ended December 31, 1998, as compared to an income tax benefit of $7,445,000 in the comparable 1997 period. We reported a net loss of $6,589,000 for year ended December 31, 1998, as compared to a net loss of $15,580,000 for the comparable 1997 period. We paid preferred dividends of $68,000 for the year ended December 31, 1998, and $605,000 in the comparable 1997 period and reported a net loss to common stockholders of $6,657,000 for the year ended December 31, 1998, as compared to a net loss to common stockholders of $16,185,000 in the comparable 1997 period. 26 ITEM 7. FINANCIAL STATEMENTS The Consolidated Financial Statements that constitute this item follow the text of this report. An index to the Consolidated Financial Statements and Schedules appears in Item 13 of this report. ITEM 8. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE In April 1998, as part of our annual consideration and selection of independent accountants, we decided not to engage Schultz, Watkins & Company, who had served as our independent certified public accountants since 1993, and retained KPMG LLP to serve as our independent certified public accountants. Management had no disagreement with Schultz, Watkins & Company on any material matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure. Schultz, Watkins & Company's report on our financial statements for 1997 did not contain an adverse opinion or a disclaimer of opinion and was not qualified or modified as to uncertainty, audit scope or accounting principles. PART III ITEM 9. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by this Item is incorporated by reference from the Company's Proxy Statement for the 2000 Annual Meeting of Stockholders. 27 ITEM 10. EXECUTIVE COMPENSATION The information required by this Item is incorporated by reference from the Company's Proxy Statement for the 2000 Annual Meeting of Stockholders. ITEM 11. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by this Item is incorporated by reference from the Company's Proxy Statement for the 2000 Annual Meeting of Stockholders. ITEM 12. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required by this Item is incorporated by reference from the Company's Proxy Statement for the 2000 Annual Meeting of Stockholders. ITEM 13. 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: 2.1 Agreement and Plan of Merger, dated November 24, 1999, by and between 3TEC Energy Corporation, a Delaware corporation and Middle Bay Oil Company, Inc., an Alabama corporation (Incorporated by reference to Exhibit A to the definitive Proxy Statement of Middle Bay Oil Company, Inc., filed October 25, 1999 (Commission File No. 0-21702) (Incorporated by reference to Exhibits to Form 8-K filed December 6, 1999.) 2.2 Form of Purchase Agreement between and among Middle Bay Oil Company, Inc. and private sellers of the properties managed by Floyd Oil Company (Incorporated by reference to Exhibits to Form 8-K filed December 7, 1999.) 2.3 Real Estate Exchange Agreement by and between Middle Bay Oil Company, Inc. and Floyd Oil Company (Incorporated by reference to Exhibits to Form 8-K/A filed December 17, 1999.) 2.4 Certificate of Merger of Middle Bay Oil Company, Inc. into 3TEC Energy Corporation (Incorporated by reference to Form 8-K/A filed December 16, 1999.) 3.1 Certificate of Incorporation of 3TEC Energy Corporation (Incorporated by reference to Exhibits to Form 8-K/A filed December 6, 1999.) 3.2 Bylaws of the Company (Incorporated by reference to Exhibit C of the Company's definitive proxy statement filed October 25, 1999.) 3.3 Certificate of Amendment to the Certificate of Incorporation of 3TEC Energy Corporation. * 4.1 Certificate of Designation of Series B Preferred Stock of 3TEC Energy Corporation (Incorporated by reference to Form 8-K/A filed December 16, 1999.) 4.2 Certificate of Designation of Series C Preferred Stock of 3TEC Energy Corporation (Incorporated by reference to Form 8-K/A filed December 16, 1999.) 28 4.3 Certificate of Designation of Series D Preferred Stock of 3TEC Energy Corporation (Incorporated by reference to Form 8-K/A filed December 16, 1999.) 10.1 Securities Purchase Agreement, dated July 1, 1999 by and between the Company and 3TEC Energy Corporation (Incorporated by reference to Exhibits to definitive Proxy Statement filed July 19, 1999.) 10.2 Securities Purchase Agreement, dated August 27, 1999 by and between the Company and Shoemaker Family Partners, LP (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.3 Securities Purchase Agreement, dated August 27, 1999 by and between the Company and Shoeinvest II, LP (Incorporated by reference to Exhibits to Form 10- QSB filed November 15, 1999.) 10.4 Securities Purchase Agreement, dated October 19, 1999 between The Prudential Insurance Company of America and the Company (Incorporated by reference to Exhibits to Form 8-K filed November 2, 1999.) 10.5 Shareholders Agreement, dated August 27, 1999 by and among the Company, 3TEC Energy Corporation and the Major Shareholders (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.6 Registration Rights Agreement, dated August 27, 1999 by and among the Company, 3TEC Energy Corporation, the Major Shareholders, Shoemaker Family Partners, LP and Shoeinvest II, LP (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.7 Amendment to Registration Rights Agreement, dated October 19, 1999 by and among the Company, W/E Energy Company, L.L.C. f/k/a 3TEC Energy Company L.L.C., f/k/a 3TEC Energy Corporation, Shoemaker Family Partners, LP, Shoeinvest II, LP, and The Prudential Insurance Company of America (Incorporated by reference to Exhibits to Form 8-K filed November 2, 1999.) 10.8 Participation Rights Agreement, dated October 19, 1999 by and among the Company, The Prudential Insurance Company of America and W/E Energy Company L.L.C. (Incorporated by reference to Exhibits to Form 8-K filed November 2, 1999.) 10.9 Employment Agreement, dated August 27, 1999 by and between Floyd C. Wilson and the Company (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.10 Employment Agreement, dated August 27, 1999 by and between John J. Bassett and the Company (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.11 Credit Agreement, dated March 27, 1998 by and among the Company, Compass Bank, and Bank of Oklahoma, National Association (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.12 First Amendment to Credit Agreement, dated August 27, 1999 by and among the Company, Compass Bank, and Bank of Oklahoma, National Association (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.13 Second Amendment to Credit Agreement, dated October 19, 1999 by and among the Company, Compass Bank, and Bank of Oklahoma, National Association (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.14 Subordination Agreement, dated August 27, 1999 by and between 3TEC Energy Corporation, Compass Bank, and Bank of Oklahoma, National Association (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.15 Subordination Agreement, dated August 27, 1999 by and among Shoemaker Family Partners, LP, Compass Bank, and Bank of Oklahoma, National Association (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 29 10.16 Subordination Agreement, dated August 27, 1999 by and among Shoeinvest II, LP, Compass Bank, and Bank of Oklahoma, National Association (Incorporated by reference to Exhibits to Form 10-QSB filed November 15, 1999.) 10.17 Letter Amendment No. 1 to Middle Bay Oil Company, Inc. Securities Purchase Agreement dated November 23, 1999, by and between Middle Bay Oil Company, Inc. (n/k/a 3TEC Energy Corporation) and The Prudential Insurance Company of America (replacing the unexecuted Exhibit 10.17 of Form 10-QSB filed November 15, 1999). 10.18 Restated Credit Agreement by and among Middle Bay Oil Company, Inc., Enex Resources Corporation and Middle Bay Production Company, Inc. as borrowers, and Bank One, Texas, N.A. and other institutions as lenders. (Incorporated by reference to Exhibits to Form 8-K filed December 17, 1999.) 27.1 Financial Data Schedule * * Filed herewith (b) The following reports were filed on Form 8-K during the fourth quarter of 1999: On October 22, 1999, the Company filed a Form 8-K under Item 5 describing a letter of intent to purchase oil and gas properties and interests, managed by Floyd Oil Company, from a group of private sellers. On November 2, 1999, the Company filed a Form 8-K under Item 5 describing the sale of securities to The Prudential Insurance Company of America. On December 6, 1999, the Company filed a Form 8-K under Items 5 and 7 describing the agreement and plan of merger between Middle Bay Oil Company, Inc. and 3TEC Energy Corporation. On December 7, 1999, the Company filed a Form 8-K under Items 2, 5 and 7 describing the acquisition of assets, managed by Floyd Oil Company, from a group of private sellers and the closing of a new credit facility with Bank One, Texas, N.A. On December 16, 1999, the Company filed an amendment under Item 7 to the Form 8-K originally filed on December 6, 1999 describing the designation of the Series B and Series C Preferred Stocks and the Certificate of Merger between Middle Bay Oil Company, Inc. and 3TEC Energy Corporation. On December 17, 1999, the Company filed an amendment under Item 7 to the Form 8-K originally filed on December 7, 1999 describing the real estate exchange agreement between Middle Bay Oil Company, Inc. and Floyd Oil Company and the restated credit agreement by and among Middle Bay Oil Company, Inc., Enex Resources Corporation, Middle Bay Production Company and Bank One, Texas, N.A. and other institutions. 30 INDEX TO FINANCIAL STATEMENTS
Page ---- Report of Independent Auditors........................................... F-2 Consolidated Balance Sheets as of December 31, 1999 and 1998............. F-3 Consolidated Statements of Operations for the years ended December 31, 1999 and 1998........................................................... F-4 Consolidated Statements of Cash Flows for the years ended December 31, 1999 and 1998........................................................... F-5 Consolidated Statements of Changes in Stockholders' Equity for the years ended December 31, 1999 and 1998........................................ F-6 Notes to Consolidated Financial Statements............................... F-7
