-----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, IX156UUy3rMFs5AcrUdpCoENj45iRFbqwtwG+rZtljpW09K/CT6jElF1957kwjdW UFQmlajC4tF9Ec0vl+Rx0g== 0000899243-01-000812.txt : 20010409 0000899243-01-000812.hdr.sgml : 20010409 ACCESSION NUMBER: 0000899243-01-000812 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010402 FILER: COMPANY DATA: COMPANY CONFORMED NAME: BELLWETHER EXPLORATION CO CENTRAL INDEX KEY: 0000319459 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 760437769 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 000-09498 FILM NUMBER: 1590522 BUSINESS ADDRESS: STREET 1: 1331 LAMAR STREET 2: SUITE 1455 CITY: HOUSTON STATE: TX ZIP: 77010 BUSINESS PHONE: 7134953000 MAIL ADDRESS: STREET 1: 1221 LAMAR STREET 2: STE 1600 CITY: HOUSTON STATE: TX ZIP: 77010-3039 10-K405 1 0001.txt FORM 10-K FOR YEAR-ENDING DECEMBER 31, 2000 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) [X]ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 OR [_]TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission File Number 0-9498 BELLWETHER EXPLORATION COMPANY (Exact name of registrant as specified in its charter) Delaware 76-0437769 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1331 Lamar, Suite 1455, Houston, 77010 Texas (Zip Code) (Address of principal executive offices) Registrant's telephone number, including area code: (713) 495-3000 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Common Stock, $0.01 par value NASDAQ/NMS Preferred Stock purchase rights Indicate by check mark whether the registrant (1) has filed all reports required by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [_] Indicate by check mark if disclosure of delinquent filers pursuant to item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this 10-K or any amendment to this Form 10-K. [X] The aggregate market value of the voting stock held by non-affiliates of the registrant at March 14, 2001 was approximately $114,125,643. As of March 14, 2001, the number of outstanding shares of the registrant's common stock was 14,046,233. Documents Incorporated by Reference: Portions of the registrant's annual proxy statement, to be filed within 120 days after December 31, 2000, are incorporated by reference into Part III. - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES Annual Report on Form 10-K For the Year Ended December 31, 2000 TABLE OF CONTENTS
Page Number ------ PART I Item 1. Business................................................. 3 Item 2. Properties............................................... 9 Item 3. Legal Proceedings........................................ 18 Item 4. Submission of Matters to a Vote of Security Holders...... 18 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters...................................... 19 Item 6. Selected Financial Data.................................. 20 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations..................... 20 Item 7a. Quantitative and Qualitative Disclosures About Market Risk..................................................... 29 Item 8. Financial Statements and Supplementary Data.............. 30 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure..................... 61 PART III Item 10. Directors and Executive Officers of the Registrant....... 61 Item 11. Executive Compensation................................... 61 Item 12. Security Ownership of Certain Beneficial Owners and Management............................................... 61 Item 13. Certain Relationships and Related Transactions........... 61 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K................................................. 61 Signatures......................................................... 64
2 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES PART I Item 1. Business Forward Looking Statements This annual report on Form 10-K includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"). All statements other than statements of historical fact included herein regarding the Company's financial position, estimated quantities and net present values of reserves, business strategy, plans and objectives for future operations and covenant compliance, are forward-looking statements. The Company can give no assurances that the assumptions upon which these statements are based will prove to have been correct. Important factors that could cause actual results to differ materially from the Company's expectations ("cautionary statements") are disclosed under Risk Factors and elsewhere herein. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified by the cautionary statements. General Bellwether Exploration Company ("Bellwether" or the "Company") is an independent energy company engaged in the acquisition, exploitation, development, exploration and production of oil and gas properties. The Company's core areas of activity are the Texas/Louisiana Gulf Coast, both onshore and offshore, southeastern New Mexico, and West Texas. At December 31, 2000, the Company's estimated net proved reserves, using constant prices which were in effect at such date, totaled 17.5 MMBbl of oil, 1.7 MMBbl of natural gas liquids ("NGL"), and 75 Bcf of natural gas for a total of 31.6 million barrels of oil equivalent ("MBOE"). On an equivalency basis, approximately 39% of the Company's estimated net proved reserves were natural gas and approximately 77% of the reserves were developed at such date. In addition to its leasehold interests, the Company has interests in natural gas processing plants in California and West Texas. The Company is party to a Master Service Agreement dated October 1, 1999, ("Master Service Agreement") and six specific contracts ("Contracts") which require Torch Energy Advisors, Inc ("Torch") to administer certain activities of the Company including oil and gas marketing, operation of oil and gas properties, land functions, accounting, risk management, legal and information technology. The Master Services Agreement may be terminated by the Company upon 90 days prior notice, subject to a fee based on the remaining terms of the Contracts. The Contracts have initial terms ranging from two to five years. Neither the Master Service Agreement nor the Contracts may be terminated by Torch prior to the expiration of their initial terms. The various Contracts have annual fees ranging from fixed and variable amounts of $0.6 million to $3.0 million plus fees based upon percentages of production ranging from 1/2% to 2%, depending on the product. In order to facilitate greater comparability with its peer group by the financial community, the Company changed its fiscal year to the calendar year, beginning January 1, 1998. This resulted in a six-month transition period of July 1, 1997 through December 31, 1997 ("transition period"). Proposed Merger On January 24, 2001, the Company entered into an Agreement and Plan of Merger with Bargo Energy Company ("Bargo"). Pursuant to the agreement and plan of merger Bargo will be merged with and into Bellwether, and Bellwether will be renamed. Contemporaneously with the merger, Bellwether proposes to increase its authorized common stock to 65.0 million shares and amend its 1996 Stock Incentive Plan to increase the number of shares reserved for issuance under the plan by 2.0 million shares. Bargo shareholders will receive a combination of cash and Bellwether stock as consideration for the merger. The merger is subject to the adoption 3 and approval of the agreement and plan of merger by the Bellwether stockholders and the Bargo stockholders, and the absence of any law or court order preventing the merger. It is anticipated that Bellwether's stockholder meeting will be held in the second quarter of 2001. The merger will be accounted for using the purchase method of accounting. Oil and Gas Activities In 1987 and 1988, the Company merged with two independent oil and gas companies owned by institutional investors and managed by Torch Energy Advisors Incorporated ("Torch"). Since those mergers, the Company has operated under agreements, pursuant to which the Company outsources certain administrative functions to Torch. In April 1997, the Company acquired oil and gas properties and $13.9 million of working capital from affiliates of Torch ("Partnership Transactions"), for $141.1 million after purchase price adjustments. The Company financed the Partnership Transactions and related fees, with $34.1 million net proceeds of a common stock offering, $97.0 million net proceeds of $100.0 million offering of 10 7/8% Senior Subordinated Notes due 2007 (the "Offerings") and advances under a new credit facility ("Senior Credit Facility"). In addition, as consideration for advisory services, Torch was issued 150,000 shares of the Company's common stock and a warrant, expiring in April 2002, to purchase 100,000 shares of common stock at $9.90 per share. The warrant and shares were valued at $1.5 million and recorded as a cost of the Partnership Transactions. In December 1998, Bellwether was the successful bidder for the Charapa field in Ecuador and, as a result, the Company was awarded a contract for production and exploration of crude oil in the Charapa field. The contract provides the Company with approximately 45% of the crude oil produced above the base production curve. The base production curve is defined as the production profile of the crude oil projected by the Ecuadorian government hydrocarbons' subsidiary. Bellwether is also entitled to recoup lease operating expenses associated with the base production. Bellwether took over operations of the field in January 2000. In February 2000, Bellwether took over operations of another Ecuadorian field, the Tiguino field. The contract with the government is similar for both fields. A Bellwether subsidiary operates the field on behalf of Petroleos Colombianos ("Petrocol"), which had been granted a 25% interest and operatorship by the Ecuadorian government. Bellwether negotiated with Petrocol and other interest owners and by July 2000 had increased its interest to 70% and had been assigned the field operatorship. Agreements transferring ownership and operatorship in the Tiguino field have been signed by all parties, but the final government approval of the transaction has not yet been obtained. Such approval is necessary for the agreements to be accepted in Ecuador. Bellwether has received a legal opinion that it is legally entitled to 70% of production from the field and has also received confirmation that the government has never failed to approve similar assignments. During 2000, after substantial analysis of its property portfolio in 1999, Bellwether began divesting of several non-core properties. The high oil and gas prices during 2000 created a favorable market for such properties. By December 31, 2000, Bellwether had sold approximately 6.4 MMBOE, or 17%, of its beginning of the year reserves, for gross proceeds of approximately $49 million. Business Strategy The Company is committed to achieving outstanding performance in all areas of the Company's business to maximize profits and shareholder return. This goal will be pursued through the following business strategy: Pursue Attractive Company or Acquisition Opportunities in Core Areas. The Company believes that acquiring oil and gas reserves using cash and/or stock as the transaction currency is the most effective way to increase shareholder value in the next one to two years. The Company believes that this strategy will allow it to add attractively priced reserves, further improve the quality of its property portfolio, and achieve economies of scale in production operations, and improve exposure in the financial markets. Once a company or a property has been acquired, the Company immediately employs an aggressive exploitation program to increase production, reduce operating costs and develop low risk exploration opportunities. 4 Focus Activities in Core Areas. The Company will enhance its competitive position by focusing its activities within core geographic areas where it has significant existing assets and infrastructure, superior technical expertise and experience, a technical/operational database and demonstrated business know-how. The Company's current core areas are the Texas-Louisiana Gulf Coast, both onshore and offshore, and southeastern New Mexico. The Company may seek to establish additional core areas in the future that are complementary to its strategy. Contain and Reduce Cost. In order to maintain a competitive cost structure and to increase efficiency, the Company will continuously seek to reduce cost, operating capital and overhead. In this regard, the Company outsources certain non-strategic functions, and monitors the costs and benefits of those outsourced activities to ensure that maximum value is being received. Additionally, the Company will regularly review its property base to identify non-core and lower margin assets. Those assets will be divested to allow redeployment of capital to more profitable activities, or to reduce outstanding debt. Increase Number of High Value Operated Properties. The Company will increase efficiency, establish greater control and enhance economic impact by increasing its holdings in higher value properties that are operated by the Company. This objective will be a principal criteria in the execution of its acquisition and divestiture strategies. Additionally, the Company's exploration and exploitation programs will focus on internally generated prospects. Utilize Technology Effectively. The Company will seek to improve its success rates and reduce its finding and operating costs by employing state of the art technology in its exploration, development and operating activities. Its exploration and development program will utilize 3-D seismic evaluation, sophisticated seismic processing and modeling tools and computer aided exploration and development systems. Operationally, the Company will employ horizontal drilling, enhanced recovery methods and advanced completion and production techniques where they are cost effective. Use an Interdisciplinary Approach. The Company utilizes interdisciplinary teams composed of geologists, geophysicists and engineers in the generation and evaluation of acquisition, exploration and exploitation investment opportunities. Through this approach the Company will maximize the identification and quantification of opportunities and reduce risk through the application of complementary experience, know-how and technology. Markets Bellwether's ability to market oil and gas from the Company's wells depends upon numerous domestic and international factors beyond the Company's control, including: 1) the extent of domestic production and imports of oil and gas, 2) the proximity of gas production to gas pipelines, 3) the availability of capacity in such pipelines, 4) the demand for oil and gas by utilities and other end users, 5) the availability of alternate fuel sources, 6) the effects of inclement weather, 7) state, federal and international regulation of oil and gas production, and 8) federal regulation of gas sold or transported in interstate commerce. No assurances can be given that Bellwether will be able to market all of the oil or gas produced by the Company or that favorable prices can be obtained for the oil and gas Bellwether produces. The Company from time to time may enter into crude oil and natural gas price swaps or other similar hedge transactions to reduce its exposure to price fluctuations. 5 In view of the many uncertainties affecting the supply of and demand for oil, gas and refined petroleum products, the Company is unable to predict future oil and gas prices and demand or the overall effect such prices and demand will have on the Company. The marketing of oil and gas by Bellwether can be affected by a number of factors, which are beyond the Company's control, the exact effects of which cannot be accurately predicted. Sales to Torch Co-Energy LLC accounted for approximately 24%, 22% and 28% of fiscal year 2000, 1999 and 1998 oil and gas revenues, respectively. The contract with Torch Co-Energy is for an initial three year term from December 1996 and is renewable month to month after such term. It provides for payment of index pricing (tied to Inside FERC postings) less gathering and transportation charges to point of delivery. Sales to Valero Industrial Gas, L.P. accounted for 18% of fiscal 1997 revenues and are based upon a month to month contract (initial term of contract ended in May 1998 with month to month renewals) which provides for index pricing less gathering, dehydration and other transportation type fees. There are no other significant delivery commitments and substantially all of the Company's U.S. oil and gas production is sold at market responsive pricing through a marketing affiliate of Torch. Bellwether's Ecuadorian crude oil was sold to YPF in the year 2000 and accounted for approximately 4% of the total Company oil and gas revenue for the year. Management of the Company does not believe that the loss of any single customer or contract would materially affect the Company's business. Regulation Federal Regulations Transportation of Gas. The Company's sales of natural gas are affected by the availability, terms and cost of transportation. The rates, terms and conditions applicable to the interstate transportation of gas by pipelines are regulated by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act ("NGA"), as well as under section 311 of the Natural Gas Policy Act ("NGPA"). Since 1985, the FERC has implemented regulations intended to increase competition within the gas industry by making gas transportation more accessible to gas buyers and sellers on an open-access, non- discriminatory basis. The FERC has announced several important transportation-related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of- service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC's pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets. Sales and Transportation of Oil. Sales of oil and condensate can be made by the Company at market prices and are not subject at this time to price controls. The price that the Company receives from the sale of these products will be affected by the cost of transporting the products to market. FERC regulations governing the rates that may be charged by oil pipelines by use of an indexing system for setting transportation rate ceilings. In certain circumstances, the new rules permit oil pipelines to establish rates using traditional cost of service and other methods of rate making. Legislative Proposals. In the past, Congress has been very active in the area of gas regulation. In addition, there are legislative proposals pending in the state legislatures of various states, which, if enacted, could significantly affect the petroleum industry. At the present time it is impossible to predict what proposals, if any, might actually be enacted by Congress or the various state legislatures and what effect, if any, such proposals might have on the Company's operations. Federal, State or Indian Leases. In the event the Company conducts operations on federal, state or Indian oil and gas leases, such operations must comply with numerous regulatory restrictions, including various nondiscrimination statutes, and certain of such operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management ("BLM") or, in the case of the Company's Outer Continental Shelf ("OCS") leases in federal waters, Minerals Management Service 6 ("MMS") or other appropriate federal or state agencies. The Company's OCS leases in federal waters are administered by the MMS and require compliance with detailed MMS regulations and orders. The MMS has promulgated regulations implementing restrictions on various production-related activities, including restricting the flaring or venting of natural gas. Under certain circumstances, the MMS may require any Company operations on federal leases to be suspended or terminated. Any such suspension or termination could materially and adversely affect the Company's financial condition and operations. On March 15, 2000, the MMS issued a final rule effective June 2000, which amends its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. Among other matters, this rule amends the valuation procedure for the sale of federal royalty oil by eliminating posted prices as a measure of value and relying instead on arm's length sales prices and spot market prices as market value indicators. Because the Company sells its production in the spot market and, therefore, pays royalties on production from federal leases, it is not anticipated that this final rule will have any substantial impact on the Company. The Mineral Leasing Act of 1920 (the "Mineral Act") prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies "similar or like privileges" to citizens of the United States. Such restrictions on citizens of a "non- reciprocal" country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation's lease can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. The Company owns interests in numerous federal onshore oil and gas leases. It is possible that the Common Stock will be acquired by citizens of foreign countries, which at some time in the future might be determined to be non-reciprocal under the Mineral Act. State Regulations. Most states regulate the production and sale of oil and gas, including: 1) requirements for obtaining drilling permits, 2) the method of developing new fields, 3) the spacing and operation of wells and 4) the prevention of waste of oil and gas resources. The rate of production may be regulated and the maximum daily production allowable from both oil and gas wells may be established on a market demand or conservation basis or both. The Company owns certain natural gas pipeline facilities that it believes meet the traditional tests the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction under the NGA. State regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. The Company may enter into agreements relating to the construction or operation of a pipeline system for the transportation of gas. To the extent that such gas is produced, transported and consumed wholly within one state, such operations may, in certain instances, be subject to the jurisdiction of such state's administrative authority charged with the responsibility of regulating intrastate pipelines. In such event, the rates which the Company could charge for gas, the transportation of gas, and the construction and operation of such pipeline would be subject to the rules and regulations governing such matters, if any, of such administrative authority. Environmental Regulations General. The Company's activities are subject to existing federal, state and local laws and regulations governing environmental quality and pollution control. Activities of the Company with respect to gas facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing gas and other products, are also subject to stringent environmental regulation by state and federal authorities including the Environmental Protection Agency ("EPA"). Risks are inherent in oil and gas exploration and production operations, and no assurance can be given that significant costs and liabilities will not be incurred in connection with environmental compliance issues. The Company cannot predict what effect 7 future regulation or legislation, enforcement policies issued thereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company's operations could have on its activities. Solid and Hazardous Waste. The Company currently owns or leases, and has in the past owned or leased, numerous properties that for many years have been used for the exploration and production of oil and gas. Although the Company believes it has utilized operating and waste disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by the Company or on or under locations where such wastes have been taken for disposal. In addition, many of these properties have been owned or operated by third parties. The Company had no control over such parties' treatment of hydrocarbons or other solid wastes and the manner in which such substances may have been disposed or released. State and federal laws applicable to oil and gas wastes and properties have gradually become stricter over time. Under these new laws, the Company could be required to remove or remediate previously disposed wastes (including wastes disposed or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future contamination. The Company generates wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The EPA and various state agencies have limited the approved methods of disposal for certain hazardous and non-hazardous wastes. Furthermore, it is possible that certain wastes generated by the Company's oil and gas operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes" under RCRA or other applicable statutes, and therefore be subject to more rigorous and costly operating and disposal requirements. Superfund. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include the owner and operator of a disposal site where a release occurred and any company that disposed or arranged for the disposal of the hazardous substance released at the site. CERCLA also authorizes the EPA and, in some cases, third parties, to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs of such action. In the course of its operations, the Company has generated and will generate wastes that may fall within CERCLA's definition of "hazardous substances." The Company may also be an owner of sites on which "hazardous substances" have been released. The Company may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been disposed. Oil Pollution Act. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose certain duties and liabilities on "responsible parties" related to the prevention of oil spills and damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or to cooperate fully in the cleanup, liability limits also do not apply. Few defenses exist to the liability imposed by the OPA. The failure to comply with OPA requirements may subject a responsible party to civil or even criminal liability. The OPA also imposes ongoing requirements on a responsible party, including proof of financial responsibility to cover at least some costs in a potential spill. Certain amendments to the OPA that were enacted in 1996 require owners and operators of offshore facilities that have a worst case oil spill potential of more than 1,000 barrels to demonstrate financial responsibility in amounts ranging from $10 million in specified state 8 waters and $35 million in federal OCS waters, with higher amounts, up to $150 million based upon worst case oil spill discharge volume calculations. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities. Air Emissions. The operations of the Company are subject to local, state and federal laws and regulations for the control of emissions from sources of air pollution. Administrative enforcement actions for failure to comply strictly with air regulations or permits may result in the payment of civil penalties and, in extreme cases, the shutdown of air emission sources. The Company believes it is in compliance with all air emission regulations. OSHA and other Regulations. The Company is subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to- know regulations under Title III of CERCLA and similar state statutes require the Company to organize and/or disclose information about hazardous materials used or produced in the Company's operations. The Company believes that it is in substantial compliance with these applicable requirements. Competition The oil and gas industry is highly competitive in all of its phases. Bellwether encounters competition from other oil and gas companies in all areas of the Company's operations, including the acquisition of reserves and producing properties and the marketing of oil and gas. Many of these companies possess greater financial and other resources than Bellwether. Competition for producing properties is affected by the amount of funds available to the Company, information about a producing property available to the Company and any standards established by the Company for the minimum projected return on investment. Competition may also be presented by alternate fuel sources. Item 2. Properties Domestic Properties The Company's domestic exploration, development and acquisition activities are focused in three core areas: Gulf Coast, Offshore Gulf of Mexico and Permian Basin. The company primarily owns working interests in domestic wells. Working interests are burdened by operating costs whereas royalty interests receive a share of unburdened revenues. As used herein, "reserve life" is the Company's estimated net proved at the end of year divided by production during the year. Reserve life is a measure of the productive life of an oil and gas property or a group of oil and gas properties, expressed in years. Reserve life index for the years ended December 31, 2000, 1999 and 1998 equal the estimated net proved reserves attributable to a property or group of properties divided by production from the property or group of properties for the four fiscal quarters preceding the date as of which the proved reserves were estimated. Gulf Coast--The fields in this area are located in Louisiana and Texas. These fields produce gas as the primary product. Bellwether owns an interest in approximately 140 wells and the reserves from these wells account for about 35% of the Company's discounted present value. The average reserve life is 6 years. The average working interest of the Company in the wells is approximately 15 percent. Gulf of Mexico--The fields in this area are located in state and federal waters offshore Louisiana and Texas. These fields produce gas as the primary product. The Company owns an interest in approximately 120 wells and the reserves from these wells account for about 35% of the Company's discounted present value. The average reserve life is 4 years. The average working interest of the Company in the wells is approximately 20 percent. Permian Basin--The fields in this area are located in West Texas and New Mexico. The West Texas fields produce oil and the New Mexico fields produce gas as the primary product. The Company owns an interest in 9 approximately 1,200 wells and the reserves from these wells account for about 15% of the Company's discounted present value. The average reserve life is 14 years. The average working interest of the Company in the wells is approximately 10 percent. Other--Non-core fields are located in California, Oregon, Oklahoma and Wyoming. The Company owns an interest in approximately 100 wells and the reserves from these wells account for about 6% of the Company's discounted present value. International Properties Ecuador--Bellwether operates two concessions in Ecuador, each of which contains one producing field. The working interest in the Charapa field is 90% and the working interest in the Tiguino field is 70%. Oil is the only sales product from both fields. Both fields are subject to contracts with the Ecuador government, under which the company has a share of production above specified base levels. Reserves from these wells account for about 9% of the Company's discounted present value. The average reserve life is 7 years. Reserves Estimated net proved oil and gas reserves at December 31, 2000 decreased approximately 18% from December 31, 1999. Properties, with proved reserves totaling 6.4 MMBOE, or about 17% of 1999 reserves, were sold during 2000. This decrease was partially offset by the increased oil and gas prices and the acquisition of a 70% working interest in the Tiguino field concession in Ecuador. The Company has not filed oil or gas reserve information with any foreign government or federal authority or agency that contain reserves materially different than those set forth herein. The following table sets forth certain information as of December 31, 2000 for the Company's core areas.