INDEPENDENT AUDITORS' REPORT The Board of Directors and Stockholders 3TEC Energy Corporation: We have audited the accompanying consolidated balance sheets of 3TEC Energy Corporation (formerly Middle Bay Oil Company, Inc.) and subsidiaries as of December 31, 1999 and December 31, 1998 and the related consolidated statements of operations, changes in stockholders' equity, and cash flows for each of the years then ended. 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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of 3TEC Energy Corporation and subsidiaries as of December 31, 1999 and 1998, and the results of their operations and their cash flows for each of the years then ended in conformity with generally accepted accounting principles. KPMG LLP Houston, Texas February 25, 2000 F-2 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, December 31, 1999 1998 ------------ ------------ ASSETS CURRENT ASSETS Cash and cash equivalents........................ $ 6,141,153 $ 1,040,096 Accounts receivable.............................. 9,453,551 3,309,043 Accounts receivable-Insurance Claim.............. -- 448,083 Other current assets............................. 176,226 141,364 ------------ ----------- Total current assets............................ 15,770,930 4,938,586 PROPERTY (AT COST) Oil and gas-successful efforts method............ 168,840,499 90,849,439 Other............................................ 1,141,879 795,323 ------------ ----------- 169,982,378 91,644,762 Accumulated depreciation, depletion and amortization...................................... (38,208,298) (39,073,584) ------------ ----------- 131,774,080 52,571,178 OTHER ASSETS....................................... 1,698,496 431,053 ------------ ----------- TOTAL ASSETS....................................... $149,243,506 $57,940,817 ============ =========== LIABILITIES AND STOCKHOLDERS' EQUITY CURRENT LIABILITIES Accounts payable-trade........................... $ 5,726,569 $ 3,643,241 Accounts payable-Enex LP Dissenters and Fractional Shares............................... -- 538,750 Revenue payable.................................. 1,576,731 342,931 Accounts payable-Stockholder Dissenters.......... 1,118,678 -- Other current liabilities........................ 347,733 275,010 ------------ ----------- Total current liabilities....................... 8,769,711 4,799,932 LONG-TERM DEBT..................................... 87,500,000 27,454,567 SENIOR SUBORDINATED CONVERTIBLE NOTES.............. 13,223,844 -- DEFERRED INCOME TAXES.............................. 290,643 1,733,167 OTHER LIABILITIES.................................. 257,627 437,949 MINORITY INTEREST.................................. 1,089,044 957,369 STOCKHOLDERS' EQUITY Preferred stock, $0.02 par, 20,000,000 shares authorized, 266,667 designated Series B and 2,300,000 shares designated Series C, none other designated...................................... -- -- Convertible preferred stock Series B, $7.50 stated value, 266,667 shares issued and outstanding. $2,000,000 aggregate liquidation preference...................................... 3,627,000 3,627,000 Convertible preferred stock Series C, $5.00 stated value, 1,139,506 and 1,142,663 shares issued and outstanding at December 31, 1999 and December 31, 1998, respectively. $5,697,530 aggregate liquidation preference................ 5,198,440 5,281,937 Common stock, $.02 par value, 60,000,000 shares authorized, 5,338,771 and 2,850,655 shares issued at December 31, 1999 and December 31, 1998, respectively.............................. 106,778 57,016 Additional paid-in capital....................... 57,775,199 37,061,627 Accumulated deficit.............................. (27,408,062) (23,401,707) Treasury stock; 7,258 shares..................... (1,186,718) (68,040) ------------ ----------- TOTAL STOCKHOLDERS' EQUITY...................... 38,112,637 22,557,833 COMMITMENTS AND CONTINGENCIES ------------ ----------- TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY......... $149,243,506 $57,940,817 ============ ===========
See accompanying notes to consolidated financial statements. F-3 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31, ------------------------ 1999 1998 ----------- ----------- REVENUE Oil and gas sales and plant income................ $19,951,750 $15,011,354 Gain on sale of properties........................ 1,047,860 1,953,362 Delay rental and lease bonus income............... 64,911 217,404 Other............................................. 955,545 520,458 ----------- ----------- TOTAL REVENUE................................... 22,020,066 17,702,578 ----------- ----------- COSTS AND EXPENSES Lease operating, production taxes and plant costs............................................ 6,727,948 7,801,249 Geological and geophysical........................ 199,499 877,643 Dry hole costs.................................... 624,780 503,444 Depreciation, depletion and amortization.......... 6,690,961 7,116,116 Impairments....................................... 2,477,980 4,164,184 Interest.......................................... 3,204,768 1,971,595 Stock compensation................................ 729,938 266,445 Severance payment................................. 624,420 -- Compensation plan payment......................... 292,527 -- General and administrative........................ 4,735,723 4,266,727 Other............................................. 583,998 138,855 ----------- ----------- TOTAL COSTS AND EXPENSES........................ 26,892,542 27,106,258 LOSS BEFORE INCOME TAX BENEFIT, MINORITY INTEREST AND DIVIDENDS TO PREFERRED STOCKHOLDERS............ (4,872,476) (9,403,680) Minority Interest................................... 2,323 15,089 Income tax benefit.................................. (1,442,524) (2,829,762) ----------- ----------- NET LOSS............................................ (3,432,275) (6,589,007) Dividends to preferred stockholders................. 574,080 67,945 ----------- ----------- NET LOSS ATTRIBUTABLE TO COMMON STOCKHOLDERS........ $(4,006,355) $(6,656,952) =========== =========== NET LOSS PER COMMON SHARE, basic and diluted........ $ (1.14) $ (2.48) =========== =========== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING, basic and diluted........................................ 3,519,532 2,683,369 =========== ===========
See accompanying notes to consolidated financial statements. F-4 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Years Ended December 31, -------------------------- 1999 1998 ------------ ------------ OPERATING ACTIVITIES Net loss........................................... $ (3,432,275) $ (6,589,007) Adjustments to reconcile net loss to net cash provided by operating activities Depreciation, depletion and amortization.......... 6,690,961 7,116,116 Impairments....................................... 2,477,980 4,164,184 Dry hole costs.................................... 624,780 503,444 Stock compensation expense........................ 729,938 266,445 Gain on sale of properties........................ (1,047,860) (1,953,362) Deferred income taxes............................. (1,442,524) (2,829,762) Minority interest................................. 2,323 15,089 Other charges..................................... 377,885 20,000 ------------ ------------ Cash flow from operations before changes in current assets and liabilities............................ 4,981,208 713,147 Changes in current assets and liabilities net of acquisition effects: Increase in accounts receivable and other current assets........................................... (5,852,041) (185,887) Increase in accounts payable, revenue payable and other current liabilities........................ 2,272,159 1,541,025 ------------ ------------ NET CASH PROVIDED BY OPERATING ACTIVITIES....... 1,401,326 2,068,285 INVESTING ACTIVITIES Payment for acquisition of 80% of Enex Corp., net of cash acquired of $4,698,211................... -- (11,403,189) Payment for acquisition of assets of Service Drilling Co., LLC................................ -- (6,328,208) Payment for acquisition of assets managed by Floyd Oil Company...................................... (82,829,903) -- Proceeds from sales of oil and gas properties..... 6,230,420 4,812,326 Proceeds from sales of other assets............... 13,363 390,927 Additions to oil and gas assets................... (3,449,083) (4,100,252) Additions to other assets......................... (509,773) (322,816) Payments from (advances to) stockholder........... 173,115 (6,950) ------------ ------------ NET CASH USED IN INVESTING ACTIVITIES........... (80,371,861) (16,958,162) FINANCING ACTIVITIES Proceeds from issuance of debt.................... 91,036,000 32,469,604 Proceeds from issuance of senior subordinated convertible notes................................ 13,223,844 -- Proceeds from issuance of common stock............ 12,465,591 -- Principal payments on debt........................ (30,990,568) (16,105,287) Preferred stock dividends......................... (245,029) (67,945) Partnership distributions......................... -- (1,348,098) Debt, common stock and preferred stock issue and registration costs............................... (1,418,246) (605,485) ------------ ------------ NET CASH PROVIDED BY FINANCING ACTIVITIES....... 84,071,592 14,342,789 Net increase (decrease) in cash and cash equivalents....................................... 5,101,057 (547,088) Cash and cash equivalents-Beginning................ 1,040,096 1,587,184 ------------ ------------ Cash and cash equivalents-Ending................... $ 6,141,153 $ 1,040,096 ============ ============ SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash paid during the year for: Interest.......................................... $ 3,269,354 $ 1,657,362 ============ ============ Income taxes...................................... -- -- ============ ============ Non-cash investing and financing activities: Preferred dividends incurred but not paid......... $ 329,051 -- ============ ============ Common stock issued for acquisition of oil and gas properties from W/E LLC.......................... $ 875,000 -- ============ ============ Common stock repurchase contingency accrual....... $ 1,118,678 -- ============ ============ Common stock issued in asset acquisition from Floyd Oil Company................................ $ 6,992,587 -- ============ ============ Common stock issued as finders fee in Enex Resources Corp. tender offer..................... -- $ 245,232 ============ ============ Common stock issued in asset acquisition from Service Drilling Corp., LLC...................... -- $ 3,554,774 ============ ============ Present value of consulting agreement of former president of Enex Resources Corp................. -- $ 788,563 ============ ============ Preferred stock issued in acquisition of Enex Consolidated Partners, LP........................ -- $ 5,713,317 ============ ============
See accompanying notes to consolidated financial statements. F-5 3TEC ENERGY CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 1999 AND 1998