Net Production Net Proved Reserves -------------------------- -------------------------- Oil & Oil Oil & Oil NGL Gas Equivalent NGL Gas Equivalent Area (MBBLS) (MMCF) MBOE (MBBLS) (MMCF) (MBOE) - ---- ------ ------ ---------- ------ ------ ---------- Gulf Coast................ 372 3,368 933 877 29,063 5,721 Gulf of Mexico............ 708 7,678 1,988 1,759 25,269 5,971 Permian Basin............. 379 1,139 569 5,447 12,279 7,493 Ecuador*.................. 174 -- 174 7,813 -- 7,813 Other**................... 747 8,293 2,129 3,241 8,118 4,594 ----- ------ ----- ------ ------ ------ 2,380 20,478 5,793 19,137 74,729 31,592 ===== ====== ===== ====== ====== ======
- -------- * Such reserves are pursuant to a contract with the Ecuadorian government under which the Company does not own the reserves but where the Company has a contractual right to produce the reserves and receive revenue. The Ecuadorian government has not issued final approval for the assignment of 4.9 MMBOE purchased by the Company; however, the Company has a legal opinion stating that it is legally entitled to the production of such reserves. ** Net production includes nine to twelve months of production from fields that were sold in the year 2000. Such fields have been removed from December 31, 2000 proved reserves. In general, estimates of economically recoverable oil and natural gas reserves and of the future net cash flows therefrom are based upon a number of variable factors and assumptions, such as historical production from the properties, assumptions concerning future oil and natural gas prices, future operating costs and the assumed effects of regulation by governmental agencies, all of which may vary considerably from actual results. All such estimates are to some degree speculative, and classifications of reserves are only attempts to define the degree of speculation involved. Estimates of the economically recoverable oil and natural gas reserves attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of future 10 net cash flows expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. The Company's actual production, revenues, severance and excise taxes and development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material. Estimates with respect to proved reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves rather than actual production history. Estimates based on these methods are generally less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be substantial, in the estimated reserves. In accordance with applicable requirements of the Securities and Exchange Commission ("SEC"), the estimated discounted future net cash flows from estimated proved reserves are based on prices and costs as of the date of the estimate unless prices or costs subsequent to that date are contractually determined. Additionally, the impact of financial derivatives is not considered. Actual future prices and costs may be materially higher or lower than prices or costs as of the date of the estimate. Actual future net cash flows also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. Acreage The following table sets forth the acres of developed and undeveloped oil and gas properties in which the Company held an interest as of December 31, 2000. Undeveloped acreage is considered to be those leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves. A gross acre in the following table refers to the number of acres in which a working interest is owned directly by the Company. The number of net acres is the sum of the fractional ownership of working interests owned directly by the Company in the gross acres expressed as a whole number and percentages thereof. A net acre is deemed to exist when the sum of fractional ownership of working interests in gross acres equals one. All of the undeveloped acreage is domestic.
Gross Net --------- ------- Developed Acreage Domestic.................................................... 404,141 75,124 Ecuador..................................................... 123,674 98,951 Undeveloped Acreage........................................... 1,034,074 364,418 --------- ------- Total..................................................... 1,561,889 538,493 ========= =======
Bellwether believes that the title to its oil and gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in the opinion of the Company, are not so material as to detract substantially from the use or value of such properties. The Company's properties are typically subject, in one degree or another, to one or more of the following: 1) royalties and other burdens and obligations, express or implied, under oil and gas leases; 2) overriding royalties and other burdens created by the Company or its predecessors in title; 3) a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements, farmout agreements, production sales contracts and other agreements that may affect the properties or their titles; 4) back-ins and reversionary interests arising under purchase agreements and leasehold assignments; 5) liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements; 6) pooling, unitization and communitization agreements, declarations and orders; and 7) easements, restrictions, rights- of-way and other matters that commonly affect oil and gas producing property. To the extent that such burdens and obligations affect the Company's rights to 11 production revenues, they have been taken into account in calculating the Company's net revenue interests and in estimating the size and value of the Company's reserves. Bellwether believes that the burdens and obligations affecting the Company's properties are conventional in the industry for properties of the kind owned by the Company. Productive Wells The following table sets forth Bellwether's gross and net interests in productive oil and gas wells as of December 31, 2000. Productive wells are defined as producing wells and wells capable of production. Gross wells, as it applies to wells in the following tables, refer to the number of wells in which a working interest is owned directly by the Company. A "net well" is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional ownership of working interests owned directly by the Company in gross wells expressed as whole numbers and percentages thereof.
Gross Net ----- --- Oil Wells Domestic...................................................... 1,138 150 Ecuador....................................................... 7 5 Gas Wells....................................................... 565 112 ----- --- Total....................................................... 1,710 267 ===== ===
Production The Company's principal domestic production volumes during the fiscal year ended December 31, 2000 were from the states of Louisiana, Texas, and Oregon from federal waters in offshore California and from federal and state waters in the Gulf of Mexico. The Charapa and Tiguino fields in Ecuador accounted for about 8% of the Company's oil production. Data relating to production volumes, average sales prices, average unit production costs and oil and gas reserve information appears in Note 12 of the Notes to Consolidated Financial Statements--Supplemental Information. Drilling Activity and Present Activities During the last three fiscal years the Company's principal domestic drilling activities occurred in the Gulf Coast, the Gulf of Mexico, Oregon and New Mexico. Development of the Charapa and Tiguino fields in Ecuador accounted for all international activities. The following table sets forth the results of drilling activity for the last three fiscal years. Exploratory Wells
Gross Net ---------------------- ---------------------- Dry Dry Productive Holes Total Productive Holes Total ---------- ----- ----- ---------- ----- ----- 1998--Domestic.................... 14 5 19 4.10 1.52 5.62 1999--Domestic.................... 8 4 12 3.75 2.04 5.79 2000--Domestic.................... 7 6 13 3.98 1.96 5.94 2000--Ecuador..................... -- -- -- -- -- --
12 Development Wells
Gross Net ---------------------- ---------------------- Dry Dry Productive Holes Total Productive Holes Total ---------- ----- ----- ---------- ----- ----- 1998--Domestic.................... 69 4 73 7.53 .52 8.05 1999--Domestic.................... 13 2 15 4.39 .14 4.53 2000--Domestic.................... 46 8 54 15.01 2.70 17.71 2000--Ecuador..................... 1 3 4 .7 2.7 3.4
The Company had 6 domestic wells in progress as of December 31, 2000. Gas Plants As of December 31, 2000, the Company owned interests in the following gas plants:
Fiscal Year 2000 ----------------------------- Throughput Ownership Facility State Operator Capacity MMCFD Interest -------- ----- -------- MMCFD ---------- --------- Point Pedernales Gas Plant.. CA Nuevo Energy Company 15 4 19.7% Torch Energy Marketing Snyder Gas Plant............ TX Inc. 60 15 11.9% Diamond M-Sharon Ridge Gas Plant(1)................... TX Exxon Company, U.S.A. (1) (1) (1)
- -------- (1) The Company has a 32.0% interest in the operations of the former Diamond M-Sharon Ridge Gas Plant. This plant was dismantled in December 1993 and the gas is being processed by Snyder Gas Plant pursuant to a processing agreement. Risk Factors Volatility of Oil and Gas Prices and Markets Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors beyond the control of the Company. These factors include: 1) weather conditions in the United States, 2) the condition of the United States economy, 3) the actions of the Organization of Petroleum Exporting Countries, 4) governmental regulation, 5) political stability in the Middle East and elsewhere, 6) the foreign supply of oil and gas, 7) the price of foreign imports, and 8) the availability of alternate fuel sources. During 2000 oil prices were higher than in the three previous years and natural gas prices were at record high levels. Any substantial and extended decline in the price of oil or gas would have an adverse effect on the Company's carrying value of its proved reserves, its borrowing capacity, its ability to obtain additional capital, and its revenues, profitability and cash flows. Volatile oil and gas prices make it difficult to estimate the value of producing properties in connection with acquisitions and often cause disruption in the market for oil and gas producing properties as buyers and sellers 13 have difficulty agreeing on such value. Price volatility also makes it difficult to budget for and project the return on acquisitions and exploitation, development and exploration projects. The availability of a ready market for the Company's oil and natural gas production also depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of reserves to, and the capacity of, oil and natural gas gathering systems, pipelines or trucking and terminal facilities. Wells may temporarily be shut-in for lack of a market or due to inadequacy or unavailability of pipeline or gathering system capacity. Ability to Replace Reserves The Company's future performance depends upon its ability to find, develop and acquire additional oil and gas reserves that are economically recoverable. The proved reserves of Bellwether will generally decline as those reserves are depleted. The Company therefore must locate and develop or acquire new oil and gas reserves to replace those being depleted by production. Because the Company's reserves are characterized by relatively rapid decline rates, the Company's revenues will decline rapidly without successful exploration, development or acquisition activities. No assurances can be given that the Company will be able to find and develop or acquire additional reserves at an acceptable cost. Acquisition Risks The Company's rapid growth in recent years has been attributable in significant part to domestic and, to a less significant part, international acquisitions of oil and gas properties. The Company expects to continue to evaluate and, where appropriate, pursue acquisition opportunities on terms management considers favorable to the Company. There can be no assurance that suitable acquisition candidates will be identified in the future, or that the Company will be able to finance such acquisitions on favorable terms. In addition, the Company competes against other companies for acquisitions, and there can be no assurances that the Company will be successful in the acquisition of any material property interests. Further, there can be no assurances that any future acquisitions made by the Company will be integrated successfully into the Company's operations or will achieve desired profitability objectives. The successful acquisition of producing properties requires an assessment of: 1) recoverable reserves, 2) future production rates, 3) exploration and exploitation potential and timing, 4) future oil and natural gas prices, 5) operating costs, 6) infrastructure requirements, 7) potential environmental and other liabilities and 8) other factors beyond the Company's control. In connection with such an assessment, the Company performs a review of the properties that it believes to be generally consistent with industry practices. Nonetheless, the resulting assessments are inexact and their accuracy is inherently uncertain, and such a review may not reveal all existing or potential problems, nor will it necessarily permit the Company to become sufficiently familiar with the properties to fully assess their merits and deficiencies. Inspections may not always be performed on every well, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. In addition, sellers of properties may be unwilling or financially unable to indemnify the Company for known or unknown liabilities at the time of an acquisition. 14 Additionally, significant acquisitions can change the nature of the operations and business of the Company depending upon the character of the acquired properties, which may be substantially different in operating and geologic characteristics or geographic location than existing properties. While the Company's operations are focused in Texas, Louisiana, offshore California, the Gulf of Mexico, and Ecuador there is no assurance that the Company will not pursue acquisitions or properties located in other geographic areas. On January 24, 2001, Bellwether entered into an Agreement and Plan of Merger with Bargo Energy Company. The merger is subject the adoption and approval of the agreement by Bellwether shareholders, Bargo shareholders and the absence of any law or court order preventing the merger. Bargo and Bellwether filed a registration statement on Form S-4 (registration number 333-54798) with the SEC on February 1, 2001. A detailed discussion of risks associated with the proposed merger may be found there. Drilling Risks Drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain and cost overruns are common. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including: 1) title problems, 2) weather conditions, 3) compliance with governmental requirements, and 4) shortages or delays in the delivery of equipment and services. Substantial Capital Requirements The Company makes, and will continue to make, substantial capital expenditures for the exploitation, exploration, acquisition and production of oil and gas reserves. Historically, the Company has financed these expenditures primarily with the sale of senior subordinated notes, proceeds from bank borrowings, sales of its common stock and cash flow from operations. The Company believes that it will have sufficient cash flow provided by operating activities, the proceeds of equity offerings and borrowings under the Senior Credit Facility to fund planned capital expenditures. If revenues or the Company's borrowing base decrease as a result of lower oil and gas prices, operating difficulties or declines in reserves, the Company may have limited ability to expend the capital necessary to undertake or complete future drilling programs. There can be no assurance that additional debt or equity financing or cash generated by operations will be available to meet these requirements. Significant Leverage and Debt Service The Company's level of indebtedness has several important effects on its future operations, including: 1) a substantial portion of the Company's cash flow from operations must be dedicated to the payment of interest on its indebtedness and will not be available for other purposes, 2) covenants contained in the Company's debt obligations require the Company to meet certain financial tests, and other restrictions limit its ability to borrow additional funds or to dispose of assets and may affect the Company's flexibility in planning for, and reacting to, changes in its business, including possible acquisition activities, and 3) the Company's ability to obtain financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may be impaired. 15 The Company's ability to meet its debt service obligations and to reduce its total indebtedness will be dependent upon the Company's future performance, which will be subject to general economic conditions and to financial, business and other factors affecting the operations of the Company, many of which are beyond its control. There can be no assurance that the Company's future performance will not be adversely affected by such economic conditions and financial, business and other factors. Risks of Foreign Operations The Company was the successful bidder for a marginal field in Ecuador in 1998. Contract negotiations with the Ecuadorian government were completed in late 1999 with operations beginning January 2000. Operatorship of a second marginal field was acquired in July 2000. For these marginal fields, Bellwether partners with other companies in consortiums which are then party to the production sharing agreements with the Ecuadorian government. Bellwether is 90% partner in the first consortium and 70% partner in the second consortium. In addition, on December 30, 1999, the Company acquired an interest in Carpatsky, which has operations in Ukraine. Operations in Ecuador, Ukraine and other areas outside of the United States in which the Company may choose to do business, are subject to the various risks inherent to foreign operations. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection and other political risks, risks of an increase in taxes and governmental policies governing operations of foreign-based companies, and other uncertainties arising out of foreign government sovereignty over the Company's international operations. The Company's international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and investment. In addition, in the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States. Outsourcing Agreement Bellwether currently has 34 employees. The Company is party to a Master Services Agreement ("MSA") with Torch, pursuant to which Torch performs certain administrative functions for the Company, including financial, accounting, marketing, legal and technical support (See Note 4 to the Consolidated Financial Statements). The Company believes that its relationship with Torch provides the Company access to professional, technical and administrative personnel not otherwise available to a company of its size. Bellwether believes that if the MSA were terminated Bellwether could, over time, hire experienced personnel and acquire the accounting and reporting systems and other assets necessary to replace Torch. However, the unanticipated termination of the MSA could have a material adverse effect upon the Company. Conflicts of Interest Mr. J. P. Bryan served as Chief Executive Officer of Bellwether from August 1999 through May 2000. He remained as Chairman of the Board throughout the year. Mr. Bryan is also Senior Managing Director of Torch and owns shares representing 23% of the shares of Torch on a fully diluted basis. Mr. Bryan also owns 1,061,750 shares of Bargo, and a subsidiary of Torch provides outsourcing services to both Bellwether and Bargo. Torch also renders outsourcing services to other independent oil and gas companies and may manage or render management or administrative services for other energy companies in the future. These services may include the review and recommendation of potential acquisitions. It is possible that conflicts may occur between Bellwether and these other companies in connection with possible acquisitions or otherwise in connection with the services rendered by Torch. Although the MSA provides for procedures to reconcile conflicts of interest between these other companies and Bellwether, no assurances can be made that such procedures will fully protect the Company from losses which may occur if a conflict between the Company and these other companies arises. Estimates of Oil and Gas Reserves This document contains estimates of oil and gas reserves owned by the Company, and the future net cash flows attributable to those reserves. There are numerous uncertainties inherent in estimating quantities of proved 16 reserves and cash flows attributable to such reserves, including factors beyond the control of the Company and the reserve engineers. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of an estimate of quantities of reserves, or of cash flows attributable to such reserves, is a function of: 1) the available data, 2) assumptions regarding future oil and gas prices and expenditures for future development and exploitation activities, and 3) engineering and geological interpretation and judgment. Additionally, reserves and future cash flows may be subject to material downward or upward revisions based upon production history, development and exploitation activities and prices of oil and gas. Actual future production, revenue, taxes, development expenditures, operating expenses, quantities of recoverable reserves and the value of cash flows from such reserves may vary significantly from the assumptions and estimates set forth herein. In addition, reserve engineers may make different estimates of reserves and cash flows based on the same available data. In calculating reserves on a oil equivalent basis, gas was converted to oil equivalent at the ratio of one Bbl of oil to six Mcf of gas. While this ratio approximates the energy equivalency of oil to gas on a Btu basis, it may not represent the relative prices received by the Company on the sale of its oil and gas production. The estimated quantities of proved reserves and the discounted present value of future net cash flows attributable to estimated proved reserves set forth herein were prepared in accordance with the rules of the SEC, and are not intended to represent the fair market value of such reserves. Hedging of Production The Company may, from time to time, reduce its exposure to the volatility of oil and gas prices by hedging a portion of its production. In a typical hedge transaction, the Company will have the right to receive from the counterparty to the hedge, the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, the Company is required to pay the counterparty this difference multiplied by the quantity hedged. In such case, the Company is required to pay the difference regardless of whether the Company has sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require the Company to make payments under the hedge agreements even though such payments are not offset by sales of production. Hedging will also prevent the Company from receiving the full advantage of increases in oil or gas prices above the fixed amount specified in the hedge. Operating Hazards, Offshore Operations and Uninsured Risks Bellwether's operations are subject to risks inherent in the oil and gas industry, such as: 1) blowouts, 2) cratering, 3) explosions, 4) uncontrollable flows of oil, gas or well fluids, 5) fires, 6) pollution, 7) earthquakes and 8) environmental risks. These risks could result in substantial losses to the Company due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. Moreover, a portion of the Company's operations are offshore and therefore are subject to a variety of operating risks which occur in to the marine environment, such as hurricanes or other adverse weather conditions, to more extensive governmental regulation, including regulations that may, in certain circumstances, impose strict liability for pollution damage, and to interruption or termination of operations by governmental authorities based on environmental or other considerations. The Company's operations could result in a liability for: 1) personal injuries, 2) property damage, 3) oil spills, 4) discharge of hazardous materials and, 5) remediation and clean-up costs and other environmental damages. The Company could be liable for environmental damages caused by previous property owners. As a result, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could 17 have a material adverse effect on the Company's financial condition and results of operations. The Company maintains insurance coverage for its operations, including limited coverage for sudden environmental damages, but does not believe that insurance coverage for all environmental damages that occur over time is available at a reasonable cost. Moreover, the Company does not believe that insurance coverage for the full potential liability that could be caused by sudden environmental damages is available at a reasonable cost. Accordingly, the Company may be subject to liability or the loss of substantial portions of its properties in the event of certain environmental damages. Environmental and Other Regulation The Company's operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations: 1) require the acquisition of a permit before drilling commences, 2) restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, 3) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and 4) impose substantial liabilities for pollution resulting from the Company's operations. Moreover, the recent trend toward stricter standards in environmental legislation and regulation is likely to continue. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and gas 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 such legislation were to be enacted, it could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these various initiatives could have a similar impact on the Company. Management believes that the Company is in substantial compliance with current applicable environmental laws and regulations. The Oil Pollution Act of 1990 imposes a variety of regulations on "responsible parties" related to the prevention of oil spills. The implementation of new, or the modification of existing, environmental laws or regulations, including regulations promulgated pursuant to the Oil Pollution Act of 1990, could have a material adverse impact on the Company. Competition The Company operates in the highly competitive areas of oil and gas exploration, development and production. The Company's competitors include major integrated oil and gas companies and substantial independent energy companies, many of which possess greater financial and other resources than the Company. Item 3. Legal Proceedings The Company was a defendant in Cause No. C-4417-96-G; A.R. Guerra, et al. v. Eastern Exploration, Inc., et al. in the 370th Judicial District Court of Hidalgo County, Texas. The suit was filed with the Court on October 11, 1996. On May 11, 1999, the trial court granted plaintiff's Motion of Summary Judgement and denied defendants' Motion of Summary Judgement. The trial court awarded plaintiffs in excess of $5.8 million in damages plus interest. In early 2000, the Company settled the case for the sum of $353,500, net to its interest. The Company has been named as a defendant in certain lawsuits incidental to its own business. Management does not believe that the outcome of such litigation will have a material adverse impact on the Company. Item 4. Submission of Matters to a Vote of Security Holders None. 18 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters The Company's common stock is traded on the NASDAQ National Market (Symbol: BELW). There were approximately 760 stockholders of record as of March 14, 2001. The Company has not paid dividends on its common stock and does not anticipate the payment of cash dividends in the immediate future as it contemplates that cash flows will be used for continued growth in Company operations. In addition, certain covenants contained in the Company's financing arrangements restrict the payment of dividends (See Management's Discussion and Analysis of Financial Condition and Results of Operations-- Financing Activities and Note 7 of the Notes to Consolidated Financial Statements). The following table sets forth the range of the high and low sales prices, as reported by the NASDAQ for Bellwether common stock for the periods indicated.
Sales Price ------------ High Low ------ ----- Quarter Ended: March 31,1998.................................................... $11.13 $7.88 June 30, 1998.................................................... $ 9.88 $7.81 September 30, 1998............................................... $ 8.88 $3.81 December 31, 1998................................................ $ 7.69 $4.13 March 31, 1999................................................... $ 5.56 $2.69 June 30, 1999.................................................... $ 5.75 $3.19 September 30, 1999............................................... $ 6.25 $4.00 December 31, 1999................................................ $ 6.19 $3.88 March 31, 2000................................................... $ 7.25 $4.19 June 30, 2000.................................................... $ 9.88 $5.63 September 30, 2000............................................... $ 8.88 $6.69 December 31, 2000................................................ $ 8.50 $5.88
Treasury Stock Repurchases In September 1998, the Board of Directors of the Company authorized the open market repurchase of up to $5.0 million of the Company's common stock during 1998, at times and prices deemed attractive by management. As of December 31, 2000, the Company had repurchased 311,000 shares of common stock in open market transactions at an average purchase price of $6.13 per share. No additional shares were purchased in 1999 and 2000. 19 Item 6. Selected Financial Data The following selected financial data with respect to the Company should be read in conjunction with the Consolidated Financial Statements and supplementary information included in Item 8 (amounts in thousands, except per share data).
Six Month Transition Fiscal Years Year Ended Year Ended Year Ended Period Ended June 30, Dec. 31, Dec. 31, Dec. 31, Ended Dec. ----------------- 2000 1999 1998 31, 1997 1997(1) 1996 ---------- ---------- ---------- ---------- -------- ------- Gas revenues............ $ 62,652 $ 41,559 $ 46,661 $ 26,849 $ 24,323 $ 9,906 Oil revenues............ 49,601 26,705 26,991 17,519 15,006 5,810 Gas plant revenues...... 6,070 3,830 3,170 2,036 6,652 8,719 Interest and other income................. 957 1,335 1,347 609 363 116 -------- -------- -------- -------- -------- ------- Total revenues........ 119,280 73,429 78,169 47,013 46,344 24,551 Production expenses..... 30,509 21,532 25,381 13,836 11,437 5,317 Gas plant expenses...... 2,677 2,366 1,967 1,232 3,322 5,185 Transportation costs.... 270 316 435 205 262 50 Depreciation, depletion and amortization....... 32,654 23,863 39,688 16,352 15,574 8,148 Impairment expense...... -- -- 73,899 -- -- -- Disposition of hedges... 8,671 -- -- -- -- -- General and administrative expenses............... 9,138 7,848 8,459 3,748 4,042 3,013 Interest expense........ 15,375 11,845 11,660 5,978 4,477 1,657 Provision for income tax (benefit).............. (12,222) (3,154) (6,069) 2,114 2,585 46 Other expenses.......... -- -- -- -- -- 153 -------- -------- -------- -------- -------- ------- Total expenses........ 87,072 64,616 155,420 43,465 41,699 23,569 -------- -------- -------- -------- -------- ------- Net income (loss)....... $ 32,208 $ 8,813 $(77,251) $ 3,548 $ 4,645 $ 982 ======== ======== ======== ======== ======== ======= Earnings (loss) per common share........... $ 2.32 $ 0.64 $ (5.50) $ 0.26 $0.46 $ 0.11 Earnings (loss) per common share--diluted.. $ 2.27 $ 0.63 $ (5.50) $ 0.25 $ 0.45 $ 0.11 Working capital......... $ 7,212 $ 3,770 $ 6,077 $ 13,964 $ 22,783 $ 5,168 Long-term debt, net of current maturities..... $125,450 $130,000 $104,400 $100,000 $115,300 $13,048 Stockholders'equity..... $ 56,960 $ 23,314 $ 14,489 $ 91,669 $ 87,924 $46,597 Total assets............ $221,545 $171,761 $131,196 $214,757 $222,648 $67,225
- -------- (1) Includes operations from the Partnership Transactions beginning April 1, 1997. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Bellwether is an independent energy company primarily engaged in the acquisition, exploitation and development of and exploration for oil and gas properties. Since April 1997 the Company has employed a balanced growth strategy combining strategic acquisitions of producing properties with technology driven development and exploration drilling. As a result, the Company's results of operations have been significantly affected by its success in acquiring oil and gas properties and its ability to maintain or increase production through its development activities. In April 1997, the Company purchased oil and gas properties and $13.9 million of working capital from affiliates of Torch for an adjusted purchase price of $141.1 million. The acquisition was recorded effective April 1, 1997 and the operations of the Company include the Partnership Transactions from that date. The Partnership Transactions were financed with $34.1 million of net proceeds of a common stock offering, $97.0 million net proceeds of 10 7/8% Senior Subordinated Notes due 2007 (the "Notes") and borrowings under a 20 new credit facility. In addition, as consideration for advisory services Torch was issued 150,000 shares of the Company's common stock and a warrant, expiring in April 2002, to purchase 100,000 shares at $9.90 per share for advisory services rendered in connection with the Partnership Transactions. The warrant and shares were valued at $1.5 million and recorded as a cost of the Partnership Transactions. In order to facilitate greater comparability with its peer group by the financial community, the Company changed its fiscal year to the calendar year beginning January 1, 1998. The Company uses the full cost method of accounting for its investment in oil and gas properties. Under the full cost method of accounting, all costs of acquisition, exploration and development of oil and gas reserves are capitalized in a "full cost pool" as incurred. Oil and gas properties in the pool, plus estimated future expenditures to develop proved reserves and future abandonment, site reclamation and dismantlement costs, are depleted and charged to operations using the unit of production method based on the ratio of current production to total proved recoverable oil and gas reserves. To the extent that such capitalized costs (net of depreciation, depletion and amortization) exceed the discounted future net revenues on an after-tax basis of estimated proved oil and gas reserves, such excess costs are charged to operations. Once incurred, the writedown of oil and gas properties is not reversible at a later date even if oil and gas prices increase. Sharp declines in oil and gas prices, including further gas price decline subsequent to year end, and to a lesser extent, downward revision in estimated proved reserves resulted in a $73.9 million pretax impairment charge ($71.6 million after tax), in the fiscal year ended December 31, 1998. Prices used in computing the impairment were February 23, 1999 prices and were based on a NYMEX oil price of $12.48 per barrel and a NYMEX gas price of $1.71 per MMBTU, adjusted to the wellhead. No such write down was required for the years ended December 31, 1999 and 2000. Financing Activities The Company's outstanding indebtedness totals $125.5 million at December 31, 2000, $100 million is attributable to the 10 7/8% Senior Subordinated Notes due in 2007 while $25.5 million is outstanding under a senior revolving credit facility with an ultimate maturity date of August 2002. In April 1997, the Company entered into a senior revolving credit facility ("Senior Credit Facility") in an amount up to $90.0 million, with a borrowing base of $55.0 million, and a maturity date of November 5, 2003. Subsequent amendments reflecting the impact of property sales in 2000 reduced the borrowing base to $34.5 million at December 31, 2000. As of December 31, 2000, $25.5 million was outstanding under the Senior Credit Facility. A February 2001 amendment reduced the credit facility to $40 million, increased the borrowing base to $35 million, and changed the maturity date to August 2002. Bellwether may elect an interest rate based either on a margin plus London Interbank Offered Rate ("LIBOR") or the higher of the prime rate or the sum of 0.5% of 1% plus the Federal Funds Rate. For LIBOR borrowings, the interest rate will vary from LIBOR plus 1.0% to LIBOR plus 3.5% based upon the borrowing base usage. The Senior Credit Facility contains various covenants including certain required financial measurements for current and interest ratios and consolidated tangible net worth. As of December 31, 2000 the Company was in compliance with all debt covenants. In addition, the Senior Credit Facility contains the following limitations: 1) Bellwether and its subsidiaries will not sell all or substantially all of their assets to another person, 2) none of Bellwether or its subsidiaries will incur additional indebtedness with the exception of permitted indebtedness, 3) the indebtedness of Bellwether's subsidiaries will not exceed 10% of consolidated tangible net worth (indebtedness from subsidiaries to Bellwether or guarantors is permitted), 4) none of Bellwether or its subsidiaries will make any restricted payments or restricted investments unless no default exists under the Senior Credit Facility and all such restricted payments and investments made since closing do not exceed the sum of (A) $5 million plus (B) 25% consolidated net income (less 100% of losses) plus (C) net cash proceeds of non-redeemable stock, provided, there are no payments made on permitted subordinated debt prior to stated maturity. 21 In April 1997, the Company issued $100.0 million of 10 7/8% Senior Subordinated Notes that mature April 1, 2007. Interest on the Notes is payable semi-annually on April 1 and October 1. The Notes contain certain covenants, including limitations on: 1) incurrence of debt, 2) other senior subordinated indebtedness, 3) restricted payments, 4) liens as well as restrictions 5) disposition of proceeds of asset sales, 6) mergers, and 7) consolidations or sales of assets. Additionally, the Notes require the Company to offer to purchase the Notes in the event of a change of control. In order to reduce cash paid for interest costs, effective September 22, 1998, the Company entered into an eight and one half year interest rate swap agreement with a notional value of $80 million. Under the agreement, the Company receives a fixed interest rate and pays a floating interest rate based on the simple average of three foreign LIBOR rates. Floating rates are redetermined for a six month period each April 1 and October 1. Through April 1, 2002, the floating rate is capped at 10.875% and capped at 12.375% thereafter. The floating rate for the period from October 1, 2000 to April 1, 2001 is 10.875%. This interest swap is currently accounted for as a hedge. Liquidity and Capital Resources The Company's principal sources of capital for the last three years been the sale of non-core properties, borrowings under bank credit facilities and cash flow from operations. Non-core property divestitures in the year 2000 realized net proceeds of approximately $46.0 million. Most sales were completed during the fourth quarter of 2000. Borrowings from banks were $25.5 million, $30.0 million, and $4.9 million at the end of fiscal years 2000, 1999, and 1998, respectively. At December 31, 2000, available debt capacity under the Senior Credit Facility, after netting $7.4 million in outstanding letters of credit, was $1.6 million. As the Notes mature in November 2007 and the Senior Credit Facility matures in August 2002, the Company has no debt repayment obligation within the next twelve months. Cash flow from operations before changes in assets and liabilities totaled $62.6 million, $30.8 million and $30.4 million for the fiscal years 2000, 1999, and 1998, respectively. Cash flow from operations before changes in working capital for the fiscal year 2000 was significantly impacted by increases in the average prices received for oil and gas production as compared to previous periods. The Company's primary uses of capital have been to fund acquisitions and to fund its exploration and development projects. Acquisitions, net of working capital acquired, totaled $7.1 million, $25.9 million, and $9.6 million for the fiscal years 2000, 1999, and 1998, respectively. Approximately $2.0 million of acquisition costs in the year 2000 related to the Tiguino field in Ecuador. The Company's expenditures for exploration, including unproved property acquisitions, and development of its oil and gas properties totaled $81.3 million, $30.9 million and $30.6 million, for the fiscal years 2000, 1999, and 1998, respectively. Development activities in Ecuador accounted for approximately $10.0 million of expenditures in the year 2000. Under the Company's contract for production of oil in the Charapa field of Ecuador, the Company is required to execute a three year $12 million minimum investment program. Outlook The Company adopted an $82.9 million capital budget for the year ending December 31, 2001 with $52.1 million for acquisitions, $20.0 million for domestic exploration and development, and $10.7 million for development in Ecuador. This budget is under review in conjunction with the proposed merger with Bargo Energy Company. The Company believes its working capital and net cash flows provided by operating activities are sufficient to meet the exploration and development plans. At December 31, 2000, $1.6 million was available for borrowing under the Senior Credit facility, as amended in February 2001. The Company is continuously reviewing acquisition opportunities and has the goal of concluding one or more acquisitions during 2001. Acquisitions will be funded through additional borrowings under the Senior Credit Facility, borrowings under a new facility and/or the issuance of securities. On January 25, 2001, Bellwether announced plans to merge with Bargo Energy Company. Contemporaneously with the merger, Bellwether proposes to increase its authorized common stock to 65.0 22 million shares and amend its 1996 Stock Incentive Plan to increase the number of shares reserved for issuance under the plan by 2.0 million shares. Under the merger agreement, Bargo shareholders will receive a combination of cash and Bellwether common stock. The merger is conditioned upon its receiving the approval of Bellwether's shareholders and Bargo's shareholders. The merger will be accounted for using the purchase method of accounting. Bellwether's management believes the merger is, among other things, in accordance with Bellwether's long-term strategy of growth through acquisitions, will create a larger company with more liquidity in its common stock and more financial flexibility, will strengthen Bellwether's management team, and will add significantly to Bellwether's production. The Company anticipates the merger will result in a cost savings of approximately $4.0 million per year. The merging of the two companies into one office location will reduce costs immediately. Key service providers, such as reserve engineers, information systems and financial outsourcers, external auditors and tax providors, attorneys and insurers, will be able to serve the larger combined company at lower cost than the two smaller companies separately. The Company's results of operations and cash flow are affected by changing oil and gas prices. Changes in oil and gas prices often result in changes in the level of drilling activity, which in turn adjusts the demand for and cost of exploration and development. Thus, increased prices may generate increased revenue without necessarily a corresponding increase in profitability while declining prices almost always have a negative impact on profitability. These industry market conditions have been far more significant determinants of Company earnings than have macroeconomic factors such as general inflation, which has had only minimal impact on Company activities in recent years. It is impossible to predict the precise effect of changing prices and inflation on future Company operations, and no assurance can be given as to the Company's future success at reducing the impact of price changes in the Company's operating results. 23 Results of Operations The table below recaps the major components of financial and operating performance to be discussed (amounts in thousands, except average prices and per BOE measures):
Year Ended December 31, --------------------------- 2000 1999 1998 -------- ------- -------- Oil and gas revenues--US......................... $107,938 $68,264 $ 73,652 Oil revenues--Ecuador............................ 4,315 -- -- Gas plant revenues............................... 6,070 3,830 3,170 Interest and other............................... 957 1,335 1,347 -------- ------- -------- Total revenue................................ 119,280 73,429 78,169 Production expenses--US.......................... 27,694 21,515 25,381 Production expenses--Ecuador..................... 2,815 17 -- Transportation costs............................. 270 316 435 Gas plant expenses............................... 2,677 2,366 1,967 Depreciation, depletion and amortization--US..... 31,909 23,863 39,688 Depreciation, depletion and amortization-- Ecuador......................................... 745 -- -- Impairment expense............................... -- -- 73,899 Disposition of hedges............................ 8,671 -- -- General and administrative expenses.............. 9,138 7,848 8,459 Interest expense................................. 15,375 11,845 11,660 Income tax benefit............................... (12,222) (3,154) (6,069) -------- ------- -------- Net income (loss)................................ $ 32,208 $ 8,813 $(77,251) ======== ======= ======== Production Oil and condensate (MBBLS)--US................. 2,206 2,080 2,297 Oil and condensate (MBBLS)--Ecuador............ 174 -- -- Natural gas (MMCF)............................. 20,478 18,965 21,302 Gas equivalent (MMCFE)......................... 34,758 31,445 35,084 Oil equivalent (MBOE).......................... 5,793 5,241 5,847 Average sales price, including the effect of hedges Oil and condensate (per BBL)--US............... $ 20.53 $ 12.84 $ 11.75 Oil and condensate (per BBL)--Ecuador.......... $ 24.80 $ -- $ -- Natural gas (per MCF).......................... $ 3.06 $ 2.19 $ 2.19 Average sales price, excluding the effect of hedges Oil and condensate (per BBL)--US............... $ 24.40 $ 14.48 $ 11.44 Oil and condensate (per BBL)--Ecuador.......... $ 24.80 $ -- $ -- Natural gas (per MCF).......................... $ 3.84 $ 2.22 $ 2.06 Average production expenses per BOE--US.......... $ 4.93 $ 4.11 $ 4.34 Average production expenses per BOE--Ecuador..... $ 16.18 (1) (1) Average general and administrative expenses per BOE............................................. $ 1.58 $ 1.50 $ 1.45 Average depletion rate per BOE--US............... $ 5.46 $ 4.32 $ 6.59 Average depletion rate per BOE--Ecuador.......... $ 4.28 (1) (1)
- -------- (1) There was no Ecuador production in 1999 and 1998. Operations of the gas plant and the gathering system are summarized as follows:
Year Ended December 31, -------------------- 2000 1999 1998 ------ ------ ------ Plant product sales volume (MBBLS)........................ 257 241 254 Average product sales price per barrel.................... $20.31 $12.93 $10.19
24 Year Ended 2000 Compared to Year Ended 1999 Net income for the year ended December 31, 2000 was $32.2 million, or $2.27 per share on a diluted basis, while net income for the year ended December 31, 1999 was $8.8 million, or $.63 per share on a diluted basis. Significant increases in oil and gas prices are primarily responsible for the improvement, but increased production has also played a role. Oil and gas revenues were $112.3 million in the year ended December 31, 2000, as compared to $68.3 million for the respective period in 1999. Oil revenues increased to $49.6 million for the year 2000 from $26.7 million for the year 1999. Domestic oil revenues benefited from the 60% increase in realized prices from $12.84 in 1999 to $20.53 in 2000. Improved domestic oil production was primarily due to new wells in the Big Island field in Southwest Louisiana and Eugene Island in the Gulf of Mexico. Sales of 174,000 barrels of Ecuadorian production, primarily from the Tiguino field, at an average price of $24.80 per barrel, accounted for the remainder of the oil revenue increase. Total oil production was 2,380,000 barrels during the year ended December 31, 2000 compared to 2,080,000 barrels for the year ended December 31, 1999. Gas revenues increased 51% from $41.6 million in 1999 to $62.7 million reported in 2000. Again, prices accounted for a large portion of the increase. Realized gas prices averaged $3.06 per mcf, or 40% higher, in the year ended December 31, 2000 as compared to $2.19 in the year ended December 31, 1999. Gas production was up 8% compared to the previous year with 20,478 MMcf and 18,965 MMcf in the years 2000 and 1999, respectively. The production increases were primarily due to continued exploration and development in the Cove field in Texas and some Gulf of Mexico fields. Additionally, the Big Island field in Southwest Louisiana, an exploratory success in 2000, also contributed gas production. The Company's Ecuador properties do not produce gas. The realized prices discussed above include the impact of oil and gas hedges. A decrease of $24.5 million related to hedge activity was reflected in oil and gas revenues for the year 2000, while a decrease in oil and gas revenues of $4.0 million was reflected for the previous year. For the year 2000, approximately 80% of domestic oil production and 73% of domestic gas production was hedged. Ecuadorian oil production was not hedged. Bellwether entered into a gas swap for $4.60 per Mcf on 15,000 Mcf per day of production from November 2000 through October 2001. This offsets the hedges previously existing on forecast production that was sold in late 2000. The non-cash loss of $8.7 million was recognized in the fourth quarter of 2000 related to the $4.60 swap. Gas plant revenues were $6.1 million in 2000, compared to $3.8 million in 1999. Contributing to this increase was a 53% increase in average realized plant liquid prices. Gas plant expense increased from $2.4 million in 1999 to $2.7 million in the year 2000, or 13%. Such increase is small when compared to the 61% increase in revenues. While Snyder Gas Plant costs for purchased natural gas increased along with commodity prices, the Diamond M plant's gas purchase costs decreased in proportion to revenues. One of the gas plant partners, which also provides significant quantities of gas to the plant, elected to take its reimbursement in-kind, receiving a share of the products. Production expenses for the year 2000 totaled $30.5 million, as compared to $21.5 million in the year 1999. On a barrel equivalency basis, production expenses were $5.27 per BOE in 2000 and $4.11 per BOE in 1999. Ecuadorian operations, which started in late 1999, account for $2.9 million, or $.49 per BOE, of this increase. Most of the Ecuadorian field expenses are non- recurring, including repair and maintenance of production facilities and replacement of downhole pumps. Production taxes are included in this production expense category and are calculated as a percentage of revenue in many areas; therefore, they have increased with the increase in realized prices, contributing $0.28 per BOE. Price inflation has impacted many items like fuel, contract labor, and specialized services. Finally, the year 2000 included a number of workovers and maintenance projects in order to boost production levels in this period of high prices. Transportation costs were not significant in either 2000 or 1999. 