Preferred Stock ----------------------------------------------------------------- Series A Series B Series C Common Stock Unearned ----------------------- ------------------ --------------------- ------------------- Paid-in Stock Shares Par Shares Par Shares Par Shares Par Capital Compensation ---------- ----------- ------- ---------- --------- ---------- --------- -------- ----------- ------------ Balance January 1, 1998......... 1,666,667 10,000,000 266,667 3,627,000 -- -- 1,506,269 30,128 23,089,563 (67,500) Preferred Series A conversion.... (1,666,667) (10,000,000) 1,111,111 22,222 9,977,778 Common shares issued as finders fee in Enex Corp. tender offer.... 11,275 226 245,006 Asset acquisition of Service Drilling Co., LLC........ 222,000 4,440 3,550,334 Restricted stock awards earned... 67,500 Warrant issued as compensation. 198,946 Preferred Series C issued in Enex Consolidated Partners, LP acquisition..... 1,142,663 5,713,317 Preferred Series C registration costs........... -- (431,380) Net Loss........ Preferred stock dividends....... ---------- ----------- ------- ---------- --------- ---------- --------- -------- ----------- ------- Balance January 1, 1999......... -- -- 266,667 3,627,000 1,142,663 5,281,937 2,850,655 57,016 37,061,627 -- Preferred Series C registration costs........... (67,711) Common stock and warrants issued to 3TEC Energy Company, LLC.... 1,585,185 31,703 10,668,297 Common stock and warrants issued to related party........... 22,222 444 149,556 Common stock and warrants issued to The Prudential Insurance Co. of America......... 351,680 7,034 2,366,810 Common stock issued in asset acquisition from Floyd Oil Company......... 503,426 10,069 6,982,518 Stockholder dissenters repurchase contingency..... Common stock registration costs........... (365,571) Preferred Series C conversions... (13,157) (65,786) 4,103 82 65,704 Preferred Series C issued as consulting fee.. 10,000 50,000 Employee stock option plan expense......... 729,938 Employee stock option exercises....... 21,500 430 116,320 Net Loss........ Preferred stock dividends....... ---------- ----------- ------- ---------- --------- ---------- --------- -------- ----------- ------- Balance December 31, 1999............ -- $ -- 266,667 $3,627,000 1,139,506 $5,198,440 5,338,771 $106,778 $57,775,199 $ -- ========== =========== ======= ========== ========= ========== ========= ======== =========== ======= Accumulated Treasury Stockholders' Deficit Stock Equity ------------- ------------ ------------- Balance January 1, 1998............ (16,744,755) (68,040) 19,866,396 Preferred Series A conversion.... -- Common shares issued as finders fee in Enex Corp. tender offer.... 245,232 Asset acquisition of Service Drilling Co., LLC........ 3,554,774 Restricted stock awards earned... 67,500 Warrant issued as compensation.... 198,946 Preferred Series C issued in Enex Consolidated Partners, LP acquisition..... 5,713,317 Preferred Series C registration costs........... (431,380) Net Loss........ (6,589,007) (6,589,007) Preferred stock dividends....... (67,945) (67,945) ------------- ------------ ------------- Balance January 1, 1999............ (23,401,707) (68,040) 22,557,833 Preferred Series C registration costs........... (67,711) Common stock and warrants issued to W/E Energy Company, LLC.... 10,700,000 Common stock and warrants issued to related party........... 150,000 Common stock and warrants issued to The Prudential Insurance Co. of America......... 2,373,844 Common stock issued in asset acquisition from Floyd Oil Company......... 6,992,587 Stockholder dissenters repurchase contingency..... (1,118,678) (1,118,678) Common stock registration costs........... (365,571) Preferred Series C conversions... -- Preferred Series C issued as consulting fee.. 50,000 Employee stock option plan expense......... 729,938 Employee stock option exercises....... 116,750 Net Loss........ (3,432,275) (3,432,275) Preferred stock dividends....... (574,080) (574,080) ------------- ------------ ------------- Balance December 31, 1999........ $(27,408,052) $(1,186,718) $38,112,637 ============= ============ =============
See accompanying notes to consolidated financial statements. F-6 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS December 31, 1999 and 1998 (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization 3TEC Energy Corporation (the Company), formerly Middle Bay Oil Company, Inc., was incorporated under the laws of the state of Alabama on November 20, 1992. The Company was reincorporated in Delaware on December 7, 1999 and changed its name to 3TEC Energy Corporation. The reincorporation and name change were part of a series of transactions related to a securities purchase agreement that closed on August 27, 1999 between the Company and W/E Energy Company, LLC ("W/E LLC"), formerly known as 3TEC Energy Company, LLC, whereby the Company received $21.4 million in cash and oil and natural gas properties for the sale of common stock, warrants and debt securities (See Note 3). Effective March 27, 1998, the Company acquired 79.2% of Enex Resources Corporation ("Enex") and over a three week period ending December 23, 1998, the Company acquired an additional 0.80% of Enex for a total 80% of Enex. Effective April 16, 1998, the Company acquired the oil and gas assets of Service Drilling Co., LLC ("Service Drilling"). Effective October 1, 1998, the Company acquired 100% of Enex Consolidated Partners, L.P. ("Enex Partnership"), a limited partnership of which Enex owned greater than a 50% interest. Effective November 23, 1999, the Company acquired oil and natural gas properties and interests managed by Floyd Oil Company ("Floyd Oil Company ") from a group of private sellers. The Company is engaged in the acquisition, development, production and exploration of oil and natural gas in the contiguous United States. The Company considers its business to be a single operating segment. Significant Accounting Policies The Company's accounting policies reflect industry standards and conform to generally accepted accounting principles. The more significant of such policies are described below. Principles of Consolidation The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries and Enex, an 80% owned subsidiary. The equity of the minority interests in Enex is shown in the consolidated financial statements as "minority interest". All significant intercompany balances and transactions have been eliminated in consolidation. Cash and Cash Equivalents For purposes of the statements of cash flows, the Company classifies all cash investments with original maturities of three months or less as cash. Oil and Gas Property The Company follows the successful efforts method of accounting for oil and natural gas properties, and accordingly, capitalizes all direct costs incurred in connection with the acquisition, drilling and development of productive oil and natural gas properties. Costs associated with unsuccessful exploration are charged to expense currently. Geological and geophysical costs and costs of carrying and retaining unevaluated properties are charged to expense. Depreciation, depletion and amortization of capitalized costs are computed separately for each field based on the unit-of-production method using only proved oil and natural gas reserves. In arriving at such rates, commercially recoverable reserves have been estimated by independent petroleum engineering firms. The Company reviews its undeveloped properties continually and charges them to expense on a property by F-7 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 property basis when it is determined that they have been condemned by dry holes, or have otherwise diminished in value. The Company recorded impairments of $1.5 million on its undeveloped properties, principally fee minerals and non-producing leasehold costs, for the year ended December 31, 1999. Gains and losses are recorded on sales of interests in proved properties and on sales of entire interests in unproved properties. For the years ended December 31, 1999 and 1998, the Company realized gains on sales of properties of $1.0 million and $2.0 million, respectively. Proved oil and natural gas reserves are the estimated quantities of oil, natural gas and natural gas liquids which are expected to be recoverable in future years from known reservoirs under existing economic and operating conditions. Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation tests. The Company reviews long-lived assets for impairment when events or changes in circumstances indicate that the carrying value of such an asset may not be recoverable. This review consists of a comparison of the carrying value of the asset to the asset's expected future undiscounted cash flows. Estimates of expected future cash flows represent management's best estimate based on reasonable and supportable assumptions and projections. If the expected future cash flows, assuming escalated prices, are less than the carrying value of the asset, an impairment exists and is measured as the excess of the carrying value over the estimated fair value of the asset. The Company estimates discounted future net cash flows to determine fair value. Any impairment provisions recognized are permanent and may not be restored in the future. For the years ended December 31, 1999 and 1998, the Company's proved properties were assessed for impairment on an individual field basis and the Company recorded impairment provisions on certain producing properties of $1.0 million and $4.1 million, respectively. Site Restoration, Dismantlement and Abandonment Costs Site restoration, dismantlement and abandonment costs (P&A costs) are common in the oil and natural gas industry. P&A costs are costs associated with removing the facilities and equipment required to operate a well and restoring the well site to specified conditions. P&A costs are incurred when the oil and natural gas reserves of a well or wells are depleted or when production drops to the point that it is no longer economically feasible to produce. The Company, in conjunction with its independent engineers and the operators of the wells, continually reviews its working interests with respect to potential P&A costs. Estimated P&A costs (net of estimated salvage value) are amortized through depletion using the unit-of-production method. As of December 31, 1999 and 1998, the Company's estimated P&A costs were approximately $495,000. Other Property and Equipment Other property and equipment are stated at cost and depreciation is computed on the straight line method over estimated lives ranging from five to seven years. Additions and betterments which provide benefits to several periods are capitalized. Environmental Liabilities Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations, and do not contribute to current or future revenue generation, are expensed. Liabilities are recorded when environmental assessments F-8 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 and/or clean-ups are probable, and the costs can be reasonably estimated. Generally, the timing of these accruals coincides with the Company's commitment to a formal plan of action. As of December 31, 1999, the Company had accrued estimated environmental costs of approximately $250,000. Revenue Oil and natural gas revenues are recorded using the sales method, whereby the Company recognizes revenues based on the amount of oil and natural gas sold to purchasers on its behalf. At December 31, 1999 and 1998, the Company's net imbalance position was immaterial. Hedging The Company periodically enters into derivative contracts to hedge the risk of future oil and natural gas price fluctuations. Such contracts may either fix or support oil and natural gas prices or limit the impact of price fluctuations with respect to the Company's sales of oil and natural gas. The Company uses the hedge or deferral method of accounting for derivative contracts and, as a result, gains and losses on commodity derivative financial instruments are generally offset by similar changes in realized prices of commodities. In order to qualify as hedges, price movements in the underlying commodity derivative must be highly correlated with the hedged commodity. Gains and losses on such hedging activities are recognized in oil and natural gas production revenues when hedged production is sold. If a derivative ceases to qualify as a hedge, changes in fair value of the derivative instrument are recognized in earnings currently. Income Taxes The Company uses the asset and liability method of accounting for income taxes under which deferred tax assets and liabilities are determined by applying enacted statutory tax rates applicable to future years to the difference between the financial statement and tax basis of assets and liabilities. The effect on deferred tax assets and liabilities of a change in tax rates is recognized as part of the provision for income taxes in the period that includes the enactment date. Stock Based Compensation The Company accounts for stock-based compensation under the intrinsic value method. Under this method, the Company records no compensation expense for stock options granted when the exercise price of options granted is equal to or greater than the fair market value of the Company's common stock on the date of grant. Earnings Per Share Basic earnings and loss per common share are based on the weighted average shares outstanding without any dilutive effects considered. Diluted earnings and loss per share reflects dilution from all potential common shares, including options, warrants and convertible preferred stock and notes. Diluted loss per share does not include the effect of any potential common shares if the effect would be to decrease the loss per share. All share and per share amounts have been retroactively adjusted for a one- for-three reverse split that was approved on January 14, 2000 (See Note 14). F-9 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 Concentrations of Market Risk The future results of the Company will be affected by the market prices of oil and natural gas. The availability of a ready market for oil and natural gas in the future will depend on numerous factors beyond the control of the Company, including weather, production of other oil and natural gas, imports, marketing of competitive fuels, proximity and capacity of oil and natural gas pipelines and other transportation facilities, any oversupply or undersupply of oil and natural gas, the regulatory environment, and other regional and political events, none of which can be predicted with certainty. Concentrations of Credit Risk Financial instruments which subject the Company to concentrations of credit risk consist primarily of cash and accounts receivable. The Company places its cash investments with high credit qualified financial institutions. Risk with respect to receivables is concentrated primarily in the current production revenue receivable from multiple oil and natural gas producers, both major and independent, and is typical in the industry. No single customer accounted for greater than 10% of the Company's total oil and natural gas sales for the years ended December 31, 1999 and 1998. Accounting Pronouncements In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". SFAS No. 133 standardizes the accounting for and disclosures of derivative instruments, including certain derivative instruments embedded in other contracts. The statement is effective for financial statements for periods beginning after June 15, 2000. The Company has not yet determined the impact of the Statement on its financial condition or results of operations. Use of Estimates Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities to prepare the financial statements in conformity with generally accepted accounting principles. Actual results could differ from those estimates. Reclassifications Certain reclassifications of prior period amounts have been made to conform to the current presentation. (2) ACQUISITIONS On March 27, 1998, the Company acquired 1,064,432 common shares, approximately 79.2%, of Enex for $15.9 million. The Company purchased the common shares of Enex through a cash tender offer that commenced February 19, 1998 (the "Enex Acquisition"). The Company also incurred approximately $60,934 in legal, accounting and printing expenses and issued 11,275 shares of Company common stock for finders fees to unrelated third parties. At the time, Enex was general partner of the Enex Partnership, a New Jersey limited partnership whose principal business is oil and natural gas exploration and production. Enex's general partner interest in the Enex Partnership was 4.1%. Enex also owned an approximate 56.2% limited partner interest in the Enex Partnership. As part of the Enex Acquisition, the Company entered into a consulting agreement, effective April 15, 1998, with the former president of Enex that provides for monthly payments of $20,000 until expiration of the F-10 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 agreement on May 18, 2002. The monthly payments serve as consideration for consulting, a covenant not to compete and a preferential right to purchase certain oil and natural gas acquisitions which the former president controls or proposes to acquire during the term of the agreement. The Company will reimburse the former president each month for reasonable and necessary business expenses incurred in connection with the performance of consulting services. The agreement survives the former president and his spouse and is nonassignable. At December 31, 1999 and 1998, the present value of the agreement, applying a 10% discount, was approximately $497,627 and $677,949, respectively. The long-term portion of the agreement is classified as other liabilities in the financial statements. The cost of acquiring 79.2% of Enex was allocated using the purchase method of accounting to the consolidated assets and liabilities of Enex based on estimates of the fair values with the remaining purchase price allocated to proved oil and natural gas properties. The allocation of the purchase price is summarized as follows: (in thousands) Working capital.................................................. $ 5,640 Oil and natural gas properties (proved and unproved)............. 19,090 Minority interest................................................ (7,669) ------- Total.......................................................... $17,061 =======
Over a three-week period ending December 23, 1998, the Company acquired an additional 0.80% (9,747 common shares) of Enex common stock for approximately $68,000. On April 16, 1998, the Company acquired substantially all of the oil and natural gas assets of Service Drilling, in exchange for 222,000 shares of Company common stock and $6.5 million in cash for a total acquisition cost of $10.0 million, before post-closing adjustments (the "Service Acquisition"). The fair value of the securities issued in connection with the Service Acquisition was calculated using the price of the Company's common stock at the time the Service Acquisition was announced to the public and further adjusted for tradability restrictions. An independent valuation firm determined the tradability discount for the Company's common stock. The effective date of the acquisition was March 1, 1998 and the cost was allocated using the purchase method of accounting. On December 30, 1998, the Company completed the acquisition of the Enex Partnership (the "Enex Partnership Acquisition"). The transaction consisted of an exchange offer whereby the Company offered to exchange 2.086 shares of Series C Preferred stock ("Series C") for each Enex Partnership unit (the "Exchange Offer"). In connection with the Exchange Offer, the Company submitted a proposal to investors in the Enex Partnership to amend the partnership agreement to provide for the transfer of all of the assets and liabilities of the Enex Partnership to the Company as of October 1, 1998 and dissolve the Enex Partnership. The Exchange Offer was approved on December 30, 1998 and the Company issued 2,177,481 Series C shares for 100% of the outstanding limited partner units. At the close of the Exchange Offer, the Enex Partnership had 1,102,631 units outstanding. Enex was issued 1,293,522 Series C shares for its 56.2% ownership of the Enex Partnership. The remaining 883,959 Series C shares were issued to the limited partners that elected to take Series C shares in lieu of cash. In January 1999, certain dissenting limited partners were paid $516,000 and other unitholders were paid $23,000 in lieu of fractional shares. Because of the dissenting limited partners, Enex owns 59.4% of the Series C shares, of which 20% (258,704 shares) are considered outstanding and held by third parties in the consolidated financial statements at December 31, 1999 and 1998. F-11 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 The intent of the Exchange Offer was to acquire the 43.8% of the outstanding limited partner units that the Company did not currently own. The tables below present the consideration paid for 100% of the Enex Partnership and for the 43.8% of the Enex Partnership not owned by Enex. The cost of acquiring 100% of the outstanding limited partner units was approximately $11.9 million, consisting of the following (in thousands): Estimated fair value of 2,177,481 shares of Company Series C preferred stock.................................................. $10,887 Cash consideration................................................ 539 Legal, accounting and other expenses.............................. 431 ------- Total........................................................... $11,857 =======
Since Enex is consolidated into the Company's financial statements, the number of shares outstanding and the value of the shares outstanding attributable to the 43.8% of the Enex Partnership not owned by Enex and the minority interest owners of Enex (20%) is 1,142,663 and $5.7 million, respectively. The cost of acquiring the outstanding limited partner units that were not owned by Enex was approximately $6.7 million, consisting of the following (in thousands): Estimated fair value of 1,142,663 shares of Company Series C preferred stock................................................... $5,713 Cash consideration................................................. 539 Legal, accounting and other expenses............................... 431 ------ Total............................................................ $6,683 ======
The Company's purchase price was allocated to the assets and liabilities attributable to the 43.8% of the Enex Partnership based on estimates of the fair values with the remaining purchase price allocated to proved oil and natural gas properties. The registration costs of approximately $431,000 reduced the value of the Series C shares issued. Because the Enex Partnership was consolidated in the financial statements of the Company as of the effective date of October 1, 1998, the preliminary purchase price allocation below shows the effect of the acquisition on the consolidated financial statements (in thousands): Working capital..................................................... $ (539) Oil and natural gas properties...................................... (23) Minority interest................................................... 5,844 ------ Series C Preferred Stock.......................................... $5,282 ======