25 Depreciation, depletion and amortization increased 37% to $32.7 million in 2000 versus $23.9 million in 1999. Depletion of the Ecuadorian full cost pool for this year was $745,000. Improvements in domestic production in the year 2000 increased the absolute amount of depreciation, depletion and amortization, but accelerated capital expenditures caused a $.99 increase in the per BOE rate. Total Company depreciation, depletion and amortization per BOE was $5.37 and $4.32 for the years ended December 31, 2000 and 1999, respectively. General and administrative expenses totaled $9.1 million in the year ended December 31, 2000 as compared to $7.8 million in the year ended December 31, 1999. Significantly lower than normal outsourcing costs in 1999 contributed to the difference. Management fees were $2.9 million in 1999 and $4.7 million in 2000. Prior to October 1999, Bellwether was charged a management fee based upon a specified percentage of the average book value of the Company's total assets, excluding cash, plus a percentage of operating cash flows. Due to the $73.9 million impairment charge in December 1998, the Company's total assets and resulting percentage of such assets was reduced. In October 1999, the Company became party to a new MSA and six specific contracts, which covered comparable outsourcing services to those contained in the 1999 contract. The new contracts have varying terms and fees, but under the contracts overall management fees have increased to levels similar to 1998 management fee levels. Other significant items in general and administrative expenses include a $1.7 million charge in 1999 due to a change in management and a $849,000 non- cash charge in 2000 required due to the difference between exercise and grant date prices on options awarded to the Company president. Interest expense increased 30% to $15.4 million for the year ended December 31, 2000 from $11.8 million in the year ended December 31, 1999. Increased interest rates and higher borrowings outstanding during the period resulted in the increase. Although outstanding debt of $125.5 million at December 31, 2000 is lower than the $130.0 million outstanding at December 31, 1999, most of the $30.0 million credit facility borrowings in 1999 were incurred in the latter half of the year, whereas borrowings during 2000 reached maximums of $40.9 million. Additional expenses of $705,000 incurred in conjunction with the credit facility amendments were also charged to interest expense in 2000. At December 31, 1999, the Company had a tax valuation allowance of $19.8 million against its deferred tax assets. A portion of the valuation allowance was recognized in 1999. As of March 31, 2000, the Company determined that it was more likely than not that the deferred assets would be realized, based upon current projections of taxable income due to higher commodity prices, and the valuation allowance was removed. At December 31, 2000, the Company believes it is more likely than not that the entire deferred asset will be realized. Year Ended 1999 Compared to Year Ended 1998 Net income for the year ended December 31, 1999 was $8.8 million, or $0.63 per share on a diluted basis, while the year ended December 31, 1998 resulted in a loss of $77.3 million, or $5.50 per share on a diluted basis. The loss in 1998 was due to a $73.9 million impairment charge resulting from the Company's capitalized cost exceeding the discounted future net revenues on an after-tax basis of estimated proved oil and gas reserves. Oil and gas revenues were $68.3 million for the year ended 1999, as compared to $73.7 million of oil and gas revenues for the year ended 1998. While oil and gas volumes were down approximately 9% in 1999 compared to 1998, oil prices were 10% higher in 1999. Oil prices increased from $11.75 per barrel in 1998 to $12.84 in 1999. While gas prices were weak in the first few months in 1999, gas prices recovered in the fourth quarter of 1999. As a result of natural gas and crude oil hedging activities, oil and gas revenues were reduced by $4 million in 1999 and were increased by $3.6 million in 1998. The production declines were attributable to normal declines in the Company's Gulf of Mexico properties. This decline was somewhat halted by the acquisition of additional Gulf of Mexico properties in July and the November acquisition of Southeast New Mexico properties. 26 Gas plant revenues were $3.8 million in the year ended December 31, 1999, an increase of 19% from $3.2 million of gas plant revenues reflected in the year ended December 31, 1998. The increase is due to a 27% increase in plant liquid prices. Gas plant expenses were $2.4 million in the year ended December 31, 1999 as compared to $2.0 million during the year ended December 31, 1998. The increase in expenses is attributable to periodic plant maintenance. Production expenses for fiscal 1999 totaled $21.5 million, as compared to $25.4 million in fiscal 1998. On an BOE basis, production expenses were $4.11 per BOE in 1999 as compared to $4.34 per BOE in 1998. The primary reason for the decreased costs was the sale of $2.9 million of non-core assets. These assets had minimal production expenses, but high lease operating and workover expenses. Transportation costs were not significant in 1999 or 1998. Depreciation, depletion and amortization decreased 40% to $23.9 million in 1999 versus $39.7 million in 1998. Such decrease was attributable to the lower book basis due to the 1998 impairment. To the extent that capitalized costs (net of depreciation, depletion and amortization) exceed the discounted future net revenues on an after-tax basis of estimated proved oil and gas reserves, such excess costs are charged to operations as an impairment. Sharp declines in oil and gas prices, including further gas price declines subsequent to year end, and to a lesser extent, downward revision in estimated proved reserves resulted in a $73.9 million pretax impairment charge ($71.6 million after tax), in the fiscal year ended December 31, 1998. February 23, 1999 prices used in computing the impairment were based on a NYMEX oil price of $12.48 per barrel and a NYMEX gas price of $1.71 per MMBTU, adjusted to the wellhead. General and administrative expenses decreased in 1999 to $7.8 million from $8.5 million in 1998. A decrease in outsourcing costs from $4.0 million to $2.9 million was the major contribution to this decline. Until October 1999, the Company was charged an outsourcing fee, which was based upon a specified percentage of the average book value of the Company's total assets, excluding cash, plus a percentage of operating cashflows. Due to the $73.9 million impairment charge mentioned above, the Company's total assets and resulting percentage of such assets was reduced. Additionally, the 1998 period included costs related to the closing of the Company's Dallas exploration office in March 1998 and certain transition costs related to the change of the Company's 1997 fiscal year. Partially offsetting such decreases was $1.7 million in severance costs incurred in the third quarter of 1999 due to the Company's recent management change. General and administrative expenses on a barrel of oil equivalent basis increased from $1.45 per equivalent BOE in 1998 to $1.50 per equivalent BOE in 1999. A refund on 1998 taxes was received in 1999. The refund resulted from higher than anticipated dry hole and expired lease charges in 1998. For the year ended December 31, 1999, due to increased future net reserves, the Company recognized a portion of the deferred tax asset previously offset by a valuation allowance. Interest expense increased to $11.8 million for the year ended December 31, 1999 from $11.7 million in the year ended December 31, 1998. Other Matters Dividends At present, there is no plan to pay dividends on the common stock. Certain restrictions contained in the Company's outstanding Notes and Senior Credit Facility limit the amount of dividends which may be declared. The Company maintains a policy, which is subject to review from time to time by the Board of Directors, of reinvesting its discretionary cash flows for the continued growth of the Company. Gas Balancing Positions It is customary in the industry for various working interest partners to sell more or less than their entitled share of natural gas production. The Company uses the sales method of accounting for gas imbalances. Under 27 this method, gas sales are recorded when revenue checks are received or are receivable on the accrual basis. The settlement or disposition of gas balancing positions as of December 31, 2000 is not anticipated to adversely impact the financial condition of the Company. Derivative Financial Instruments The Company periodically uses derivative financial instruments to manage oil and gas price risk and interest rate risk. For purposes of its hedging activities, the Company divides product price risks into two categories, fluctuations in the price of oil and gas on the NYMEX and fluctuations in the difference between NYMEX prices and the price actually received by the Company for its production (referred to as "basis differential"). From time to time the Company enters into swap transactions in which the Company agrees to pay a fixed price and the counter party to the swap agrees to pay a NYMEX based price. Effective September 22, 1998, the Company entered into an eight and a half- year interest rate swap agreement with a notational value of $80 million. Under the agreement, the Company receives a fixed interest rate and pays a floating interest rate based on the simple average of three foreign LIBOR rates. Floating rates are redetermined for a six-month period each April 1 and October 1. Through April 2002 the floating rate is capped at 10.875% and capped at 12.375% thereafter. The floating rate for the period from October 1, 2000 to April 1, 2001 is 10.875%, which is the cap. If rates were to drop below the cap by 10%, Bellwether's interest costs in the next period would decrease about $44,000. New Accounting Pronouncements In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement establishes standards of accounting for and disclosures of derivative instruments and hedging activities. As amended, this statement is effective for fiscal quarters beginning after January 1, 2001. The Company has reviewed its operations for and documented all hedge transactions in accordance with this pronouncement. All of Bellwether's commodity derivative instruments, with the exception of those causing the $8.7 million loss recognized in the fourth quarter of 2000, qualify for treatment as hedges. Beginning January 1, 2001, Bellwether will record the fair value of commodity hedges as current assets or liabilities, with the offsetting amount of $33.1 million in Other Comprehensive Income. Earnings will only be impacted as hedge transactions are satisfied or to the extent that a hedge proves to be ineffective. The Company's interest rate swap, however, will not be designated for hedge accounting under the new pronouncement. At January 1, 2001, a long-term liability will be recorded for $4.4 million, the fair value of the swap, with a corresponding charge to income due to this change in accounting principle. Quarterly adjustments will be made in order to reflect changes in the fair value of the swap. 28 Item 7a. Quantitative and Qualitative Disclosures About Market Risk The Company is exposed to market risk, including adverse changes in commodity prices and interest rate. Commodity Price Risk--The Company produces and sells crude oil, natural gas and natural gas liquids. As a result, the Company's operating results can be significantly affected by fluctuations in commodity prices caused by changing market forces. The Company periodically seeks to reduce its exposure to price volatility by hedging its productions through swaps, options and other commodity derivative instruments. The Company uses hedge accounting for these instruments, and settlements of gains or losses on these contracts are reported as a component of oil and gas revenues and operating cash flows in the period realized. These agreements expose the Company to counterparty credit risk to the extent that the counterparty is unable to meet its settlement commitments to the Company. Bellwether entered into a gas swap for $4.60 per mcf on 15,000 mcf per day of production from November 2000 through October 2001. This offsets hedges previously existing on forecast production that was sold in late 2000. A non- cash loss of $8.7 million was recognized in the fourth quarter 2000 related to the $4.60 swap, along with a related current liability. The liability will be relieved monthly as the swap is settled. By December 31, 2000, the liability had been reduced to $7.5 million. The following tables detail the Company's hedges of future production which were in place at December 31, 2000. The oil hedge was transacted in August 2000. All gas hedges were entered into before March 2000. Oil Hedges
NYMEX NYMEX BBLS Total Price Price Period Per Day BBLS Type Floor Ceiling ------ ------- ------- ------ ------ ------- Jan. 2001-Dec. 2001................. 1,500 547,500 Collar $24.00 $30.00
Gas Hedges
NYMEX NYMEX MCF Price Price Period Per Day Total MCF Type Floor Ceiling ------ ------- --------- ------ ----- ------- Jan. 2001-March 2001............... 25,000 2,250,000 Collar $2.30 $3.37 April 2001-Oct. 2001............... 35,000 7,490,000 Collar $2.30 $2.92
The fair value at December 31, 2000 of these swap agreements was a loss of $33.1 million. A 10% increase or decrease in oil and gas prices would have a $6 million impact in the fair value. These energy swap agreements expose the Company to counterparty credit risk to the extent the counterparty is unable to meet its monthly settlement commitment to the Company. Interest Rate Risk--The Company may enter into financial instruments such as interest rate swaps to manage the impact of changes in interest rates. Effective September 22, 1998, the Company entered into an eight and a half year interest rate swap agreement with a notional value of $80 million. Under the agreement, the Company receives a fixed interest rate and pays a floating interest rate, subject to a cap, based on the simple average of three foreign LIBOR rates. Floating rates are redetermined for a six month period each April 1 and October 1. This agreement is not held for trading purposes. The swap provider is a major financial institution, and the Company does not anticipate non-performance by the provider. The Company's exposure to changes in interest rates primarily results from short term changes in the LIBOR rates. A 10% decrease in the floating LIBOR rates would have the effect of decreasing interest costs to the Company by $872,500 per year. A 10% increase in the floating LIBOR rates would have no impact since any increase at this time is capped at 10.875%. 29 Item 8. Financial Statements and Supplementary Data INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page Number ------ Independent Auditors' Report............................................ 31 Financial Statements: Consolidated Balance Sheets as of December 31, 2000 and 1999............ 32 Consolidated Statements of Operations for the Years Ended December 31, 2000, 1999 and 1998.................................................. 34 Consolidated Statements of Changes in Stockholders' Equity for the Years Ended December 31, 2000, 1999 and 1998......................... 35 Consolidated Statements of Cash Flows for the Years Ended December 31, 2000, 1999 and 1998.................................................. 36 Notes to Consolidated Financial Statements............................ 37
30 INDEPENDENT AUDITORS' REPORT The Board of Directors and Stockholders of Bellwether Exploration Company and Subsidiaries: We have audited the accompanying consolidated balance sheets of Bellwether Exploration Company and subsidiaries as of December 31, 2000 and 1999 and the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the years in the three-year period ended December 31, 2000. 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 auditing standards generally accepted in the United States of America. 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 present fairly, in all material respects, the financial position of Bellwether Exploration Company and subsidiaries as of December 31, 2000 and 1999 and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. KPMG LLP Houston, Texas March 9, 2001 31 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, December 31, 2000 1999 ASSETS ------------ ------------ (Amounts in thousands) CURRENT ASSETS: Cash and cash equivalents.......................... $ 14,464 $ 6,101 Accounts receivable and accrued revenues........... 27,724 14,354 Notes receivable-affiliate......................... 1,281 -- Prepaid expenses and other......................... 1,189 1,562 --------- --------- Total current assets............................. 44,658 22,017 --------- --------- PROPERTY, PLANT AND EQUIPMENT, at cost: Oil and gas properties (full cost) United States--Unproved properties of $11,360 and $16,325 excluded from amortization as of December 31, 2000 and 1999, respectively................... 421,408 344,778 Ecuador--Unproved properties of $0 and $404 excluded from amortization as of December 31, 2000 and 1999, respectively............................ 12,988 1,246 Gas plant facilities................................. 18,452 17,775 --------- --------- 452,848 363,799 Accumulated depreciation, depletion and amortization--oil and gas........................... (296,567) (221,092) Accumulated depreciation, depletion and amortization--gas plant............................. (7,345) (6,134) --------- --------- Net property, plant and equipment.................... 148,936 136,573 Leasehold, furniture and equipment................... 2,782 438 Accumulated depreciation............................. (404) (74) --------- --------- 2,378 364 --------- --------- INVESTMENT IN OUTSIDE COMPANY........................ 4,554 4,554 DEFERRED INCOME TAXES................................ 15,141 2,739 OTHER ASSETS......................................... 5,878 5,514 --------- --------- $ 221,545 $ 171,761 ========= =========
See Notes to Consolidated Financial Statements. 32 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
December 31, December 31, 2000 1999 LIABILITIES AND STOCKHOLDERS' EQUITY ------------ ------------ (Amounts in thousands, except share information) CURRENT LIABILITIES: Accounts payable and accrued liabilities........... $ 29,960 $ 18,247 Commodity derivative liabilities................... 7,486 -- -------- -------- Total current liabilities........................ 37,446 18,247 -------- -------- LONG-TERM DEBT....................................... 125,450 130,000 OTHER LIABILITIES.................................... 1,689 200 STOCKHOLDERS' EQUITY: Preferred stock, $0.01 par value, 1,000,000 shares authorized; none issued or outstanding at December 31, 2000 and 1999................................. -- -- Common stock, $0.01 par value, 30,000,000 shares authorized, 14,259,626 and 14,168,791 shares issued at December 31, 2000 and December 31, 1999, respectively...................................... 143 142 Additional paid-in capital......................... 81,892 80,455 Retained deficit................................... (23,170) (55,378) Treasury stock, at cost, 311,000 shares............ (1,905) (1,905) -------- -------- Total stockholders' equity....................... 56,960 23,314 -------- -------- $221,545 $171,761 ======== ========
See Notes to Consolidated Financial Statements. 33 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2000 1999 1998 --------------- --------------- --------------- (Amounts in thousands, except per share data) REVENUES: Gas revenues.......... $ 62,652 $ 41,559 $ 46,661 Oil revenues--United States............... 45,286 26,705 26,991 Oil revenues-- Ecuador.............. 4,315 -- -- Gas plant revenues.... 6,070 3,830 3,170 Interest and other income............... 957 1,335 1,347 --------------- -------------- --------------- 119,280 73,429 78,169 --------------- -------------- --------------- COSTS AND EXPENSES: Production expenses-- United States........ 27,694 21,515 25,381 Production expenses-- Ecuador.............. 2,815 17 -- Transportation costs.. 270 316 435 Gas plant expenses.... 2,677 2,366 1,967 Depreciation, depletion and amortization--United States............... 31,909 23,863 39,688 Depreciation, depletion and amortization-- Ecuador.............. 745 -- -- Impairment expense.... -- -- 73,899 Disposition of hedges............... 8,671 -- -- General and administrative expenses............. 9,138 7,848 8,459 Interest expense...... 15,375 11,845 11,660 --------------- -------------- --------------- 99,294 67,770 161,489 --------------- -------------- --------------- Income (loss) before income tax benefit..... 19,986 5,659 (83,320) Provision for income tax benefit................ (12,222) (3,154) (6,069) --------------- -------------- --------------- Net income (loss)....... $ 32,208 $ 8,813 $ (77,251) =============== ============== =============== Net income (loss) per share.................. $ 2.32 $ .64 $ (5.50) =============== ============== =============== Net income (loss) per share--diluted......... $ 2.27 $ .63 $ (5.50) =============== ============== =============== Weighted average common shares outstanding............ 13,899 13,854 14,039 =============== ============== =============== Weighted average common shares outstanding--diluted... 14,175 13,896 14,039 =============== ============== ===============
See Notes to Consolidated Financial Statements. 34 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Preferred Common Stock Stock Additional Retained Treasury Stock ------------- ------------- Paid-In Earnings -------------- Shares Amount Shares Amount Capital (Deficit) Shares Amount Total ------ ------ ------ ------ ---------- --------- ------ ------- -------- (Amounts in thousands) Balance December 31, 1997................... 13,892 $139 -- $-- $78,470 $ 13,060 -- $ -- $ 91,669 ====== ==== === === ======= ======== ==== ======= ======== Stock options exercised and related tax effects................ 273 3 -- -- 1,972 -- -- -- 1,975 Treasury shares purchased.............. -- -- -- -- -- -- (311) (1,904) (1,904) Net loss................ -- -- -- -- -- (77,251) -- -- (77,251) ------ ---- --- --- ------- -------- ---- ------- -------- Balance December 31, 1998................... 14,165 $142 -- $-- $80,442 $(64,191) (311) $(1,904) $ 14,489 ====== ==== === === ======= ======== ==== ======= ======== Stock options Exercised and related tax effects................ 4 -- -- -- 13 -- -- -- 13 Treasury shares purchased.............. -- -- -- -- -- -- -- (1) (1) Net income.............. -- -- -- -- -- 8,813 -- -- 8,813 ------ ---- --- --- ------- -------- ---- ------- -------- Balance December 31, 1999................... 14,169 $142 -- $-- $80,455 $(55,378) (311) $(1,905) $ 23,314 ====== ==== === === ======= ======== ==== ======= ======== Stock options Exercised and related tax effects ....................... 91 1 -- -- 588 -- -- -- 589 Compensation expense.... -- -- -- -- 849 -- -- -- 849 Treasury shares purchased.............. -- -- -- -- -- -- -- -- -- Net income.............. -- -- -- -- -- 32,208 -- -- 32,208 ------ ---- --- --- ------- -------- ---- ------- -------- Balance December 31, 2000................... 14,260 $143 -- $-- $81,892 $(23,170) (311) $(1,905) $ 56,960 ====== ==== === === ======= ======== ==== ======= ========