On November 23, 1999, the Company completed the acquisition of oil and natural gas properties and interests, managed by Floyd Oil Company, owned by a group of private sellers (the "Floyd Oil Acquisition") for $86.8 million in cash and 503,426 shares of Company common stock. Prior to the acquisition, there was no relationship between Floyd C. Wilson, President of the Company and Floyd Oil Company. The effective date of the acquisition was January 1, 1999 and the cost was allocated using the purchase method of accounting. The total purchase price of $90.2 million, considering post-closing adjustments and transaction costs, was allocated principally to oil and natural gas properties. F-12 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 The following pro forma data presents the results of the Company for the years ended December 31, 1999 and 1998, as if the acquisitions of Enex, Service, Enex Partnership and Floyd Oil had occurred on January 1, 1998. The pro forma results are presented for comparative purposes only and are not necessarily indicative of the results which would have been obtained had the acquisitions been consummated as presented. The following data reflect pro forma adjustments for oil and natural gas revenues, production costs, depreciation and depletion related to the properties and businesses acquired, preferred stock dividends on preferred stock issued, interest expense on debt issued and the related income tax effects (in thousands, except per share amounts):
Pro Forma --------------- 1999 1998 ------- ------- (Unaudited) Total revenues............................................ $55,735 $55,299 Net income (loss) attributable to common stockholders..... 2,413 (4,725) Net income (loss) per share attributable to common stockholders Basic................................................... 0.45 (0.89) Diluted................................................. 0.41 (0.89)
(3) COMMON STOCK, WARRANT AND SENIOR SUBORDINATED CONVERTIBLE NOTE SALE TO W/E ENERGY COMPANY, L.L.C. ("W/E LLC") On August 27, 1999, the Company closed a Securities Purchase Agreement (the "Agreement") for a total of $21.4 million with W/E Energy Company, LLC ("W/E LLC"). The Securities Purchase Agreement and contemplated transactions were approved by the stockholders at the Company's annual meeting on August 10, 1999. The controlling person of W/E LLC is EnCap Investments L.L.C., a Delaware limited liability company ("EnCap Investments"). The sole member of EnCap Investments is El Paso Field Services Company, a Delaware corporation ("El Paso Field Services"). The controlling person of El Paso Field Services is El Paso Energy Corporation, a Delaware corporation. The Company received $9.8 million in cash and properties valued at $875,000 for 1,585,185 shares of common stock and 1,200,000 warrants (the "Warrants") and $10.7 million for a 5-year senior subordinated convertible note with a face value of $10.7 million (See Note 7). At closing, W/E LLC became the Company's largest shareholder with current ownership of approximately 30% of the current outstanding shares of common stock. (4) RELATED PARTY TRANSACTIONS The Company had a note receivable from Bay City Energy Group, Inc., a shareholder of the Company, as of December 31, 1998 in the amount of $173,115. In conjunction with the sale of securities to W/E LLC (See Note 3) in August, 1999, the note and all accrued interest was paid in full. The principal balance of the note accrued interest at 5% annually and was due January 1, 2001. The note was secured by 25,000 shares of Company common stock. Interest of $34,110 was accrued on the note as of December 31, 1998. The Company rents office space from C.J. Lett III, a shareholder and former officer and director of the Company. The rent is $3,000 per month for three years through February, 2000. Mr. Lett has common stock ownership in two oil service companies that provide services to the Company. The Company paid approximately $117,000 and $203,000 to these companies for the years ended December 31, 1999 and 1998, respectively. F-13 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 David B. Miller and D. Martin Phillips, directors of the Company, are managing directors of EnCap Investments, which is the controlling person of W/E LLC which owns approximately 30% of the common stock of the Company, excluding shares attributable to the warrants and convertible notes, as of December 31, 1999. Gary R. Christopher, a shareholder and director of the Company, is employed by Kaiser-Francis Oil Co., which owns approximately 21% of the common stock of the Company as of December 31, 1999. (5) ACCOUNTS RECEIVABLE-INSURANCE CLAIM The Company owns a 100% working interest in the Louis Mayard #1 well (the "Well") located in the Esther Field in Vermillion Parish, Louisiana. Due to a failed recompletion attempt and the inability of the Company to shut in the Well using normal operating methods, the Company incurred approximately $1.9 million during 1998 to gain control of the Well using special crews. On November 4, 1998, the insurance company made a partial payment to the Company under its well control insurance policy of approximately $1.4 million. In April, 1999 the Company was paid $383,000 in final settlement of all claims related to the Well. The Company had recorded the estimated remaining amount due from the insurance company in current assets as Accounts Receivable- Insurance Claim at December 31, 1998. (6) LONG-TERM DEBT Long-term debt at December 31, 1999 and 1998, consisted of the following (in thousands):
1999 1998 ------- ------- $250 million Credit Facility............................. $87,500 $ -- $100 million Revolver.................................... -- 27,455 ------- ------- Total.................................................... 87,500 27,455 Less current maturities.................................. -- -- ------- ------- Long term debt excluding current maturities............ $87,500 $27,455 ======= =======
Concurrent with the Floyd Oil Acquisition, the Company entered into a $250 million credit facility (the "Facility") with Bank One, Texas, NA as agent and four other banks. The Company's borrowing base has been initially set at $95 million with $87.5 million outstanding at December 31, 1999. The borrowing base will be redetermined semi-annually on May 1 and November 1. Interest under the Facility accrues at a rate calculated at the Company's option as either the bank's prime rate plus 25 basis points or LIBOR plus basis points increasing from a low of 125 to a high of 187.5 as loans outstanding increase as a percentage of the borrowing base. As of December 31, 1999, the Company was paying 8.08% per annum interest on $82.5 million and 8.36% per annum interest on $5 million of the principal balance of the Facility. The loan matures on November 30, 2002. Prior to maturity, no payments of principal are required so long as the borrowing base exceeds the loan balance. The borrowings under the Facility are secured by substantially all of the Company's oil and natural gas properties. The Facility requires an interest coverage ratio of two and a half to one (2.5:1) determined on a quarterly basis prior to the quarter ending September 30, 2000 and each four quarter period thereafter, and a current ratio, excluding current maturities of the Facility, of one to one (1:1), determined on a quarterly basis. The Facility also requires certain other affirmative and negative covenants including, but not limited to: . Use of all proceeds from sales of oil and natural gas properties for the repayment of the outstanding debt. F-14 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 . Prohibits the declaration or payment of any cash dividend; purchase, redeem or otherwise acquire for value any outstanding stock; return capital to stockholders; or make any distribution of assets to stockholders, except for dividends on Series C Preferred Stock and redemption of Series C Preferred Stock under certain circumstances. . Agree not to enter into any hedge transactions except with the bank's consent and for certain pre-approved hedging activities in connection with oil and natural gas properties. Events of default under the Facility include a final judgement or order in excess of $1 million, a change of control of the Company or Floyd C. Wilson ceasing to act as President and Chief Executive Officer. Aggregate amounts of expected required repayments of long term debt at December 31 are as follows (in thousands): 2000.............................................................. $ -- 2001.............................................................. -- 2002.............................................................. 87,500 Thereafter........................................................ -- ------- Total........................................................... $87,500 =======
(7) SENIOR SUBORDINATED CONVERTIBLE NOTES On August 27, 1999, senior subordinated convertible promissory notes (the "Senior Notes") were sold to W/E LLC and affiliates of Alvin V. Shoemaker ("Shoemaker"), a former director and significant shareholder, for $10.7 million and $150,000, respectively. On October 19, 1999, $2.4 million of Senior Notes were sold to The Prudential Insurance Company of America ("Prudential"). The Senior Notes bear interest at an annual rate of 9%. Interest is payable beginning on December 31, 1999, every March 31, June 30, September 30 and December 31, until maturity on August 27, 2004. The Company may defer payment of fifty percent (50%) of the first eight quarterly interest payments. The Senior Notes may be prepaid, without premium or penalty, in whole or in part, at any time after August 27, 2001. The holders of the Senior Notes may convert all or any portion of outstanding principal and accrued interest at any time into shares of Company common stock at a conversion price of $9.00 per common share, a total of 1,469,316 common shares. The conversion price may be adjusted from time to time based on the occurrence of certain events. In the event of a change in control, the entire outstanding principal balance and all accrued but unpaid interest is immediately due and payable. The Senior Notes rank senior in right of payment to all Company notes and indebtedness other than the Facility. (8) INCOME TAXES Income tax benefit for the years ended December 31, 1999 and 1998 consisted of the following (in thousands):
December 31, ---------------- 1999 1998 ------- ------- Current................................................. $ -- $ -- Deferred................................................ (1,443) (2,830) ------- ------- Total................................................. $(1,443) $(2,830) ======= =======
F-15 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 The reconciliation of income tax computed at the U.S. federal statutory tax rates to the provision for income taxes is as follows (in thousands):