See Notes to Consolidated Financial Statements. 35 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2000 1999 1998 ------------ ------------ ------------ (Amounts in thousands) CASH FLOWS FROM OPERATING ACTIVITIES: Net income (loss)...................... $ 32,208 $ 8,813 $(77,251) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depreciation, depletion and amortization........................ 33,213 24,694 40,544 Stock option expense amortization.... 849 -- -- Disposition of hedges................ 8,671 -- -- Impairment expense................... -- -- 73,899 Deferred taxes....................... (12,307) (2,739) (6,820) -------- -------- -------- 62,634 30,768 30,372 Changes in assets and liabilities, net of acquisition effects: Accounts receivable and accrued revenues............................ (13,370) 2,101 2,691 Prepaid expenses and other........... 373 157 1,521 Accounts payable and accrued liabilities......................... 12,217 6,265 (2,220) Due (to) from affiliates............. -- (125) 3,245 Other................................ (215) (411) (887) -------- -------- -------- NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES............................ 61,639 38,755 34,722 -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Acquisitions of oil and gas properties.......................... (7,078) (25,889) (9,596) Investment in outside companies...... -- (4,426) (128) Note receivable...................... (1,281) -- -- Additions to oil and gas properties.. (81,294) (30,904) (30,583) Proceeds from sales of properties.... 45,906 5,139 421 Abandonment costs.................... (1,531) (136) (757) Additions to leasehold, furniture and equipment........................... (2,462) (448) (55) Additions to gas plant facilities.... (677) (369) (689) Other................................ (446) (1,071) (88) -------- -------- -------- NET CASH FLOWS USED IN INVESTING ACTIVITIES............................ (48,863) (58,104) (41,475) ======== ======== ======== CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowings............. 31,400 42,000 4,900 Net proceeds from issuance of common stock............................... 496 13 1,649 Payments of long-term debt........... (35,950) (16,400) (500) Credit facility costs................ (359) (172) (81) Purchase of treasury shares.......... -- (1) (1,904) -------- -------- -------- NET CASH FLOWS (USED IN) PROVIDED BY FINANCING ACTIVITIES.................. (4,413) 25,440 4,064 -------- -------- -------- Net increase (decrease) in cash and cash equivalents...................... 8,363 6,091 (2,689) Cash and cash equivalents at beginning of period............................. 6,101 10 2,699 -------- -------- -------- Cash and cash equivalents at end of period................................ $ 14,464 $ 6,101 $ 10 ======== ======== ========
See Notes to Consolidated Financial Statements. 36 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Organization Bellwether Exploration Company ("the Company") is an independent energy company primarily engaged in the acquisition, exploitation and development of and exploration for oil and gas properties. The Company is a Delaware corporation. Since April 1997, the Company has employed a balanced growth strategy combining strategic acquisitions of producing properties with technology driven development and exploration drilling. As a result, the Company's results of operations have been significantly affected by its success in acquiring oil and gas properties and its ability to maintain or increase production through its development activities. On January 25, 2001, Bellwether announced plans to merge with Bargo Energy Company. Contemporaneously with the merger, Bellwether proposes to increase its authorized common stock to 65.0 million shares and amend its 1996 Stock Incentive Plan to increase the number of shares reserved for issuance under the plan by 2.5 million shares. Under the merger agreement, Bargo shareholders will receive a combination of cash and Bellwether common stock. The merger is conditioned upon its receiving the approval of Bellwether's shareholders and Bargo's shareholders. The merger will be accounted for using the purchase method of accounting. Bellwether's management believes the merger is, among other things, in accordance with Bellwether's long-term strategy of growth through acquisitions, will create a larger company with more liquidity in its common stock and more financial flexibility, will strengthen Bellwether's management team, and will add significantly to Bellwether's production. 2. Summary of Significant Accounting Policies Principles of Consolidation The consolidated financial statements include the accounts of Bellwether Exploration Company and its wholly-owned subsidiaries. Snyder Gas Plant Venture and NGL/Torch Gas Plant Venture and their 11.9% and 32.0% investments in the Snyder and Diamond M-Sharon Ridge Gas Plants have been pro rata consolidated through September 1999 at which time the joint ventures were dissolved. The Company's investment in Carpatsky is reflected using the cost method. Oil and Gas Properties The Company utilizes the full cost method to account for its investment in oil and gas properties. Under this method, all costs of acquisition, exploration and development of oil and gas reserves (including such costs as leasehold acquisition costs, geological expenditures, dry hole costs and tangible and intangible development costs and direct internal costs) are capitalized as incurred. Direct internal costs capitalized are primarily the salary and benefits of geologists and engineers directly involved in acquisition, exploration and development activities and amounted to $3.3 million, $1.7 million and $0.8 million in the years ended December 31, 2000, 1999 and 1998, respectively. The Company currently has two full cost pools: United States and Ecuador. The cost of oil and gas properties, the estimated future expenditures to develop proved reserves, and estimated future abandonment, site remediation and dismantlement costs are depleted and charged to operations using the unit-of-production method based on the ratio of current production to proved oil and gas reserves as estimated by independent engineering consultants. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization computation until it is determined whether or not proved reserves can be assigned to the properties or whether impairment has occurred. Depletion expense per equivalent barrel of domestic production was approximately $5.46 in 2000, $4.32 in 1999, and $6.59 in 1998. Depletion expense per equivalent barrel of Ecuador production was $4.28 in 2000. 37 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Nothing was excluded from amortization in the Company's Ecuador full cost pool as of December 31, 2000. The following table shows, by category of cost and date incurred, the domestic unproved property costs excluded from amortization (amounts in thousands):
Total at Leasehold Exploration Development December 31, Costs Costs Costs 2000 --------- ----------- ----------- ------------ Costs Incurred During Periods Ended: December 31, 2000............ $ 948 $532 $-- $ 1,480 December 31, 1999............ 8,591 -- -- 8,591 December 31, 1998............ 1,289 -- -- 1,289 Prior........................ -- -- -- -- ------- ---- --- ------- $10,828 $532 $-- $11,360 ======= ==== === =======
Land and seismic costs have been incurred in the current and prior years by the Company and are still in the evaluation stage. Approximately $2.8 million and $1.2 million was evaluated and moved to the full cost pool in 2000 and 1999, respectively. Such costs fall into four broad categories: 1) Material projects which are in the last one to two years of seismic evaluation; 2) Material projects currently being marketed to third parties; 3) Leasehold and seismic costs for projects not yet evaluated at all; and 4) Drilling and completion costs for projects in progress at year end which have not resulted in the recognition of reserves at December 2000. This category of costs will transfer into the full cost pool in 2001. Dispositions of oil and gas properties are recorded as adjustments to capitalized costs, with no gain or loss recognized unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas. To the extent that capitalized costs of oil and gas properties, net of accumulated depreciation, depletion and amortization, exceed the discounted future net revenues of proved oil and gas reserves net of deferred taxes, such excess capitalized costs would be charged to operations. Oil and gas prices declined in 1998, with continued declines in early 1999. As a result of such declines, the Company's capitalized costs were in excess of future net revenues calculated using prices in effect in late February 1999. The Company recorded an oil and gas property impairment of $73.9 million in 1998. No such impairment in book value was required at December 2000 or 1999. Any reference to oil and gas reserve information in the Notes to Consolidated Financial Statements is unaudited. Gas Plants and Gas Gathering System Gas plant facilities include the costs to acquire certain gas plants and to secure rights-of-way. Capitalized costs associated with gas plants facilities are amortized primarily over the estimated useful lives of the various components of the facilities utilizing the straight-line method. The estimated useful lives of such assets range from four to fifteen years. Effective September 1, 1999, NGL Associates , the Company's partner in the Torch-NGL Joint Venture and the Snyder Gas Plant Joint Venture (the "Ventures"), was given 16.5% of the Ventures' interests in order to 38 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) satisfy requirements of the joint ventures. The result of this transfer of interests was the dissolution of the joint ventures. Bellwether's interest in the gas plants was reduced to 11.9% and 32.0% in the Snyder and Diamond M- Sharon Ridge Gas Plants, respectively. The Company sold its gas gathering subsidiary for $40,000 on March 1, 1999. Revenue Recognition and Gas Imbalances The Company uses the sales method of accounting for revenue. Under this method, oil and gas revenues are recorded when revenue checks are received or are receivable on the accrual basis. Sales to Torch Co-Energy LLC accounted for greater than 10% of oil and gas revenues in 2000, 1999, and 1998. The sales amounts were $27.9 million, $14.4 million, and $13.6 million, respectively, and were part of domestic revenues. Sales to Valero Industrial Gas, L.P. of $7.0 million accounted for greater than 10% of the domestic revenues in 1997. Gas imbalances are created, but not recorded, when the sales amount is not equal to the Company's entitled share of production. The Company had a net imbalance liability, at fair value, determined by applying average realized prices for the year to the imbalance volumes of $2.3 million, $1.2 million and $.5 million, at December 31, 2000, 1999 and 1998, respectively. A certain portion of the gas balancing liability is related to properties approaching depletion; therefore, cash settlement may be likely. The Company is taking steps to extend the productive life of such reserves. Natural Gas and Crude Oil Hedging Commodity derivatives utilized as hedges include collar and swap contracts. In order to qualify as a hedge, price movements in the underlying commodity derivative must be sufficiently correlated with the hedged commodity. When a commodity derivative ceases to qualify as a hedge, the change in its fair value is recognized in income currently. Settlement of gains and losses on price swap contracts are realized monthly, generally based upon the difference between the contract price and the average closing New York Mercantile Exchange ("NYMEX") price and are reported as a component of oil and gas revenues and operating cash flows in the period realized. Gains and losses attributable to the termination of a swap contract are deferred on the balance sheet and recognized in revenue when the hedged crude oil and natural gas is sold. There were no such deferred gains or losses at December 31, 2000, 1999 or 1998. Oil and gas revenues were decreased by $24.5 million and $4.0 million in the years ended December 31, 2000 and 1999, respectively, and increased by $3.6 million in the year ended December 31, 1998, as a result of such hedging activity. In the fourth quarter of the year 2000, the Company recognized a non-cash loss of $8.7 million related to a $4.60 per Mcf gas swap on 15,000 Mcf per day over the period November 2000 through October 2001 and previously existing swaps intended to hedge forecasted production. The swap was intended to limit future losses by offsetting the previously existing hedges on forecasted production from properties sold by the Company in late 2000. Income Taxes Deferred taxes are accounted for under the asset and liability method of accounting for income taxes. Under this method, deferred income taxes are recognized for the tax consequences of "temporary differences" by applying enacted statutory tax rates applicable to future years to differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities. The effect on deferred taxes of a change in tax rates is recognized in income in the period the change occurs. 39 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Statements of Cash Flows For cash flow presentation purposes, the Company considers all highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents. Interest paid in cash for the years ended December 31, 2000, 1999 and 1998, was $13.8 million, $11.1 million, and $11.1 million, respectively. Income tax refunds received in cash for December 31, 1999 were $437,000. Income taxes paid in cash for the years ended December 31, 2000 and 1998 were $108,831 and $1,408,000, respectively. Certain non-cash transactions were recorded in 2000: 1) A $849,000 non-cash general and administrative charge in 2000 was required due to the difference between exercise and grant date prices on options awarded to the Company president, and 2) A non-cash loss of $8.7 million at December 31, 2000 related to a $4.60 gas swap not treated as a hedge. Benefit Plans During 1993, the Company adopted the Bellwether Corporation Simplified Employee Pension Plan (the "Savings Plan") whereby all employees of the Company are eligible to participate. The Savings Plan is administered by a Plan Administrator appointed by the Company. Eligible employees may contribute a portion of their annual compensation up to the legal maximum established by the Internal Revenue Service for each plan year. The Company's matching contributions are a maximum of 6% each plan year. Employee contributions are immediately vested and employer contributions have a five year vesting period. Amounts contributed by the Company to the Savings Plan for the years ended December 31, 2000, 1999 and 1998 were $312,185, $191,176, and $123,952, respectively. Deferred Compensation Plan In late 1997, the Company adopted the Bellwether Deferred Compensation Plan. This plan, which is not required to be funded, allows selected employees the option to defer a portion of their compensation until their retirement. Such deferred compensation is invested in any one or more of six mutual funds managed by American Funds Service Company ("Fund Manager"), at the direction of the employees. The Company designated Southwest Guaranty Trust Company as Trustee to supervise the Fund Manager. The market value of these investments is included in Current Assets at December 31, 2000, 1999 and 1998 and was approximately $25,000, $98,000 and $49,000, respectively. New Accounting Pronouncements In June 1998, the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This statement establishes standards of accounting for and disclosures of derivative instruments and hedging activities. As amended, this statement is effective for fiscal quarters beginning after January 1, 2001. The Company has reviewed its operations for and documented all hedge transactions in accordance with this pronouncement. All of Bellwether's commodity derivative instruments, with the exception of those causing the $8.7 million loss recognized in the fourth quarter of 2000, qualify for treatment as hedges. Beginning January 1, 2001, Bellwether will record the fair value of commodity hedges as current assets or liabilities, with the offsetting amount of $33.1 million in Other Comprehensive Income. Earnings will be impacted as hedge transactions are satisfied or to the extent that a hedge proves to be ineffective. The Company's interest rate swap, however, will not be designated for hedge accounting under the new pronouncement. At January 1, 2001, a long-term liability will be recorded for $4.4 million, the fair value of the swap, with a corresponding charge to income due to this change in accounting principle. Quarterly adjustments will be made in order to reflect changes in the fair value of the swap or collars. 40 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Use of Estimates Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as well as reserve information which affects the depletion calculation and the computation of the full cost ceiling limitation to prepare these financial statements in conformity with generally accepted accounting principles in the United States. Actual results could differ from these estimates. Reclassifications Certain reclassifications of prior period statements have been made to conform to current reporting practices. 3. Acquisitions and Investments During the last three fiscal years, the Company has completed or made the following acquisitions and investments: During 1998, in connection with a possible transaction by the Company with Carpatsky Petroleum Company ("Carpatsky"), the Company agreed to guarantee $500,000 of indebtedness of Carpatsky to Torch. The Carpatsky note to Torch went into default in June 1998. Under an agreement effective October 31, 1999, Bellwether paid Torch $565,700 for the guaranty. The Company received in exchange 4.5 million shares of Carpatsky and a warrant to acquire an additional 967,296 common shares. On December 30, 1999, Bellwether purchased 95.5 million preferred shares of Carpatsky Petroleum, Inc. and warrants to acquire 12.5 million common shares for $4 million. The preferred shares are convertible into 50 million Carpatsky common shares. This investment does not give the Company the ability to significantly influence Carpatsky's operations. In December 1998, Bellwether was the successful bidder for the Charapa field in Ecuador. With the successful bid, the Company was awarded a contract for production and exploration of crude oil in the Charapa field. The contract provides the Company with approximately 45% of the crude oil produced above the base production curve. The base production curve is defined as the production profile of the crude oil projected by the Ecuadorian government hydrocarbons subsidiary. Bellwether is also entitled to recoup lease operating expenses associated with the base production. Negotiations with the Ecuadorian government took place throughout 1999 with Bellwether officially taking over operations of the field in January of 2000. Bellwether committed to a $12 million work program over three years. In February 2000, Bellwether took over operations of another Ecuadorian field, the Tiguino field. The contract with the government is similar for both fields. A Bellwether subsidiary operated the field on behalf of Petroleos Colombianos ("Petrocol"), which had been granted a 25% interest and operatorship by the Ecuadorian government. Bellwether negotiated with Petrocol and other interest owners throughout 2000 ultimately acquiring 70% and the assignment of operatorship by July 2000. Agreements transferring ownership and operatorship in the Tiguino field have been signed by all parties, but the final government approval of the transaction has not yet been obtained. Such approval is necessary for the agreements to be accepted in Ecuador. Bellwether has received a legal opinion letter that it is legally entitled to the 70% of production from the field and has also received confirmation that the government has never failed to approve similar assignments. 4. Related Party Transactions The Company is a party to a master services agreement and six specific outsourcing contracts which require Torch to administer certain business activities of the Company. The various contracts have terms from two years to five years in length and annual fees ranging from fixed and variable amounts of $0.6 million to $3.0 million plus fees based upon percentages of production ranging from 1/2% to 2% depending on the product. Prior to 41 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) October 1999, the Company was party to an administrative services agreement which required Torch to administer certain activities of the Company for monthly fees equal to the sum of one-twelfth of 2% of the average of the book value of the Company's total assets, excluding cash, plus 2% of annual operating cash flows (as defined) during the period in which the services are rendered plus reimbursement of certain costs incurred on behalf of the Company. For the periods ended December 31, 2000, 1999, and 1998 related fees paid to Torch amounted to $4.7 million, $2.9 million and $4.0 million, respectively. In July 2000, Pan American Energy Finance, a wholly-owned subsidiary of Bellwether entered into a $1 million revolving credit facility with Carpatsky. The facility earns interest at 10% per annum and is due on November 30, 2001. As of December 31, 2000 the full $1 million had been borrowed. On August 2, 1999, two senior executives left the Company to pursue other opportunities. Mr. J. P. Bryan, a member of the board of directors, then was elected Chairman and CEO effective August 2, 1999. Mr. Bryan is Senior Managing Director of and a holder of common stock of the parent corporation of Torch. Approximately $1.7 million of severance cost attributable to this management change were incurred in August 1999. Mr. Bryan resigned his position as CEO of Bellwether in May 2000 and his position as Chairman in December 2000, but remains on the Board of Directors. In April, 1997, Torch was issued 150,000 shares of the Company's common stock and a warrant, expiring in April 2002, to purchase 100,000 shares at $9.90 per share for advisory services rendered in connection with an acquisition. Pursuant to a Separation Agreement between the Company and one of the senior executives, the executive entered into a nonrecourse promissory note with a principal amount of $332,872. The loan bears interest at an annual rate of seven percent and is due and payable on August 23 2002. The loan is secured by 78,323 shares of the Company's Common Stock. As of December 31, 2000, the outstanding loan balance of $332,872 was reflected in Other Assets on the Balance Sheet, while accrued interest of $8,414 was reflected within Accounts Receivable and Accrued Revenues on the Balance Sheet. Sales to Torch-Co Energy LLC accounted for approximately 24%, 22% and 28% of fiscal year 2000, 1999 and 1998 oil and gas revenues, respectively. A subsidiary of Torch markets oil and natural gas production from certain oil and gas properties in which the Company owns an interest. The Company generally pays fees of 1/2% to 2% of revenues for such marketing services. Such charges were $563,369, $947,500 and $1,143,000, in periods ended December 31, 2000, 1999 and 1998, respectively. Prior to the contract revisions the fees were 2% on all marketed production; therefore a savings is reflected in the year 2000 over previous years. Costs of the evaluation of potential property acquisitions and due diligence conducted in conjunction with acquisitions closed are incurred by Torch at the Company's request. The Company was charged $1.3 million, $357,800, and $379,000 for these costs in periods ended December 31, 2000, 1999 and 1998, respectively. Torch operates certain oil and gas interests owned by the Company. The Company is charged, on the same basis as other third parties, for all customary expenses and cost reimbursements associated with these activities. Prior to October 1999, Torch retained such reimbursements as part of its compensation. After October 1999, overhead reimbursements are retained by Bellwether and are reported as reductions to general and administrative expenses. Operator's overhead charged by Torch and retained as compensation for these activities for the periods ended December 31, 1999 and 1998 was $1,153,000 and $1,349,000, respectively. Torch is the operator of the Snyder Gas Plant. In periods ended December 31, 2000, 1999 and 1998, the fees paid by the Company to Torch were $96,339, $73,000 and $72,000, respectively. 42 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 5. Stockholders' Equity Common and Preferred Stock The Certificate of Incorporation of the Company authorizes the issuance of up to 30,000,000 shares of common stock and 1,000,000 shares of preferred stock, the terms, preferences, rights and restrictions of which are established by the Board of Directors of the Company. Certain restrictions contained in the Company's loan agreements limit the amount of dividends which may be declared. There is no present plan to pay cash dividends on common stock as the Company intends to reinvest its cash flows for continued growth of the Company. In addition to stock options outstanding, the Company has 100,000 warrants outstanding at an exercise price of $9.90 per share. The expiration date for 100,000 warrants is April 2002. A tax benefit related to the exercise of employee stock options of $95,000 in 2000 and $324,000 in 1998 was allocated directly to additional paid in capital. Such benefit was not material in year 1999. Shareholder Rights Plan In September 1997, Bellwether adopted a shareholder rights plan to protect Bellwether's shareholders from coercive or unfair takeover tactics. Under the shareholder rights plan, each outstanding share of Bellwether common stock and each share of subsequently issued Bellwether common stock has attached to it one right. The rights become exercisable if a person or group acquires or announces an intention to acquire beneficial ownership of 15% or more of the outstanding shares of Bellwether common stock without the prior consent of Bellwether. When the rights become exercisable each holder of a right will have the right to receive, upon exercise of the right, a number of shares of common stock of Bellwether which, at the time the rights become exercisable, have a market price of two times the exercise price of the right. Bellwether may redeem the rights for $.01 per right at any time before they become exercisable without shareholder approval. The rights will expire on September 26, 2007, subject to earlier redemption by the board of directors of Bellwether. Earnings Per Share The following represents the reconciliation of the numerator (income) and denominator (shares) of the earnings per share computation to the numerator and denominator of the diluted earnings per share computation. The Company's reconciliation is as follows (amounts in thousands, except per share amounts):
Year Ended December 31, Year Ended 2000 December 31, 1999 -------------------------- ----------------------- Income Shares Per Share Income Shares Per Share -------- ------ --------- ------ ------ --------- Net income................. $ 32,208 $8,813 -------- ------ ------ ------ ------ ----- Earnings per Common share.. $ 32,208 13,899 $ 2.32 $8,813 13,854 $0.64 Effect of Dilutive Securities: Options & Warrants........ -- 276 -- 42 -------- ------ ------ ------ ------ ----- Earnings per common share-- diluted................... $ 32,208 14,175 $ 2.27 $8,813 13,896 $0.63 ======== ====== ====== ====== ====== ===== Year Ended December 31, 1998 -------------------------- Income Shares Per Share -------- ------ --------- Net Income (loss).......... $(77,251) -------- ------ ------ Earnings (loss) per Common share..................... $(77,251) 14,039 $(5.50) Effect of Dilutive Securities: Options & Warrants........ -- -- -- -------- ------ ------ Earnings (loss) per common share--diluted............ $(77,251) 14,039 $(5.50) ======== ====== ======
43 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) For the year ended December 31, 1998, diluted earnings per share were not calculated since the issuance or conversion of additional securities would have had an antidilutive effect due to the loss in the period. Options and warrants equal to 584,500 in 2000 and 1,181,499 in 1999 that could potentially dilute basic earnings per share in the future were not included in the computation of diluted earnings per share because to do so would have been antidilutive. Treasury Stock In September 1998, the Company's Board of Directors authorized the repurchase of up to $5.0 million of the Company's common stock. As of December 31, 1999, 311,000 shares had been acquired at an aggregate price of $1,905,000. These treasury shares are reported at cost as a reduction to Stockholders' Equity. Stock Incentive Plans The Company has stock option plans that provide for granting of options for the purchase of common stock to directors, officers and key employees of the Company and Torch. These stock options may be granted subject to terms ranging from 6 to 10 years at a price equal to the fair market value of the stock at the date of grant. At year end 2000 the plans allow the Company 28,500 options. On May 15, 2000 the Company's president was granted 500,000 options with an exercise price set at the average price for the 30 days prior to the grant date. Such average price was less than the closing price on the grant date. The Company is required to recognize compensation expense, over the vesting period, for the options equal to the difference between the exercise price and the close price of Bellwether's stock on the grant date. A charge of $536,070 was recorded in May 2000, when one-third of the options vested. The remaining expense is charged ratably over the vesting period of two years. Relative to these options, total compensation expense recognized for the year ended December 31, 2000 was $849,000. At December 31, 2000, an unrecorded liability of approximately $759,000 exists for the unvested cost of these options. A summary of activity in the stock option plans is set forth below:
Option Price Range Number Of ------------ Shares Low High --------- ----- ------ Balance at December 31, 1997........................... 1,387,825 $3.00 $12.38 Granted.............................................. 300,000 $6.25 $10.94 Surrendered.......................................... (146,000) $5.62 $12.38 Exercised............................................ (273,325) $3.00 $ 7.75 Balance at December 31, 1998........................... 1,268,500 $4.38 $12.38 Granted.............................................. 653,500 $3.34 $ 6.22 Surrendered.......................................... (390,000) $3.34 $10.19 Exercised............................................ (4,000) $3.34 $ 3.34 Balance at December 31, 1999........................... 1,528,000 $3.34 $12.38 Granted.............................................. 917,500 $4.25 $ 8.75 Surrendered.......................................... (51,999) $3.34 $ 7.97 Exercised............................................ (90,835) $3.34 $ 7.63 Balance at December 31, 2000........................... 2,302,666 $3.34 $12.38 ========= ===== ====== Exercisable at December 31, 2000....................... 1,732,502 $3.34 $12.38 ========= ===== ======
44 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Detail of stock options outstanding and options exercisable at December 31, 2000 follows:
Outstanding Exercisable ------------------------------- ------------------ Weighted Weighted Weighted Average Average Average Remaining Exercise Exercise Range of Exercise Prices Number Life (Years) Price Number Price - ------------------------ --------- ------------ -------- --------- -------- 1994 Plan $3.34 to $ 7.63.... 563,166 5.7 $5.21 447,001 $5.29 1996 Plan $3.34 to $12.38.... 1,739,500 9.2 $6.63 1,285,501 $6.78 --------- --------- Total.................... 2,302,666 1,732,502 ========= =========
The estimated weighted average fair value per share of options granted during 2000, 1999, and 1998 was $12.75, $11.68 and $2.34, respectively. The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions. For 2000, expected stock price volatility of 65%; a risk free interest rate of 5.1%; and an average expected option life of 10 years. For 1999, expected stock price volatility of 93%; a risk free interest rate of 6.5%; and an average expected option life of 10 years. For 1998, expected stock price volatility of 40%; a risk free interest rate of 5.5%, an average expected option life of 5 years. Had compensation expense for stock-based compensation been determined based on the fair value at the date of grant, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands, except share information):
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2000 1999 1998 ------------ ------------ ------------ Net income (loss) As reported............................ $32,208 $ 8,813 $(77,251) Pro forma.............................. $24,955 $(19,516) $(78,321) Earnings (loss) per share As reported............................ $ 2.32 $ .64 $ (5.50) Pro forma.............................. $ 1.79 $ (1.41) $ (5.58) Diluted earnings (loss) per share As reported............................ $ 2.27 $ .63 $ (5.50) Pro forma.............................. $ 1.76 $ (1.41) $ (5.58)
6. Derivative Financial Instruments The Company periodically uses derivative financial instruments to manage oil and gas price risk; generally commodity price swap agreements which provide for the Company to receive or make counterparty payments on the differential between a fixed price and a variable indexed price for natural gas or crude oil. Gains and losses from these hedging activities are included in oil and gas sales at the time the related production is delivered. Hedging activities decreased revenues by $24.5 million and $4.0 million for the years 2000 and 1999, respectively. Revenues for the year 1998 were increased by $3.6 million due to hedging activities. 45 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The following tables detail the Company's hedges of future production, which were in place at December 31, 2000. The oil hedge was transacted in August 2000. All gas hedges were entered into before March 2000. Oil Hedges
NYMEX NYMEX BBLS Total Price Price Period Per Day BBLS Type Floor Ceiling ------ ------- ------- ------ ------ ------- Jan. 2001-Dec. 2001................. 1,500 547,500 Collar $24.00 $30.00
Gas Hedges
NYMEX NYMEX MCF Price Price Period Per Day Total MCF Type Floor Ceiling ------ ------- ---------- ------ ----- ------- Jan. 2001-March 2001.............. 25,000 2,250,000 Collar $2.30 $3.37 April 2001-Oct. 2001.............. 35,000 97,490,000 Collar $2.30 $2.92
The fair value at December 31, 2000 of these swap agreements was a loss of $33.1 million. These energy swap agreements expose the Company to counterparty credit risk to the extent the counterparty is unable to meet its monthly settlement commitment to the Company. Bellwether entered into a gas swap for $4.60 per mcf on 15,000 mcf per day of production from November 2000 through October 2001. This offsets hedges previously existing on forecasted production that was sold in late 2000. A non-cash loss of $8.7 million was recognized in the fourth quarter 2000 related to the $4.60 swap, along with a related current liability. The liability will be relieved monthly as the swap is settled. By December 31, 2000, the liability had been reduced to $7.5 million. In order to reduce interest costs, effective September 22, 1998, the Company entered into an eight and one-half year's interest rate swap agreement with a notional value of $80 million. Under the agreement, the Company receives a fixed interest rate and pays a floating interest rate based on the simple average of three foreign LIBOR rates. Floating rates are redetermined for a six-month period each April 1 and October 1. The floating rate for the period from October 1, 2000 to April 1, 2001 is 10.875%. Through April 1, 2002 the floating rate is capped at 10.875% and capped at 12.375% thereafter. The Company's interest rate swap will not be designated for hedge accounting upon implementation of SFAS 133, therefore, the interest rate swap will be recorded at fair value with a corresponding charge to income. Determination of Fair Values of Financial Instruments Fair value for cash, short-term investments, receivables and payables approximates carrying value. The following table details the carrying values and approximate fair values of the Company's other investments, derivative financial instruments and long-term debt at December 31, 2000 and 1999 (in thousands).
December 31, 2000 December 31, 1999 ---------------------- ---------------------- Carrying Approximate Carrying Approximate Value Fair Value Value Fair Value --------- ----------- --------- ----------- Assets (Liabilities): Derivative instruments other than trading: Interest rate swap agreements................... $ -- $ (4,411) $ -- $ 3,045 Production swap agreements.... $ -- $ (33,133) $ -- $ 862 Long-term debt (See Note 7)..... $(125,450) $(114,890) $(130,000) $(125,485)
46 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 7. Long-Term Debt Long-term debt is comprised of the following at December 31, 2000 and 1999 (in thousands):
December 31, December 31, 2000 1999 ------------ ------------ Bank credit facility............................ $ 25,450 $ 30,000 10 7/8% Senior Subordinated Notes............... 100,000 100,000 -------- -------- Long-term debt.................................. $125,450 $130,000 ======== ========
Debt maturities by fiscal year are as follows (amounts in thousands): 2000............................................................. $ -- 2001............................................................. -- 2002............................................................. 25,450 2003............................................................. -- 2004............................................................. -- Thereafter....................................................... 100,000 -------- $125,450 ========
In April 1997, the Company entered into a senior revolving unsecured credit facility ("Senior Credit Facility") in an amount up to $90.0 million, with a borrowing base to be re-determined semi-annually, and a maturity date of November 5, 2003. On May 20, 1999 the borrowing base was re-determined to be $55.0 million. Subsequent amendments reflecting the impact of the property sales in 2000 have reduced the borrowing base to $34.5 million at December 31, 2000. At December 31, 2000, there were $24.5 million in borrowings outstanding under the Senior Credit Facility. In February 2001, the senior credit facility was amended to reduce the facility amount to $40 million while increasing the borrowing base to $35 million. The maturity date was changed to August 2002. Bellwether may elect an interest rate based either on a margin plus London Interbank Offered Rate ("LIBOR") or the higher of the prime rate or the sum of 0.5% of 1% plus the Federal Funds Rate. For LIBOR borrowings, the interest rate will vary from LIBOR plus 1.0% to LIBOR plus 3.5% based upon the borrowing base usage. The Senior Credit Facility contains various covenants including certain required financial measurements for current and interest ratios and consolidated tangible net worth. As of December 31, 2000 the Company was in compliance with all debt covenants. In addition, the Senior Credit Facility contains the following limitations: 1) Bellwether and its subsidiaries will not sell all or substantially all of their assets to another person, 2) none of Bellwether or its subsidiaries will incur additional indebtedness with the exception of permitted indebtedness, 3) the indebtedness of Bellwether's subsidiaries will not exceed 10% of consolidated tangible net worth (indebtedness from subsidiaries to Bellwether or guarantors is permitted), 4) none of Bellwether or its subsidiaries will make any restricted payments or restricted investments unless no default exists under the Senior Credit Facility and all such restricted payments and investments made since closing do not exceed the sum of (A) $5 million plus (B) 25% consolidated net income (less 100% of losses) plus (C) net cash proceeds of non-redeemable stock, provided, there are no payments made on permitted subordinated debt prior to stated maturity. In April 1997, the Company issued $100.0 million of 10 7/8% Senior Subordinated Notes ("Notes") that mature April 1, 2007. Interest on the Notes is payable semi-annually on April 1 and October 1. The Notes will be redeemable, in whole or in part, at the option of the Company at any time on or after April 1, 2002 at 105.44% 47 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) which decreases annually to 100.00% on April 1, 2005 and thereafter, plus accrued and unpaid interest. In the event of a change of control of the Company, each holder of the Notes will have the right to require the Company to repurchase all or part of such holder's Notes at an offer price in cash equal to 101.0% of the aggregate principal amount thereof, plus accrued and unpaid interest to the date of purchase. The Notes contain certain covenants, including limitations on indebtedness, restricted payments, transactions with affiliates, liens, guarantees of indebtedness by subsidiaries, dividends and other payment restrictions affecting restricted subsidiaries, issuance and sales of restricted subsidiary stock, disposition of proceeds of asset sales, and restrictions on mergers, and consolidations or sales of assets. Effective September 22, 1998, the Company entered into an eight and one- half year's interest rate swap agreement with a notional value of $80 million. Under the agreement, the Company receives a fixed interest rate and pays a floating interest rate based on the simple average of three foreign LIBOR rates. Floating rates are redetermined for a six-month period each April 1 and October 1. The floating rate for the period from October 1, 1999 to April 1, 2000 is 9.64%. Through April 1, 2002 the floating rate is capped at 10.875% and capped at 12.375% thereafter. This interest swap is accounted for as a hedge. 8. Income Taxes Income tax expense (benefit) is summarized as follows (in thousands):
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2000 1999 1998 ------------ ------------ ------------ Current Federal........................ $ 67 $ (425) $ 658 State.......................... 18 10 93 Deferred--Federal, Foreign and State........................... (12,307) (2,739) (6,820) -------- ------- ------- Total income tax benefit......... $(12,222) $(3,154) $(6,069) ======== ======= =======
The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 2000 and 1999 is as follows:
December 31, December 31, 2000 1999 ------------ ------------ Net operating loss carryforwards.................. $10,091 $10,296 Percentage depletion carryforwards................ 271 271 Alternative minimum tax credit carryforwards...... 752 725 Property, plant and equipment..................... 3,087 9,551 State income taxes................................ 1,138 1,732 ------- ------- Total deferred income tax assets.................. 15,339 22,575 ------- ------- Valuation allowances.............................. -- (19,836) Foreign income taxes.............................. (198) -- ------- ------- Total deferred income tax liability............... (198) (19,836) ------- ------- Net deferred income tax asset..................... $15,141 $ 2,739 ======= =======
At December 31, 1999, the Company determined that it is more likely than not that a portion of the deferred tax assets will not be realized and the valuation allowance was adjusted by $5.2 million to a total valuation allowance of $19.8 million. At December 31, 2000, however, the Company determined that it was more likely 48 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) than not that the deferred tax assets would be realized based on current projections of taxable income due to higher commodity prices at year end 2000, and the valuation allowance was decreased by $19.8 million to zero. A tax benefit related to the exercise of employee stock options of approximately $95,000 was allocated directly to additional paid-in capital in 2000. Such benefit was not material in 1999. Total income tax differs from the amount computed by applying the Federal income tax rate to income before income taxes and minority interest. The reasons for the differences are as follows:
Year Ended Year Ended Year Ended December 31, December 31, December 31, 2000 1999 1998 ------------ ------------ ------------ Statutory Federal income tax rate... 34.0% 34.0% (34.0)% Increase (decrease) in tax rate resulting from: State income taxes, net of federal benefit............................ 3.0% 3.1% (3.1)% Foreign income taxes, net of federal benefit............................ 1.0% -- -- Non-deductible travel and entertainment...................... 0.1% 0.2% 0.1% Other............................... -- (.8)% -- Change in valuation allowance....... (99.3)% (92.2)% 29.7% ----- ----- ----- (61.2)% (55.7)% (7.3)% ===== ===== =====
The Company issued 3,400,000 shares of its common stock on July 20, 1994. As a result of the common stock issuance, the Company underwent an ownership change. Therefore, the Company's ability to use a portion of its net operating loss ("NOL") carryforwards for federal income tax purposes is subject to limitations. Section 382 of the Internal Revenue Code significantly limits the amount of NOL and investment tax credit carryforwards that are available to offset future taxable income and related tax liability when a change in ownership occurs. At December 31, 2000, the Company had net operating loss carryforwards of approximately $29 million, which will expire in future years beginning in 2001. 9. Commitments and Contingencies Lease Commitments The minimum future payments under the terms of the Company's office space operating lease is as follows:
Year Ended December 31 ($ in thousands) ---------------------- --------------- 2001 403 2002 415 2003 426 2004 430 2005 438
Rent expense was $509,000 in 2000, $16,023 in 1999 and zero in prior years. Prior to October 1999, the Company was not responsible for office rental as the administration services contract with Torch at the time included office space. When the new Torch Master Service Agreement became effective in October 1999, Bellwether began paying office rent. 49 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Other Commitments Under the Company's contract for production of oil in the Charapa field of Ecuador, the Company is required to execute a three year $12 million minimum investment program. Under a similar contract for production of oil in the Tiguino field of Ecuador, a $25 million minimum investment program over three years is required. The Ecuadorian national oil company requires guarantees for a portion of each investment program. Such guarantees are backed by the Company's letters of credit totaling $7.4 million. The letters of credit are drawn on the Senior Credit Facility and are renewable annually. Contingencies The Company has been named as a defendant in certain lawsuits incidental to its business. Management does not believe that the outcome of such litigation will have a material adverse impact on the Company. The Company was defendant in Cause No. C-4417-96-G; A.R. Guerra, et al. v. Eastern Exploration, Inc., et al. in the 370th Judicial District Court of Hidalgo County, Texas. On May 11, 1999, the trial court granted plaintiff's Motion of Summary Judgement and denied defendants' Motion of Summary Judgement. The trial court awarded plaintiffs in excess of $5.8 million on damages plus interest. The Company settled the case in early 2000 for the sum of $353,500, net to its interest. 10. Selected Quarterly Financial Data (amounts in thousands, except per share data) (Unaudited):
Quarter Ended --------------------------------------------- December 31, September 30, June 30, March 31, 2000 2000 2000 2000 ------------ ------------- -------- --------- Revenues........................ $35,229 $30,810 $25,953 $24,611 Operating income................ $ 680 $ 8,639 $ 5,011 $ 5,656 Net income...................... $ 432 $ 5,357 $ 3,029 $23,390 Earnings per common share....... $ 0.03 $ 0.38 $ 0.22 $ 1.69 Earnings per common shares-- diluted........................ $ 0.03 $ 0.37 $ 0.21 $ 1.67
Quarter Ended --------------------------------------------- December 31, September 30, June 30, March 31, 1999 1999 1999 1999 ------------ ------------- -------- --------- Revenues........................ $24,631 $17,771 $15,335 $13,326 Operating income (loss)......... $ 7,283 $ (463) $ 123 $(1,284) Net income (loss)............... $ 9,972 $ 2 $ 123 $(1,284) Earnings (loss) per common share.......................... $ 0.72 $ 0.00 $ 0.01 $ (0.09) Earnings (loss) per common share--diluted................. $ 0.71 $ 0.00 $ 0.01 $ (0.09)
The income in the quarter ended March 31, 2000 reflects the recognition of a $19.8 million tax asset based upon increased future net reserves. 50 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 11. Segment Reporting The Company's operations are concentrated primarily in three segments: exploration and production of oil and natural gas in the United States, in Ecuador and gas plants.