December 31, ---------------- 1999 1998 ------- ------- Income tax benefit at statutory rate................... $(1,656) $(3,202) Increase (decrease) in valuation allowance............. (151) 860 Increase due to non-deductible stock compensation...... 248 -- Purchase price adjustment.............................. -- (508) Other.................................................. 116 20 ------- ------- Total................................................ $(1,443) $(2,830) ======= =======
The Company's net deferred tax liability at December 31, 1999 and 1998 is as follows (in thousands):
1999 1998 -------- ------- Deferred tax liability Oil and natural gas properties....................... $ 1,428 $ -- -------- ------- Deferred tax asset NOL carryforward..................................... (6,643) (4,057) AMT tax credit carryforward.......................... (36) (36) Oil and natural gas properties....................... -- (19) Other................................................ (547) (395) -------- ------- (7,226) (4,507) Valuation allowance.................................... 6,089 6,240 -------- ------- Net deferred tax liability............................. $ 291 $ 1,733 ======== =======
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax asset will not be realized. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon projections for future taxable income over the periods in which the deferred tax assets are deductible and the Section 382 limitation discussed below, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 1999 and 1998. The Enex Acquisition caused an ownership change pursuant to Section 382 in March 1998. As a result of this ownership change, the Company's use of its net operating loss carryforwards subsequent to that date will be limited. The Floyd Oil Acquisition in November 1999 also caused an ownership change pursuant to Section 382. As a result of this ownership change, the Company's use of its net operating loss carryforwards subsequent to that date will be limited to approximately $1.5 million per year. As of December 31, 1999, the Company had net operating loss carryforwards of approximately $20 million, expiring beginning in 2009 through 2019. (9) RETIREMENT PLAN AND EMPLOYEE INCENTIVE PLAN All of the employees of the Company are eligible to participate in a defined contribution plan that provides for maximum discretionary employee contributions of 15% of total wages paid to employees for the year and Company contributions. No Company contributions were made to the plan for the years ending December 31, 1999 and 1998. F-16 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 In March 1995, the Board of Directors adopted an employee incentive compensation plan (the "Plan") for the benefit of Company employees. The Plan benefits were equal to one percent (1%) of the annual net profit from oil and natural gas properties acquired or discovered on or after January 1, 1994 and one percent (1%) of the annual sales proceeds from any oil and natural gas properties sold on or after January 1, 1994. The Compensation Committee of the Board of Directors had sole authority regarding the amount and timing of payment of any Plan benefits to eligible employees. On August 27, 1999, the Company paid $274,625 to the eligible participants in the Plan and terminated the Plan pursuant to the terms of the W/E LLC agreement. The payment was equal to 100% of the Plan benefits through August 27, 1999. The entire amount of the payment, including associated taxes of $17,902, was recognized during the year ended December 31, 1999. Prior to the Compensation Committee's authorization, the Plan benefits were not accrued as an expense in the financial statements because the likelihood that the Compensation Committee would determine that the benefits would be payable to eligible employees was less than probable. (10) STOCK OPTION PLANS At December 31, 1999, the Company had two fixed stock option plans, the 1995 Stock Option and Stock Appreciation Rights Plan (the "1995 Plan") and the 1999 Stock Option Plan (the "1999 Plan"). As discussed in Note 1, for the years ended December 31, 1999 and 1998, no compensation cost has been recognized, relating to stock options issued, as the exercise price of each option equals the market price of the Company's common stock on the date of grant. Had compensation cost for the Company's 1995 Plan been determined based on the fair value at the grant date for stock options granted for the years ending December 31, 1999 and 1998, the Company's net loss and loss per share would have been increased to the pro forma amounts listed below (in thousands, except per share amounts):
December 31, ---------------- 1999 1998 ------- ------- Net loss As Reported.......................................... $(4,006) $(6,657) Pro Forma............................................ (4,110) (7,120) Net loss per common share, basic and diluted As Reported.......................................... $ (1.14) $ (2.48) Pro Forma............................................ (1.17) (2.65)
The weighted average fair value of stock options granted during 1999 and 1998 was $2.40 and $8.91 per share, respectively. The fair value of each option is estimated on the date of grant using the Black-Scholes option- pricing model with the following assumptions used for the grants in 1999 and 1998; no dividend yield; expected volatility of 77%; weighted average risk- free interest rate of 4.78% and 4.93%, respectively; and an expected life of 3 years. At December 31, 1999, the range of exercise prices and weighted average remaining contractual life of options outstanding was $4.50 to $23.25 and 2.81 years, respectively. At December 31, 1999 there were 157,300 and 500,000 shares of common stock available for grant under the 1995 and 1999 Plans, respectively. All of the options granted under the 1995 Plan expire five (5) years from the date of grant if not exercised and are 100% vested. As of December 31, 1999, no options have been issued under the 1999 Plan. The 1995 and 1999 Plans are administered by the Compensation Committee of the Board of Directors. F-17 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 On August 24, 1999, the Company amended the 1995 Plan due to the change in control that resulted from the Agreement (See Note 3). The 1995 Plan was amended to extend the exercise date for all options issued prior to July 1, 1999 to one year from the following dates: (1) the termination date of employees if the termination date is without cause and occurred during the six-month period commencing with the closing of the Purchase Agreement; (2) the date of termination for employees terminated for "Good Reason" as defined in such employee's employment agreement; and (3) the date of resignation of a holder who is also a director who resigns at closing of the Agreement. The extension of the exercise period of the employee stock options resulted in a new measurement date and compensation expense, equal to the intrinsic value of all of the outstanding options, of approximately $730,000, was recognized as stock compensation. Information relating to stock options and certain warrants is summarized below:
Average Exercise Shares Price Per Share ------- ---------------- Options and warrants outstanding at January 1, 1998............................................ 201,389 $16.71 Granted.......................................... 102,333 $16.71 ------- Options and warrants outstanding at December 31, 1998............................................ 303,722 $16.71 Granted.......................................... 66,667 $ 4.50 Exercised........................................ (21,500) $ 5.43 Forfeited........................................ (12,967) $17.40 ------- Options and warrants outstanding at December 31, 1999............................................ 335,922 $15.00 ======= Options and warrants exercisable at December 31, 1999............................................ 335,922 $15.00 =======
Options to acquire 75,000 shares of the Company common stock at an exercise price of $16.50 were granted outside of the 1995 Plan on February 13, 1997 to certain officers of the Company. Warrants to acquire 25,000 shares of the Company common stock at an exercise price of $15.00 were granted outside of the 1995 Plan on September 15, 1998 to a consultant (See Note 11). Both grants are included in the table above. Warrants to purchase 1,216,822 shares and 266,226 shares of common stock at $3.00 per share were issued on August 27, 1999 and October 19, 1999, respectively, and are excluded from the table above because the warrants were issued in conjunction with the sales of stock and are not stock-based compensation. (11) STOCKHOLDERS' EQUITY Preferred Stock-Series A On September 4, 1996, the Company signed a stock purchase agreement with Kaiser Francis Oil Company ("Kaiser-Francis"). Kaiser-Francis agreed to purchase 1,666,667 shares of Series A Preferred Stock ("Series A") at $6.00 per share, for a total investment of $10 million. The parties agreed to a five-year purchase period, effective September 4, 1996, with minimum incremental investments of $500,000 each. Each issuance of Series A was subject to approval by Kaiser-Francis of the use of proceeds. The Series A was nonvoting and accrued dividends at 8% per annum, payable quarterly in cash. The Series A was convertible at any time after issuance into shares of common stock at the rate of 0.66 shares of common stock for each share of Series A before January 1, 1998. The conversion rate decreases for every full year (excluding partial years) thereafter at 8% per annum. As of December 31, 1997, 1,666,667 shares of the Series A had been issued. On January 31, 1998 Kaiser- Francis converted 100% of the Series A into 1,111,111 common shares of the Company. F-18 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 Preferred Stock--Series B In connection with the merger of Shore Oil Company , effective June 30, 1997, the Company issued 266,667 shares of Series B Preferred Stock ("Series B"). The Series B is nonvoting and pays no dividends. The Series B has a liquidation value of $7.50 per share. Until December 31, 2002, any holder of the Series B may convert all or any portion of Series B shares into Company Common Stock ("Common") at the greater ratio of (i) three shares of Series B for one share of Common or (ii) at a ratio based upon the "Alternative Conversion Factor." The Alternative Conversion Factor is determined by dividing the net increase in value of approximately 40,000 net mineral acres owned by the Company in South Louisiana by $8,000,000 and multiplying the product by 355,333 to arrive at the potential number of total Common shares all holders would receive upon conversion. In no event shall the aggregate total number of shares of Common into which the Series B are converted be less than 88,889 shares or exceed 444,444 shares, unless further increased for any anti-dilution provisions. Upon expiration of the conversion period, unless the Company has given notice to redeem the Series B, all of the shares of the Series B shall be automatically converted. At December 31, 1999, the value of the fee minerals had increased to a level that resulted in the Series B shares being convertible into an additional 1,891 common shares applying the Alternative Conversion Factor. At December 31, 1999, none of the Series B had been converted. Preferred Stock--Series C In connection with the Enex Partnership Acquisition, on December 30, 1998, the Company issued 2,177,481 shares of Series C Preferred Stock ("Series C") in exchange for 100% of the Enex Partnership units. The holders of Series C are entitled to receive cumulative cash dividends in an amount per share of $0.50 per year (10% annual rate), payable semi-annually on March 31 and September 30 of each year. These dividends are payable in preference to and prior to the payment of any dividend or distribution to any holder of Company common stock or other junior security. The Series C dividends began to accrue on December 30, 1998. The banks have granted the Company a waiver allowing the Company to pay the dividends on the Series C as long as no default or event of default exists or would exist as a result of any Series C dividend payment. The Series C has a liquidation preference of $5.00 per share plus an amount equal to all accumulated, accrued and unpaid dividends. The liquidation preference of Series C ranks on parity with the Series B. Each share of Series C is convertible into one-third share of Company common stock. On or after January 1, 2000, the Company may redeem all or a portion of the Series C, at its option, at a purchase price of $5.00 per share, plus an amount equal to all accumulated, accrued and unpaid dividends. The Series C is generally nonvoting; however, holders of Series C are entitled to vote on any amendment, alteration or appeal of any provision of the Company's Articles of Incorporation which would adversely affect any holder's rights and preferences. As a result of its limited partnership interest in the Enex Partnership, Enex owns 1,293,522 shares of the Series C of which the Company owns 80%, or 1,034,818 shares through its 80% ownership of Enex. Common Stock and Warrants On August 27, 1999, the Company sold to W/E LLC 1,585,185 shares of common stock and five-year warrants to purchase 1,200,000 shares of common stock for $9.8 million in cash and oil and natural gas properties valued at $875,000. On the same date, the Company sold 22,222 shares of common stock and five-year warrants to purchase 16,822 shares of common stock to Shoemaker for $150,000 (See Notes 3 and 7). F-19 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 On October 19, 1999, the Company closed a private placement of securities to Prudential. The economic terms and conditions of the private placement are similar to those of the securities purchase agreement with W/E LLC and Shoemaker entered into on July 1, 1999. The private placement consisted of the sale of 351,681 shares of common stock and five-year warrants to purchase 266,226 shares at $3.00 per share of common stock for $2.4 million and a five- year senior subordinated convertible note for $2.4 million (See Note 7). The warrants issued to W/E LLC, Shoemaker and Prudential are exercisable for $3.00 per share and expire five years from the issue date. Sixty percent of the warrants are immediately exercisable, in whole or in part at any time until the expiration date. An additional 10% of the warrants may be exercised at each anniversary of the grant date until expiration. On the occurrence of either a change of control, payment in full of the Senior Notes or conversion of the entire principal balance of the Senior Notes, all of the warrants become immediately exercisable. If less than the entire principal balance of the Senior Notes are converted, a pro-rata portion of the warrants will be convertible based on the portion of the Senior Notes that are converted. On September 15, 1998 the Company entered into a consulting agreement with Edward K. Andrew ("Andrew") for a term of five years beginning January 1, 1999. As compensation, the Company granted to Andrew a warrant to purchase 25,000 shares of Company common stock at a price of $15.00. The warrants vested over the period September 15, 1998 to January 1, 1999. The estimated fair value of the warrants was determined at the date of grant and charged to stock compensation expense over the vesting period. On February 13, 1997, the Company awarded to certain officers 16,364 shares of restricted stock of the Company. The restricted stock awards were contingent on the performance of services to the Company in the future with 50% of the restricted shares being earned over the six month period July 1, 1997 to December 31, 1997 and 50% over the six month period January 1, 1998 to June 30, 1998. All restricted shares were earned and issued as of December 31, 1998. Earnings Per Share At December 31, 1999 and 1998, the Company had a weighted average of 1,149,476 and 283,297, combined stock options, warrants and convertible preferred stock and notes outstanding, respectively, which were not included in the computation of diluted earnings per share, because the effect of the assumed exercise of these stock options, warrants and convertible securities would have an antidilutive effect on the computation of diluted loss per share. At December 31, 1999 and 1998, the Company had outstanding convertible preferred stock that was convertible into 469,744 and 469,778 shares of common stock, and dividends of $574,080 and $67,945, respectively, which were not reflected in the computation of diluted earnings per share, because the effect of the assumed conversion of these preferred shares would have an antidilutive effect on the computation of diluted loss per share. At December 31, 1999, the Company had $4,154,292 weighted average face value of convertible subordinated notes that were convertible into 461,588 shares of common stock and interest expense of $376,367, which were not reflected in the computation of diluted earnings per share, because the effect of the assumed conversion of these subordinated notes would have an antidilutive effect on the computation of diluted loss per share. (12) COMMITMENTS AND CONTINGENCIES The Company is obligated under the terms of certain operating leases for office space that continue through January 31, 2005. Total rent expense was $267,337 and $268,477 for the years ended December 31, 1999 and 1998, respectively. Future minimum rental payments under the Company's leases total $309,372, $248,694, $194,016, $194,016 and $194,016 for the years ending December 31, 2000 through 2004, respectively. F-20 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 On November 18, 1999, the Company's shareholders approved a reincorporation of the Company from Alabama to Delaware (See Note 1). The Alabama Code has a shareholder dissent provision that allows a shareholder to dissent from the reincorporation and demand cash payment equal to the fair value of the common stock owned at the date of the reincorporation. Before the November 18 meeting, the Company received shareholder dissents representing ownership of 99,438 shares of common stock. Over the period December 15, 1999 to January 25, 2000, the Company received formal demands for payment from the dissenting shareholders (the "dissenters"). The Company expects to make an offer to the dissenters before March 10, 2000. Once the offer is made, the dissenters have 30 days to accept the offer or make a counteroffer. If the Company and the dissenters cannot reach agreement on the fair value of the common shares within 60 days of the dissenters' counteroffer, if any, the matter is then moved to the Circuit Court of Washington County, Alabama for resolution. The exact amount to be paid to the dissenters for their common shares cannot be determined at this time. Based on the Company's closing stock price on November 23, 1999 of $11.25 per share and accrued interest from November 23, 1999, the Company accrued the estimated cash payment to the dissenters of approximately $1.1 million. As of December 31, 1999, the Company had $55,000 of irrevocable standby letters of credit outstanding. The Company is a defendant in various legal proceedings which are considered routine litigation incidental to the Company's business, the disposition of which management believes will not have a material effect on the financial position or results of operations of the Company. (13) FINANCIAL INSTRUMENTS In April 1999, the Company entered into costless collar hedges for approximately 3,650 Mcf per day with a weighted average floor and ceiling of $2.06 and $2.20, respectively, for the months of May through October of 1999. During the year ending December 31, 1999, the Company incurred hedging losses of approximately $164,000. At December 31, 1999, the Company had no open derivative instruments. Fair value of cash, receivables and payables approximates carrying value. Fair value of long-term debt also approximates carrying value due to the nature of the Facility, whereby the interest rates are floating rates which reflect market rates. At December 31, 1999, the fair value of the $13.2 million senior subordinated convertible notes was $13.1 million. (14) SUBSEQUENT EVENTS On January 14, 2000, the Company's stockholders voted to effect a one-for- three reverse split of the Company's common stock for the stockholders of record on December 9, 1999. The reverse stock split resulted in a decrease of 10,677,542 in the number of shares issued at December 31, 1999, 14,515 of which are held in treasury. The par value of these shares was transferred to additional paid-in capital. All common share and earnings per common share amounts as of December 31, 1999 and 1998 have been retroactively restated in the accompanying consolidated financial statements to reflect the reverse stock split. On February 3, 2000, the Company closed the acquisition of Magellan Exploration, LLC ("Magellan"), a privately held Delaware limited liability company, for an estimated purchase price of $18.3 million. In connection with the acquisition, the Company issued 1,085,934 common shares and warrants to purchase 333,333 shares of common stock with an exercise price of $30.00 per share, which are exercisable for four years. The Company also issued 617,008 shares of Series D convertible preferred stock with a stated value of $24.00 per share, F-21 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 dividend rate of 5% per annum with an option for three years for the Company to pay the dividends in additional Series D shares and with each Series D share convertible at any time into Company common stock on a one-for-one basis. The Company may redeem the Series D shares upon 30 days written notice and there are no rights of holders to "put" the Series D shares to the Company. The owners of Magellan also received a 5% "Back-In" working interest in twelve (12) exploration prospects. (15) SUPPLEMENTAL OIL AND NATURAL GAS INFORMATION (UNAUDITED) Capitalized Costs and Costs Incurred The following tables present the capitalized costs related to oil and natural gas producing activities and the related depreciation, depletion, amortization and impairment as of December 31, 1999 and 1998 and costs incurred in oil and natural gas property acquisition, exploration and development activities (in thousands) for the years ended December 31, 1999 and 1998.