Year Ended December 31, --------------------------- 2000 1999 1998 -------- -------- -------- Sales to unaffiliated customers: Oil and gas--US................................ $107,938 $ 68,264 $ 73,652 Oil and gas--Ecuador........................... 4,315 -- -- Gas plants..................................... 6,070 3,830 3,170 -------- -------- -------- Total sales.................................. 118,323 72,094 76,822 Interest and other income...................... 957 1,335 1,347 Total revenues............................... 119,280 73,429 78,169 ======== ======== ======== Operating profit (loss) before income taxes: Oil and gas--US................................ $ 40,983 $ 22,570 $(65,751) Oil and gas--Ecuador........................... 719 (17) -- Gas plants..................................... 3,393 1,464 1,203 -------- -------- -------- $ 45,095 $ 24,017 $(64,548) Unallocated corporate expenses................. 9,734 6,513 7,112 Interest expense............................... 15,375 11,845 11,660 -------- -------- -------- Operating profit (loss) before income taxes.... $ 19,986 $ 5,659 $(83,320) ======== ======== ======== Identifiable assets: Oil and gas--US................................ $125,586 $123,686 $ 95,786 Oil and gas--Ecuador........................... 12,243 1,246 -- Gas plants..................................... 11,107 11,641 12,430 -------- -------- -------- $148,936 $136,573 $108,216 Corporate assets and investments............... 72,609 35,188 22,980 -------- -------- -------- Total........................................ $221,545 $171,761 $131,196 ======== ======== ======== Capital expenditures: Oil and gas--US................................ $ 76,242 $ 56,793 $ 40,179 Oil and gas--Ecuador........................... 12,130 -- -- Gas plants..................................... 677 369 689 -------- -------- -------- $ 89,049 $ 57,162 $ 40,868 ======== ======== ======== Depreciation, depletion amortization and impairments: Oil and gas--US................................ $ 30,356 $ 22,643 $112,447 Oil and gas--Ecuador........................... 745 -- -- Gas plants..................................... 1,211 1,159 1,140 -------- -------- -------- $ 32,312 $ 23,802 $113,587 ======== ======== ========
51 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) 12. Supplemental Information--(Unaudited) Oil and Gas Producing Activities: Included herein is information with respect to oil and gas acquisition, exploration, development and production activities, which is based on estimates of year-end oil and gas reserve quantities and estimates of future development costs and production schedules. Reserve quantities and future production are based primarily upon reserve reports prepared by the independent petroleum engineering firm Ryder Scott Company the years ended December 31, 2000, 1999 and 1998. These estimates are inherently imprecise and subject to substantial revision. Estimates of future net cash flows from proved reserves of gas, oil, condensate and natural gas liquids were made in accordance with Statement of Financial Accounting Standards No. 69, "Disclosures about Oil and Gas Producing Activities." The estimates are based on prices at year-end. Estimated future cash inflows are reduced by estimated future development costs (including future abandonment and dismantlement), and production costs based on year-end cost levels, assuming continuation of existing economic conditions, and by estimated future income tax expense. Tax expense is calculated by applying the existing statutory tax rates, including any known future changes, to the pre-tax net cash flows, less depreciation of the tax basis of the properties and depletion allowances applicable to the gas, oil, condensate and NGL production. The impact of the net operating loss is considered in calculation of tax expense. The results of these disclosures should not be construed to represent the fair market value of the Company's oil and gas properties. A market value determination would include many additional factors including: 1) anticipated future increases or decreases in oil and gas prices and production and development costs; 2) an allowance for return on investment; 3) the value of additional reserves not considered proved at the present, which may be recovered as a result of further exploration and development activities; and 4) other business risks. 52 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Costs Incurred (in thousands)
Year Ended December 31, ----------------------- 2000 1999 1998 ------- ------- ------- United States: Property acquisition: Proved properties.................................. $ 5,065 $22,428 $ 617 Unproved properties................................ -- 2,406 8,788 Exploration........................................ 13,139 14,052 16,186 Development: Proved developed properties........................ 41,615 15,500 10,755 Proved undeveloped properties...................... 16,423 1,352 3,642 ------- ------- ------- $76,242 $55,738 $39,988 ------- ------- ------- Ecuador: Property acquisition: Proved properties.................................. $ 2,013 $ 651 $ -- Unproved properties................................ -- 404 191 Development: Proved developed properties........................ 10,117 -- -- Proved undeveloped properties...................... -- -- -- ------- ------- ------- $12,130 $ 1,055 $ 191 ------- ------- ------- Worldwide: Property acquisition: Proved properties.................................. $ 7,078 $23,079 $ 617 Unproved properties................................ -- 2,810 8,979 Exploration........................................ 13,139 14,052 16,186 Development: Proved developed properties........................ 51,732 15,500 10,755 Proved undeveloped properties...................... 16,423 1,352 3,642 ------- ------- ------- $88,372 $56,793 $40,179 ======= ======= =======
53 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Capitalized costs (in thousands):
Year Ended December 31, -------------------- 2000 1999 --------- --------- United States: Proved properties..................................... $ 410,048 $ 328,453 Unproved properties................................... 11,360 16,325 --------- --------- Total capitalized costs............................. 421,408 344,778 Accumulated depreciation, depletion, amortization and impairment............................................. (295,822) (221,092) --------- --------- Net capitalized costs................................... $ 125,586 $ 123,686 --------- --------- Ecuador: Proved properties..................................... $ 12,988 $ 842 Unproved properties................................... -- 404 --------- --------- Total capitalized costs............................. 12,988 1,246 Accumulated depreciation, depletion, amortization and impairment............................................. (745) -- --------- --------- Net capitalized costs................................... $ 12,243 $ 1,246 --------- --------- Worldwide: Proved properties..................................... $ 423,036 $ 329,295 Unproved properties................................... 11,360 16,729 --------- --------- Total capitalized costs............................. 434,396 346,024 Accumulated depreciation, depletion, amortization and impairment............................................. (296,567) (221,092) --------- --------- Net capitalized costs................................... $ 137,829 $ 124,932 ========= =========
54 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Results of operations for producing activities (in thousands):
Year Ended December 31, 2000 ----------------------------- U.S. Ecuador Worldwide -------- -------- --------- Revenues from oil and gas producing activities... $107,938 $ 4,315 $112,253 Production expenses.............................. 27,694 2,815 30,509 Disposition of hedges............................ 8,671 -- 8,671 Transportation costs............................. 234 36 270 Income tax....................................... 15,574 -- 15,574 Depreciation, depletion and amortization......... 30,356 745 31,101 -------- -------- -------- Results of operations from producing activities (excluding corporate overhead and interest costs).......................................... $ 25,409 $ 719 $ 26,128 ======== ======== ======== Year Ended December 31, ------------------ 1999(1) 1998(1) -------- -------- Revenues from oil and gas producing activities... $ 68,264 $ 73,652 Production costs................................. 21,532 25,381 Transportation costs............................. 316 435 Income tax....................................... 8,820 -- Impairment expense............................... -- 73,899 Depreciation, depletion and amortization......... 22,643 38,548 -------- -------- Results of operations from producing activities (excluding corporate overhead and interest costs).......................................... $ 14,953 $(64,611) ======== ========
- -------- (1) Ecuador activities did not commence production until 2000; therefore, no prior year information for international operations is disclosed. Per unit sales prices and costs
Year Ended December 31, ---------------------- 2000 1999(2) 1998(2) ------ ------ ------ Average sales price, including the effect of hedges Oil and condensate (per BBL)--US..................... $20.53 $12.84 $11.75 Oil and condensate (per BBL)--Ecuador................ $24.80 $ -- $ -- Natural gas (per MCF)................................ $ 3.06 $ 2.19 $ 2.19 Average sales price, excluding the effect of hedges Oil and condensate (per BBL)--US..................... $24.40 $14.48 $11.44 Oil and condensate (per BBL)--Ecuador................ $24.80 (1) (1) Natural gas (per MCF)................................ $ 3.84 $ 2.22 $ 2.06 Average production expenses per BOE--US................ $ 4.93 $ 4.11 $ 4.34 Average production expenses per BOE--Ecuador........... $16.18 $ (1) $ (1) Average depletion rate per BOE--US..................... $ 5.46 $ 4.32 $ 6.59 Average depletion rate per BOE--Ecuador................ $ 4.28 (1) (1)
- -------- (1) Ecuador activities commenced production in 2000; therefore, prior year price and cost information is not disclosed. 55 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The Company's estimated total proved and proved developed reserves of oil and gas are as follows:
Year Ended December 31, 2000 ---------------------- Oil NGL Gas Description (MBBL) (MBBL) (MMCF) - ----------- ------ ----- ------- United States: Proved reserves at beginning of period.................. 10,827 2,069 130,079 Revisions of previous estimates......................... 1,033 93 (21,291) Extensions and discoveries.............................. 613 4 18,418 Production.............................................. (1,987) (219) (20,478) Sales of reserves in-place.............................. (817) (292) (31,999) Purchase of reserves in-place........................... -- -- -- ------ ----- ------- Proved reserves at end of period........................ 9,669 1,655 74,729 ====== ===== ======= Proved developed reserves-- Beginning of period................................... 9,990 2,032 108,491 ====== ===== ======= End of period......................................... 9,073 1,508 68,757 ====== ===== ======= Ecuador: (1) Proved reserves at beginning of period.................. 3,884 -- -- Revisions of previous estimates......................... (714) -- -- Production.............................................. (174) -- -- Purchase of reserves in-place........................... 4,817 -- -- ------ ----- ------- Proved reserves at end of period........................ 7,813 -- -- ====== ===== ======= Proved developed reserves-- Beginning of period................................... 245 -- -- ====== ===== ======= End of period......................................... 2,135 -- -- ====== ===== ======= Worldwide: Proved reserves at beginning of period.................. 14,711 2,069 130,079 Revisions of previous estimates......................... 319 93 (21,291) Extensions and discoveries.............................. 613 4 18,418 Production.............................................. (2,161) (219) (20,478) Sales of reserves in-place.............................. (817) (292) (31,999) Purchase of reserves in-place........................... 4,817 -- -- ------ ----- ------- Proved reserves at end of period........................ 17,482 1,655 74,729 ====== ===== ======= Proved developed reserves-- Beginning of period................................... 10,235 2,032 108,491 ====== ===== ======= End of period......................................... 11,208 1,508 68,757 ====== ===== =======
56 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Year Ended Year Ended December 31, 1999 December 31, 1998 ---------------------- ----------------------- Oil NGL Gas Oil NGL Gas Description (MBBL) (MBBL) (MMCF) (MBBL) (MBBL) (MMCF) - ----------- ------ ----- ------- ------ ------ ------- United States: Proved reserves at beginning of period................... 8,489 1,573 111,585 12,238 2,571 125,960 Revisions of previous estimates................... 2,671 798 (767) (2,473) (1,032) (5,944) Extensions and discoveries... 499 -- 11,636 813 225 9,416 Production................... (1,831) (249) (18,965) (2,106) (191) (21,302) Sales of reserves in-place... (262) (60) (6,754) (4) -- (167) Purchase of reserves in- place....................... 1,261 7 33,344 21 -- 3,622 ------ ----- ------- ------ ------ ------- Proved reserves at end of period...................... 10,827 2,069 130,079 8,489 1,573 111,585 ====== ===== ======= ====== ====== ======= Proved developed reserves-- Beginning of period........ 8,021 1,554 106,253 11,153 2,460 119,270 ====== ===== ======= ====== ====== ======= End of period.............. 9,990 2,032 108,491 8,021 1,554 106,253 ====== ===== ======= ====== ====== ======= Ecuador: (1) Purchase of reserves in- place....................... 3,884 -- -- -- -- -- ------ ----- ------- ------ ------ ------- Proved reserves at end of period...................... 3,884 -- -- -- -- -- ====== ===== ======= ====== ====== ======= Proved developed reserves-- Beginning of period........ -- -- -- -- -- -- ====== ===== ======= ====== ====== ======= End of period.............. 245 -- -- -- -- -- ====== ===== ======= ====== ====== ======= Worldwide: Proved reserves at beginning of period................... 8,489 1,573 111,585 12,238 2,571 125,960 Revisions of previous estimates................... 2,671 798 (767) (2,473) (1,032) (5,944) Extensions and discoveries... 499 -- 11,636 813 225 9,416 Production................... (1,831) (249) (18,965) (2,106) (191) (21,302) Sales of reserves in-place... (262) (60) (6,754) (4) -- (167) Purchase of reserves in- place....................... 5,145 7 33,344 21 -- 3,622 ------ ----- ------- ------ ------ ------- Proved reserves at end of period...................... 14,711 2,069 130,079 8,489 1,573 111,585 ====== ===== ======= ====== ====== ======= Proved developed reserves-- Beginning of period........ 8,021 1,554 106,253 11,153 2,460 119,270 ====== ===== ======= ====== ====== ======= End of period.............. 10,235 2,032 108,491 8,021 1,554 106,253 ====== ===== ======= ====== ====== =======
- -------- (1) The Company's Latin American reserves are pursuant to a contract with the Ecuadorian government under which the Company does not own the reserves but has a contractual right to produce the reserves and receive revenues. Relating to the reserves added in 2000, all documentation and agreements giving the Company the right to production from the field have been completed, but final approval from the Ecuadorian government has not yet been received. No similar assignments have ever been denied government approval. 57 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) Discounted future net cash flows (in thousands) The standardized measure of discounted future net cash flows and changes therein related to proved oil and gas reserves are shown below:
Year Ended December 31, ------------------------------ 2000 1999 1998 ---------- -------- -------- United States: Future cash flow................................ $ 950,121 $535,605 $328,285 Future production costs......................... (203,464) (202,800) (132,108) Future income taxes............................. (183,139) (23,234) -- Future development costs........................ (36,874) (54,034) (29,609) ---------- -------- -------- Future net cash flows........................... 526,644 255,537 166,568 10% discount factor............................. (133,062) (63,933) (50,588) ---------- -------- -------- Standardized future net cash flows.............. $ 393,582 $191,604 $115,980 ========== ======== ======== Ecuador: Future cash flow................................ $ 174,632 $ 88,089 $ -- Future production costs......................... (60,899) (34,534) -- Future income taxes............................. (37,793) (9,860) -- Future development costs........................ (27,595) (13,273) -- ---------- -------- -------- Future net cash flows........................... 48,345 30,422 -- 10% discount factor............................. (18,835) (17,138) -- ---------- -------- -------- Standardized future net cash flows.............. $ 29,510 $ 13,284 $ -- ========== ======== ======== Worldwide: Future cash flow................................ $1,124,753 $623,694 $328,285 Future production costs......................... (264,363) (237,334) (132,108) Future income taxes............................. (220,932) (33,094) -- Future development costs........................ (64,469) (67,307) (29,609) ---------- -------- -------- Future net cash flows........................... 574,989 285,959 166,568 10% discount factor............................. (151,897) (81,071) (50,588) ---------- -------- -------- Standardized future net cash flows.............. $ 423,092 $204,888 $115,980 ========== ======== ========
58 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued) The following are the principal sources of change in the standardized measure of discounted future net cash flows (in thousands of dollars):
Year Ended December 31, 2000 --------------------------- United World Ecuador States Wide ------- -------- -------- Standardized measure--beginning of year.......... $13,284 $191,604 $204,888 Sales, net of production costs................... (1,500) (80,244) (81,744) Purchases of reserves in-place................... 28,389 -- 28,389 Net change in prices and production costs........ (23,174) 375,242 352,068 Net change in income taxes....................... (14,430) (113,444) (127,874) Extensions, discoveries and improved recovery, net of future production and development costs.. -- 56,283 56,283 Changes in estimated future development costs.... (1,990) (4,942) (6,932) Development costs incurred during the period..... 4,329 31,095 35,424 Revisions of quantity estimates.................. (6,787) (46,271) (53,058) Accretion of discount............................ 1,329 19,160 20,489 Sales of reserves in-place....................... -- (34,697) (34,697) Changes in production rates and other............ 30,060 (204) 29,856 ------- -------- -------- Standardized measure--end of year................ $29,510 $393,582 $423,092 ======= ======== ========
Year Ended December 31, 1999 --------------------------- United World Ecuador States Wide ------- -------- -------- Standardized measure--beginning of year.......... $ -- $115,980 $115,980 Sales, net of production costs................... -- (50,430) (50,430) Purchases of reserves in-place................... 17,431 40,488 57,919 Net change in prices and production costs........ -- 40,736 40,736 Net change in income taxes....................... (4,147) -- (4,147) Extensions, discoveries and improved recovery, net of future production and development costs.. -- 23,497 23,497 Changes in estimated future development costs.... -- (3,304) (3,304) Development costs incurred during the period..... -- 8,930 8,930 Revisions of quantity estimates.................. -- 20,565 20,565 Accretion of discount............................ -- 11,598 11,598 Sales of reserves in-place....................... -- (6,575) (6,575) Changes in production rates and other............ -- (9,881) (9,881) ------- -------- -------- Standardized measure--end of year................ $13,284 $191,604 $204,888 ======= ======== ========
59 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Year Ended December 31, 1998 ------------ Standardized measure--beginning of year....................... $185,715 Sales, net of production costs................................ (44,264) Purchases of reserves in-place................................ 3,379 Net change in prices and production costs..................... (55,408) Net change in income taxes.................................... 14,517 Extensions, discoveries and improved recovery, net of future production and development costs............................. 8,255 Changes in estimated future development costs................. 4,542 Development costs incurred during the period.................. 11,244 Revisions of quantity estimates............................... (20,520) Accretion of discount......................................... 18,572 Sales of reserves in-place.................................... (260) Changes in production rates and other......................... (9,792) -------- Standardized measure--end of year............................. $115,980 ========
The discounted future cash flows above were calculated using NYMEX equivalent prices of $26.80, $25.60, and $12.05 per barrel and $9.52, $2.33, and $2.15 per MMBTU, for December 31, 2000, 1999, and 1998, respectively, adjusted to the wellhead to reflect adjustments for transportation, quality and heating content. The foregoing discounted future net cash flows do not include the effects of hedging or other derivative contracts not specific to a property. Including the tax effected impact of hedging on discounted future net cash flows would have increased discounted future net cash flows by approximately $370,000 in 1999. Including the tax effected impact of hedging on discounted future cash flows would have decreased discounted future net cash flows by approximately $35.7 million in 2000. 60 BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None PART III Item 10. Directors and Executive Officers of the Registrant The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2000. Such information is incorporated herein by reference. Item 11. Executive Compensation The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2000. Such information is incorporated herein by reference. Item 12. Security Ownership of Certain Beneficial Owners and Management The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2000. Such information is incorporated herein by reference. Item 13. Certain Relationships and Related Transactions The information required by this item will be included in a definitive proxy statement, pursuant to Regulation 14A, to be filed not later than 120 days after December 31, 2000. Such information is incorporated herein by reference. PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K (a) 1. and Financial Statements. See index to Consolidated Financial Statements 2. and Supplemental Information in Item 8, which information is incorporated herein by reference. 2.1 Agreement and Plan of Merger dated January 24, 2001 between the Company and Bargo Energy Company (incorporated by reference to Exhibit 2.1 to the Company's 8-K dated January 26, 2001). 3. Exhibits 3.1 Certificate of Incorporation of Bellwether Exploration Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement No. 33-76570) 3.2 Certificate of Amendment to Certificate of Incorporation (incorporated by reference to Exhibit 3.2 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 1997) 3.3 Certificate of Designation, Preferences and Rights of Series A Preferred Stock (incorporated by reference to Exhibit 1 to the Company's Registration Statement on Form 8-A dated September 19, 1997.) 3.4 By-laws of Bellwether Exploration Company (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement No. 33-76570)
61 3.5 Amendment to Article II, Section 2.2 of Bellwether Exploration Company's Bylaws (incorporated by reference to Exhibit 3.5 to the Company's Annual Report on Form 10-K for the transition period ended December 31, 1997). 3.6 Amendment to Bellwether Exploration Company's bylaws adopted on March 27, 1998 (incorporated by reference to Exhibit 3.6 to the Company's Annual Report on Form 10-K for the transition period ended December 31, 1997). 4.1 Specimen Stock Certificate (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-1, File No. 33- 76570) 4.2 The Company's 1996 Stock Incentive Plan (incorporated by reference to Exhibit 10.20 to the Company's Registration Statement on Form S-1, File No. 33-21813) 4.3 Indenture dated April 9, 1997 among the Company, a Subsidiary Guarantor and Bank of Montreal Trust Company (incorporated herein by reference to Exhibit 4.2 to the Company's Registration Statement on Form S-1, Registration No. 33-21813) 4.4 First Supplemental Indenture dated April 21, 1997 among the Company, Odyssey Petroleum Company, Black Hawk Oil Company, 1989-I TEAI Limited Partnership and Bank of Montreal Trust Company, as Trustee (incorporated by reference to Exhibit 99.2 on the Company's Form 8-K Current Report filed on April 23, 1997) 4.5 Shareholders Rights Agreement between the Company and American Stock Transfer & Trust Company (incorporated herein by reference to the Company's Registration Statement on Form 8-A as filed with the Securities and Exchange Commission on September 19, 1997) 4.6 Warrant to Torch Energy dated April 9, 1997 (incorporated by reference to Exhibit 4.6 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 1997) 10.1 Administrative Services Agreement with Torch Energy Advisors Incorporated commencing January 1, 1994 (incorporated by reference to Exhibit 94-10-3 to the Company's Report on Form 10-Q for the quarter ended March 31, 1994) 10.2 1994 Stock Incentive Plan (incorporated by reference to Exhibit 10.9 to the Company's Registration Statement No. 33-76570) 10.3 Registration Rights Agreement among the Company, Allstate Insurance Company and the former owners of Odyssey Partners, Ltd. (incorporated by reference to Exhibit 10.4 to the Company's Registration Statement No. 33-76570) 10.4 Assignment of gas purchase contract from Texas Gas Transmission Corporation to Bellwether (incorporated by reference to Exhibit 96- 10-4 to the Company's Report on Form 10-Q for the quarter ended March 31, 1997) 10.5 Acquisition Agreement dated March 31, 1997 among Bellwether Exploration Company, Program Acquisition Company and the other parties thereto. (incorporated by reference to Exhibit 2.2 of the Company's Registration Statement on Form S-1 (Registration No. 333- 21813) filed on April 3, 1997) 10.6 Credit Agreement dated April 21, 1997 among the Company, Odyssey Petroleum Company, Black Hawk Oil Company, 1989-I TEAI Limited Partnership, Morgan Guarantee Trust Company of New York, as administrative Agent, and certain banking institutions (incorporated by reference to the Company's Form 8-K Current Report as filed with the Commission on April 23, 1997). 10.7 Purchase and Sale Agreement dated June 9, 1997 among Bellwether Exploration Company, Black Hawk Oil Company, 1988-II TEAI Limited Partnership, 1989-I TEAI Limited Partnership, TEAI Oil and Gas Company, and the other parties thereto as Sellers, and Jay Resources Corporation as Buyer (incorporated by reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K for the fiscal year ended June 30, 1997).