1999 1998 -------- ------- Capitalized Costs Proved properties..................................... $162,455 $84,325 Nonproducing leasehold................................ 6,385 6,524 Accumulated depreciation, depletion, amortization and impairment........................................... (37,861) (38,810) -------- ------- Net capitalized costs............................... $130,979 $52,039 ======== ======= Costs Incurred Proved properties..................................... $ 91,081 $28,878 Unproved properties................................... 343 337 Exploration costs..................................... 824 1,802 Development costs..................................... 2,154 3,041 -------- ------- Total............................................... $ 94,402 $34,058 ======== ======= Depletion, depreciation, amortization and impairment.... $ 9,067 $11,013 ======== =======
Estimated Quantities of Reserves The Company has interests in oil and natural gas properties that are located principally in Texas, Louisiana, Kansas, Oklahoma and New Mexico. The Company does not own or lease any oil and natural gas properties outside the United States. There are no quantities of oil and natural gas subject to long-term supply or similar agreements with any governmental agencies. The Company retains independent engineering firms to provide year-end estimates of the Company's future net recoverable oil, natural gas and natural gas liquids reserves. In 1999, such estimates were prepared by Ryder Scott Company. In 1998, such estimates were prepared by Lee Keeling and Associates, Inc. and H.J. Gruy & Associates, Inc.. The reserve information was prepared in accordance with guidelines established by the Securities and Exchange Commission. Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves F-22 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 include those reserves expected to be recovered from new wells or on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion. Net quantities of proved developed and undeveloped reserves of oil, including condensate and natural gas liquids, for the years ended December 31, 1999 and 1998 are summarized as follows (in barrels):
1999 1998 --------- --------- Proved Reserves Beginning of year................................. 3,342,048 2,933,000 Revisions of previous estimates................... 502,139 (277,291) Extensions and discoveries........................ 12,667 103,506 Purchases of reserves in place.................... 6,865,638 1,254,663 Sales of reserves in place........................ (355,190) (90,373) Production for the year........................... (531,881) (581,457) --------- --------- End of year..................................... 9,835,421 3,342,048 ========= ========= Proved Developed Reserves Beginning of year................................. 3,117,839 2,580,000 End of year....................................... 9,358,048 3,117,839
Net quantities of proved developed and undeveloped reserves of natural gas for the years ended December 31, 1999 and 1998 are summarized as follows (in Mcf):
1999 1998 ----------- ---------- Proved Reserves Beginning of year.............................. 43,482,980 18,419,000 Revisions of previous estimates................ (5,135,492) (82,742) Extensions and discoveries..................... 1,225,665 290,347 Purchases of reserves in place................. 126,556,624 30,997,247 Sales of reserves in place..................... (1,693,121) (2,294,193) Production for the year........................ (4,737,656) (3,846,679) ----------- ---------- End of year.................................. 159,699,000 43,482,980 =========== ========== Proved Developed Reserves Beginning of year.............................. 36,731,365 14,251,000 End of year.................................... 122,914,000 36,731,365
Standardized Measure of Discounted Future Net Cash Flows From Proved Reserves The following is a summary of the standardized measure of discounted future net cash flows related to the Company's proved oil and natural gas reserves. For these calculations, estimated future cash flows from estimated future production of proved reserves are computed using oil and natural gas prices as of the end of each period presented. Future development and production costs attributable to the proved reserves were estimated assuming that existing conditions would continue over the economic lives of the individual leases and costs were not escalated for the future. Estimated future income taxes were calculated by applying statutory tax rates (based on current law adjusted for permanent differences and tax credits) to the estimated future pre-tax net cash flows related to proved oil and natural gas reserves, less the tax basis of the properties involved. F-23 3TEC ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) December 31, 1999 and 1998 The Company cautions against using this data to determine the value of its oil and natural gas properties. To obtain the best estimate of the fair value of the oil and natural gas properties, forecasts of future economic conditions, varying discount rates, and consideration of other than proved reserves would have to be incorporated into the calculation. In addition, there are significant uncertainties inherent in estimating quantities of proved reserves and in projecting rates of production that impair the usefulness of the data. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves for the years ended December 31, 1999 and 1998 are summarized as follows (in thousands):
1999 1998 --------- -------- Future cash inflows................................... $ 594,023 $133,549 Future production costs and development costs......... (223,765) (62,085) Future income tax expenses............................ (92,975) -- --------- -------- Future net cash flows................................. 277,283 71,464 10% discount to reflect timing of cash flows.......... (128,542) (32,570) --------- -------- Standardized measure of discounted future net cash flows................................................ $ 148,741 $ 38,894 ========= ========
The following are the principal sources of changes in the standardized measure of discounted future net cash flows for the years ended December 31, 1999 and 1998 (in thousands):
1999 1998 -------- ------- Sales of oil and natural gas, net of production cost.... $(13,224) $(7,210) Net changes in prices and production cost............... 18,646 (5,459) Extensions and discoveries.............................. 1,945 732 Purchases of reserves................................... 150,295 23,092 Sales of reserves....................................... (1,643) (1,528) Revisions of previous quantity estimates................ (1,994) (1,573) Net change in income taxes.............................. (49,874) 2,712 Accretion of discount................................... 3,889 3,635 Changes in production rates (timing) and other.......... 1,807 -- -------- ------- Change for year......................................... $109,847 $14,401 ======== =======
During recent years, there have been significant fluctuations in the prices paid for oil in the world markets. The situation has had a destabilizing effect on posted prices for oil in the United States, including the posted prices paid by purchasers of the Company's oil. The period end prices of oil and natural gas at December 31, 1999 and 1998, used in the above table were $23.64 and $9.50 per barrel of oil and $2.23 and $2.10 per thousand cubic feet of natural gas, respectively. F-24 GLOSSARY OF CERTAIN OIL AND GAS TERMS The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and herein: Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons. Bcf. One billion cubic feet of natural gas. Bcfe. One billion cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids. Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit. Completion. The installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve. Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production. Development well. A well drilled into a proved natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory well. A well drilled to find and produce natural gas or oil reserves that are not proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir. Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic level. MBbls. One thousand barrels of oil or other liquid hydrocarbons. Mcf. One thousand cubic feet of natural gas. Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids. Mmbtu. One million British Thermal Units. Mmcf. One million cubic feet of natural gas. Mmcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids. Productive well. A well that is found to be capable of producing sufficient quantities of oil and gas so that proceeds from the sale of the production are greater than production expenses and taxes. Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of oil and natural gas. 31 Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves. The estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on developed acreage where the subject reserves cannot be recovered without drilling additional wells. PV-10 value. The estimated future net revenue to be generated from the production of proved reserves discounted to present value using an annual discount rate of 10%. These amounts are calculated net of estimated production costs and future development costs, using prices and costs in effect as of a certain date, without escalation and without giving effect to non-property related expenses, such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion, and amortization. Recompletion. The completion of an existing well for production from a formation that exists behind the casing of the well. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. Royalty interest. An interest in a natural gas and oil property entitling the owner to a share of natural gas and oil production free of costs of production. Standardized measure. The estimated future net cash flows from proved natural gas and oil reserves computed using prices and costs, at a specific date, after income taxes and discounted at 10%. Tcfe. One trillion cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids. Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves. Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production. 32 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 by the undersigned, thereunto duly authorized, as of March 30, 2000. 3TEC ENERGY CORPORATION (Registrant) By: /s/ Floyd C. Wilson ____________________________________________ Floyd C. Wilson Chief Executive Officer, President and Chairman By: /s/ Stephen W. Herod ____________________________________________ Stephen W. Herod Executive Vice-President, Chief Financial Officer, Secretary POWER OF ATTORNEY KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Floyd C. Wilson and Stephen W. Herod, and each of them, his true and lawful attorneys-in-fact and agents, each with full power of substitution and resubstitution, to sign any and all amendments (including post- effective amendments) to this Annual Report on Form 10-KSB and to file the same, with exhibits thereto and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorney-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact, or their substitute or substitutes, or any of them, shall do or cause to be done by virtue hereof. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: March 30, 2000 /s/ Floyd C. Wilson _________________________ ________________________________________________ Date Floyd C. Wilson Chief Executive Officer, President and Chairman March 30, 2000 /s/ Stephen W. Herod _________________________ ________________________________________________ Date Stephen W. Herod Director, Executive Vice-President, Chief Financial Officer, Secretary 33 March 30, 2000 /s/ Gary R. Christopher _________________________ ________________________________________________ Date Gary R. Christopher Director March 30, 2000 /s/ D. Martin Phillips _________________________ ________________________________________________ Date D. Martin Phillips Director March 30, 2000 /s/ David B. Miller _________________________ ________________________________________________ Date David B. Miller Director 34 EX-3.3 2 AMENDMENT TO CERTIFICATE OF INCORPORATION EXHIBIT 3.3 CERTIFICATE OF AMENDMENT OF CERTIFICATE OF INCORPORATION OF 3TEC ENERGY CORPORATION The undersigned, being the Executive Vice President of 3TEC Energy Corporation (the "Corporation") DOES HEREBY CERTIFY as follows: 1. The name of the Corporation is 3TEC Energy Corporation. 2. The Certificate of Incorporation of the Corporation is hereby amended to effect a one (1) for three (3) reverse split of all of the Corporation's issued common stock, par value $.02 per share (the "Common Stock"), whereby each three (3) issued shares of Common Stock shall be changed into one (1) share of Common Stock, and, in that connection, to reduce the stated capital of the Corporation. This Certificate of Amendment shall be effective as of 11:59 p.m. Eastern Standard Time on January 14, 2000. 3. In order to effectuate the amendment set forth in Paragraph 2 above: (a) All of the Corporation's issued Common Stock, having a par value of $.02 per share, is hereby changed into new Common Stock, having a par value of $.02 per share, on the basis of one (1) new share of Common Stock for each three (3) shares of Common Stock issued as of the date of filing of the Amendment with the Secretary of State for the State of Delaware, provided, however, that no fractional shares of Common Stock shall be issued pursuant to such change. Each stockholder who would otherwise be entitled to a fractional share as a result of such change shall have only a right to receive a cash payment equal to the amount produced by multiplying such fraction times the closing price of one share of Common Stock as of the close of business on the date of filing of this Amendment, in lieu of any fractional share otherwise issuable upon conversion. (b) The Corporation's 60,000,000 authorized shares of Common Stock, having a par value of $.02 per share, shall not be changed; (c) The Corporation's 20,000,000 authorized shares of preferred stock, having a par value of $.02 per share, shall not be changed; and (d) The Corporation's stated capital shall be reduced by an amount equal to the aggregate par value of the shares of Common Stock issued prior to the effectiveness of this Amendment which, as a result of the reverse split provided for herein, are no longer issued shares of Common Stock. 4. The foregoing amendments of the Certificate of Incorporation of the Corporation have been duly adopted by the Corporation's Board of Directors and Stockholders in accordance with the provisions of Section 242 of the Delaware General Corporation Law. IN WITNESS WHEREOF, the undersigned have subscribed this document on the date set forth below. Dated: January 14, 2000 - ------------------------------------------ Stephen W. Herod, Executive Vice President EX-27.1 3 FINANCIAL DATA SCHEDULE
5 YEAR DEC-31-1999 JAN-01-1999 DEC-31-1999 6,141,153 0 9,453,551 0 0 15,770,930 169,982,378 38,208,298 149,243,506 8,769,711 100,723,844 0 8,825,440 106,778 29,180,419 149,243,506 19,951,750 22,020,066 6,727,948 26,892,542 0 0 3,204,768 (4,874,799) (1,442,524) (3,432,275) 0 0 0 (3,432,275) (0.975) (0.975)
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