62 10.8 Employment contract dated June 1, 1998 between the Company and J. Darby Sere' (incorporated by reference to Exhibit 10.1 to the Company's 10-Q for the quarter ended June 30, 1998). 10.9 Employment contract dated June 1, 1998 between the Company and William C. Rankin (incorporated by reference to Exhibit 10.2 to the Company's Report on Form 10-Q for the quarter ended June 30, 1998). 10.10 Purchase and Sale Agreement dated June 11, 1999 between Bellwether Exploration Company as Buyer and Energen Resources MAQ, Inc. as Seller (incorporated by reference to Exhibit 10.15 to the Company's Report on Form 10-Q for the quarter ended June 30, 1999). 10.11 Separation contract dated August 9, 1999 between the Company and J. Darby Sere' (incorporated by reference to Exhibit 10.16 to the Company's Report on Form 10-Q for the quarter ended June 30, 1999). 10.12 Separation contract dated August 9, 1999 between the Company and William C. Rankin (incorporated herein by reference to Exhibit 10.17 to the Company's Report on Form 10-Q for the quarter ended June 30, 1999). 10.13 Employment Contract dated August 1, 1999 between the Company and J.P. Bryan (incorporated herein by reference to Exhibit 10.18 to the Company's Report on Form 10-Q for the quarter ended September 30, 1999). 10.14 Securities Purchase Agreement dated December 29, 1999 by and between the Company and Carpatsky Petroleum, Inc.--(incorporated by references to Exhibit 11.14 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999). 10.15 Master Services Agreement dated October 1, 1999 between the Company and Torch Operating Company, Torch Energy Marketing, Inc., Torch Energy Advisors, Inc. and Novistar, Inc., -- (incorporated by references to Exhibit 11.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999). 10.16 Contract for the Production of Crude Oil and Additional Hydrocarbon Exploration in the Charapa Marginal Field of Petroecuador between the Company in Consortium with Tecnipetrol, Inc. and the Ecuadorian State Oil Company, Petroecuador--(incorporated by references to Exhibit 11.16 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999). 10.17 Master Service Agreement between the Company and Tecnie S.A.C. dated November 1, 1999--(incorporated by references to Exhibit 10.17 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999). 10.18 Employment contract dated May 15, 2000 between the Company and Douglas G. Manner (incorporated by reference to Exhibit 10.20 to the Company's Report on Form 10-Q for the quarter ended June 30, 2000). 10.19 Separation agreement dated January 1, 2001 between the Company and Robert J. Bensh--included herewith. 10.20 Employment contract dated January 15, 2001 between the Company and Kent Williamson--included herewith. 11.22 Form of Voting Agreement (incorporated by reference to the Company's 8-K dated January 26, 2001). 21.1 Subsidiaries of Bellwether Exploration Company--Included herewith. 23 Consents of experts: 23.2 Consent of Ryder Scott Company 23.3 Consent of KPMG LLP
63 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Company and in the capacities and on the dates indicated. BELLWETHER EXPLORATION COMPANY /s/ Douglas G. Manner By: _________________________________ Douglas G. Manner Chief Executive Officer & Chairman Dated: March 29, 2001 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Company and in the capacities and on the dates indicated.
Signature Title Date --------- ----- ---- /s/ J. P. Bryan Director March 29, 2001 ______________________________________ J. P. Bryan /s/ Ann Kaesermann Vice President--Chief March 29, 2001 ______________________________________ Accounting Officer Ann Kaesermann /s/ Dr. Jack Birks Director March 29, 2001 ______________________________________ Dr. Jack Birks /s/ Judy Ley Allen Director March 29, 2001 ______________________________________ Judy Ley Allen /s/ Vincent H. Buckley Director March 29, 2001 ______________________________________ Vincent H. Buckley /s/ Habib Kairouz Director March 29, 2001 ______________________________________ Habib Kairouz /s/ A. K. McLanahan Director March 29, 2001 ______________________________________ A. K. McLanahan /s/ Townes G. Pressler Director March 29, 2001 ______________________________________ Townes G. Pressler
64 EX-10.19 2 0002.txt SEPARATION AGREEMENT-ROBERT BENSH EXHIBIT 10.19 SEPARATION AGREEMENT It is hereby agreed by and between ROBERT J. BENSH ("Employee") and BELLWETHER EXPLORATION COMPANY ("Bellwether"), that Employee has voluntarily resigned from his position as Senior Vice President - Finance effective January 1, 2001; provided, however, Employee shall remain an employee of Bellwether until his resignation of employment becomes effective on or before June 1, 2001 (hereinafter "Separation Date"), and that in order to resolve amicably all matters concerning his employment and release, Employee and Bellwether, in consideration of their mutual promises and other consideration itemized below, hereafter enter into the following agreements: 1. Nothing stated in this Agreement, or stated or done in connection herewith, shall constitute or indicate in any way any wrongdoing of any kind either by Employee or Bellwether. 2. Bellwether and Employee are parties to that certain Employment Agreement entered into effective as of June 1, 2000 ("Employment Agreement"). Bellwether agrees that upon execution by Employee and receipt by its representative of this Agreement and the Mutual Release appended as EXHIBIT A, the Employment Agreement is terminated pursuant to Section 5(e) of the Employment Agreement and the Employee shall not be entitled to any further compensation other than any unpaid Salary and benefits accrued through the date of termination; provided, however, Employee shall receive the following: (a) Current salary and benefits for Employee for a ninety (90) day period subsequent to the date of this Agreement. Such salary payment shall be made to the personal bank account of Robert J. Bensh; (b) Salary and benefits for Employee's assistant, Dana Dupriest, ("Assistant") for a ninety (90) day period; (c) Use of the following until June 1, 2001: (i) office space for Employee and Assistant at the Company's Houston, Texas offices, (ii) furniture, (iii) telephone service, (iv) computer equipment and (v) necessary office supplies; (d) All of Employee's Company stock options shall immediately vest as of the date hereof and Employee shall have the right to exercise said stock option on or before the close of business on June 30, 2002; (e) One-half of the Houston Astro field box season tickets at Enron Field for the 2001 season only on the following basis: Odd-numbered games - Employee Even-numbered games - Bellwether Thereafter, the season tickets revert back to the Employee as previously stated in the Employee's original Employment Agreement entered into with the Company. 3. Effective June 1, 2001, Employee acknowledges that during the course of his employment, he has had access to certain trade secrets of Bellwether and that such trade secrets constitute valuable, highly confidential, special and unique property of Bellwether, which Employee agrees not to disclose. These "trade secrets" are maps, computer programs, engineering studies, geological studies, and files, records and documents relating thereto. Also, the "trade secrets" include lists of customers who utilize Bellwether's services, related customer information and the internal financial statements and related information of Bellwether. However, such customer lists do not include customers which Employee knew before he was employed by Bellwether; neither do such customer lists include customers which could readily be identified by someone outside the employ of Bellwether. These "trade secrets" shall not include any information readily discernable from trade or general circulation publications or otherwise existing or available in public domain. 4. Effective June 1, 2001, Employees of Bellwether shall refrain from making any derogatory or disparaging remarks to any third party against Employee with respect to his employment by Bellwether, his performance, his character, or any such matters. Further, employees of Bellwether shall refrain from discussions among themselves using any such derogatory or disparaging remarks. In compliance with the covenant, Bellwether's obligation shall be to make reasonable efforts to have its employees refrain from making the type or remarks described in this last paragraph. Management shall instruct any employees overheard to make such remarks to cease and desist. 5. Effective June 1, 2001, Employee shall refrain from making any derogatory or disparaging remarks regarding his employment by Bellwether, or Bellwether's services, management, or operations to any third party other than members of Employee's immediate family. 6. Effective June 1, 2001, Employee acknowledges that he has been given a period of up to twenty-one (21) days within which to consider this Agreement and the Mutual Release to be executed hereunder, and that these documents have been executed by him voluntarily prior to expiration of the 21-day period, with full knowledge of all relevant information and after ample opportunity to consult with legal counsel. Employee is hereby advised to consult with and represents that he has consulted with an attorney prior to entering into this Agreement and the Mutual Release to be executed hereunder. Employee and Bellwether further agree that Employee has a period of seven (7) days following his execution of this Agreement and the Mutual Release to be executed hereunder in which to revoke these documents by delivering to Bellwether's undersigned representative written notice of his revocation, and that this Agreement and the Mutual Release executed hereunder shall not become effective or enforceable until such revocation period has expired. 7. Effective June 1, 2001, Bellwether and Employee agree that they will not disclose to any other person or entity and will keep confidential the fact of the existence of this Agreement, and all other facts or information of every kind concerning this Agreement. Provided, however, that Employee may disclose the existence of this Agreement or information 2 therein to his family, his attorney(s) or to his financial advisors or tax preparer or to the government for tax purposes, or as otherwise required by law. 8. This Agreement shall be binding on and inure to the benefit of Employee and Bellwether as well as all of their heirs, executors, administrators, officers, directors, employees, stockholders, successors and assigns, and all subsidiaries, affiliates and representatives of any of the foregoing entities. 9. Bellwether and Employee agree that this Agreement and the Mutual Release shall be construed under the laws of Texas and, if necessary, litigated in Houston, Texas. 10. This Agreement contains the entire agreement of the parties in complete satisfaction of all claims Employee or Bellwether may have against each other as of the date of execution of this Agreement, including all accrued costs and fees, if any. This Agreement may be executed in one or more counterparts, all of which together shall constitute a single instrument. IN WITNESS HEREOF, the parties to this Agreement have executed this instrument on the dates set forth below. EMPLOYEE: Date: ------------------------------- -------------------------------- Robert J. Bensh BELLWETHER EXPLORATION COMPANY Date: By: ------------------------------- -------------------------------- Douglas G. Manner, President 3 EX-10.20 3 0003.txt EMPLOYMENT CONTRACT-KENT WILLIAMSON EXHIBIT 10.20 EMPLOYMENT AGREEMENT This Employment Agreement (this "Agreement") entered into effective as of January 15, 2001 (except as to the provisions of paragraph 5(g)(ii) hereof which shall be effective as of December 7, 2000), by and between Kent Alan Williamson (the "Executive"), and Bellwether Exploration Company, a Delaware corporation having its principal place of business at 1331 Lamar, Suite 1455, Houston, Texas 77010-3039 (the "Company"); W I T N E S S E T H: WHEREAS, The Company wishes to employ the Executive as the Senior Vice President, Operations and to perform services incident to such position for the Company, and the Executive wishes to be so employed by the Company, all upon the terms and conditions hereinafter set forth: NOW THEREFORE, in consideration of the premises and mutual covenants and obligations herein set forth and for other good and valuable consideration, the receipt, sufficiency and adequacy of which is hereby acknowledged, accepted and agreed to, the parties hereto, intending to be legally bound, hereby agree as follows: 1. EMPLOYMENT AND TERM. The Company hereby employs the Executive to serve as the Senior Vice President, Operations of the Company. The term of this Agreement (the "Term of this Agreement") shall be effective as of the date first above written and shall terminate thirty-six (36) months from the date hereof (the "Termination Date"), unless earlier terminated by either party hereto in accordance with the provisions of Section 5 hereof. During the term of this Agreement, the terms of employment shall be as set forth herein unless modified by the Executive and the Company in accordance with the provisions of Section 11 hereof. The Executive hereby agrees to accept such employment and to perform the services specified herein, all upon the terms and conditions hereinafter set forth. 2. POSITION AND RESPONSIBILITIES. The Executive shall serve as the Senior Vice President, Operations of the Company and shall report to, and be subject to the general direction of the President and Chief Executive Officer of the Company. The Executive shall have other obligations, duties, authority and power to do all acts and things as are customarily done by a person holding the same or equivalent position or performing duties similar to those to be performed by executives in corporations of similar size to the Company and shall perform such managerial duties and responsibilities for the Company as may reasonably be assigned to him by the President and Chief Executive Officer of the Company. Unless otherwise agreed to by the Executive, the Executive shall be based at the Company's principal executive offices located in the greater Houston, Texas metropolitan area. 3. EXTENT OF SERVICE. The Executive shall devote his full business time and attention to the business of the Company. 4. COMPENSATION. (a) In consideration of the services to be rendered by the Executive to the Company, the Company will pay the Executive a salary ("Salary") of $200,000 per year during the Term of this Agreement. Such Salary will be payable in conformity with the Company's prevailing practice for executives' compensation as such practice shall be established or modified from time to time. Salary payments shall be subject to all applicable federal and state withholding, payroll and other taxes. From time to time during the Term of this Agreement, the amount of the Executive's Salary may be increased by, and at the sole discretion of, the Compensation Committee of the Company's Board of Directors, which shall review the Executive's Salary no less regularly than annually. (b) The Company shall grant the Executive an option to purchase 200,000 shares of common stock of the Company at an exercise price per share price of $6.57, which is equal to the average of the closing price of such common stock for the thirty (30) business days preceding the date of this Agreement ("Option"). Such Option shall vest 33.4% on the execution date of this Agreement and the remainder in two equal amounts on each of the first and second anniversary dates of this Agreement. The term of the Option shall be ten years from the date of grant subject to the provisions of paragraph 5(f)(i) hereof. (c) Any annual cash bonus paid to the Executive shall be based on performance and be at the sole discretion of the Compensation Committee of the Company's Board of Directors; provided, however, in the event such cash bonus shall be paid to the Executive, it shall be no less than 50% of Executive's then existing current salary. (d) During the term of this Agreement, the Company shall pay or reimburse the Executive for all reasonable out-of-pocket expenses for travel, meals, hotel accommodations, entertainment and the like incurred by him in connection with the business of the Company upon submission by him of an appropriate statement documenting such expenses as required by the Internal Revenue Code of 1986, as amended (the "Code"). (e) The Executive shall be entitled to four (4) weeks of paid vacation during each calendar year during the term of this Agreement. Vacation shall accrue on the first day of each calendar year. The Company shall not pay the Executive for any accrued but unused portion of vacation and any such unused portion of vacation shall not be carried forward to the next year. (f) During the term of this Agreement, the Executive shall be entitled to participate in and to receive all rights and benefits under any life, disability, medical and dental, health and accident and profit sharing or deferred compensation plans and such other plan or plans as may be implemented by the Company during the term of this Agreement. The Executive shall also be entitled to participate in and to receive all rights and benefits under any plan or program adopted by the Company for any other or group of other executive employees of the Company, including without limitation, the rights and benefits under the directors' and 2 officers' liability insurance currently in place under the Company's insurance program for the directors and officers of the Company. (g) During the term of this agreement, the Executive shall be entitled to receive a car allowance of $500.00 per month and one parking space shall be provided to the Executive by the Company. (h) The Company shall pay one club initiation fee of up to $25,000.00 and the base monthly dues applicable thereto, not to exceed $250.00 per month. 5. TERMINATION. (a) Termination by Company; Discharge for Cause. The Company shall be entitled to terminate this Agreement and the Executive's employment with the Company at any time and for whatever reason; or at any time for "Cause" (as defined below) by written notice to the Executive. Termination of the Executive's employment by the Company shall constitute a termination for "Cause" if such termination is for one or more of the following reasons: (i) the willful failure or refusal of the Executive to render services to the Company in accordance with his obligations under this Agreement, including, without limitation, the willful failure or refusal of the Executive to comply with the work rules, policies, procedures, and directives as established by the Board of Directors and consistent with this Agreement; such failure or refusal to be uncured and continuing for a period of not less than fifteen (15) days after notice outlining the situation is given by the Company to the Executive; (ii) the commission by the Executive of an act of fraud or embezzlement; (iii) the commission by the Executive of any other action with the intent to injure the Company; (iv) the Executive having been convicted of a felony or a crime involving moral turpitude; (v) the Executive having misappropriate the property of the Company; (vi) the Executive having engaged in personal misconduct which materially injures the Company; or (vii) the Executive having willfully violated any law or regulation relating to the business of the company which results in material injury to the Company. In the event of the Executive's termination by the Company for Cause hereunder, the Executive shall be entitled to no severance or other termination benefits except for any unpaid Salary accrued through the date of termination. A termination of this Agreement by the Company without Cause pursuant to this Section 5(a) shall entitle the Executive to the Severance Payment and other benefits specified in Section 5(f) hereof. (b) Death. If the Executive dies during the term of this Agreement and while in the employ of the Company, this Agreement shall automatically terminate and the Company shall have no further obligation to the Executive or his estate except that the Company shall pay to the Executive's estate that portion of his Salary and benefits accrued through the date of death. All such payments to the Executive's estate shall be made in the same manner and at the same time as the Executive's Salary. (c) Disability. If during the term of this Agreement, the Executive shall be prevented from performing his duties hereunder for a period of 60 days by reason of disability, 3 then the Company, on 30 days' prior notice to the Executive, may terminate this Agreement. For purposes of this Agreement, the Executive shall be deemed to have become disabled when the Board of Directors of the Company, upon verification by a physician designated by the Company, shall have determined that the Executive has become physically or mentally unable (excluding infrequent and temporary absences due to ordinary illness) to perform the essential functions of his duties under this Agreement with reasonable accommodation. In the event of a termination pursuant to this paragraph (c), the Company shall be relieved of all its obligations under this Agreement, except that the Company shall pay to the Executive or his estate in the event of his subsequent death, that portion of the Executive's Salary and benefits accrued through the date of such termination. All such payments to the Executive or his estate shall be made in the same manner and at the same time as his Salary would have been paid to him had he not become disabled. (d) Termination for Good Reason. The Executive shall be entitled to terminate this Agreement and his employment with the Company at any time upon thirty (30) days written notice to the Company for "Good Reason" (as defined below). The Executive's termination of employment shall be for "Good Reason" if such termination is a result of any of the following events: (i) The Executive is assigned any responsibilities or duties materially inconsistent with his position, duties, responsibilities and status with the Company as in effect at the date of this Agreement or as may be assigned to the Executive pursuant to Section 2 hereof; or his title or offices as in effect at the date of this Agreement or as the Executive may be appointed or elected to in accordance with Section 2 are changed; or the Executive is required to report to or be directed by any person other than the President and Chief Executive Officer of the Company; (ii) there is a reduction in the Salary (as such Salary shall have been increased from time to time) payable to the Executive pursuant to Section 4(a) hereof; (iii) failure by the Company or any successor to the Company or its assets to continue to provide to the Executive any material benefit, bonus, profit sharing, incentive, remuneration or compensation plan, stock ownership or purchase plan, stock option plan, life insurance, disability plan, pension plan or retirement plan in which the Executive was entitled to participate in as at the date of this Agreement or subsequent thereto, or the taking by the Company of any action that materially and adversely affects the Executive's participation in or materially reduces his rights or benefits under or pursuant to any such plan or the failure by the Company to increase or improve such rights or benefits on a basis consistent with practices in effect prior to the date of this Agreement or with practices implemented and subsequent to the date of this Agreement with respect to the executive employees of the Company generally, which ever is more favorable to the Executive, but excluding such action that is required by law; (iv) without Executive's consent, the Company requires the executive to relocate to any city or community other than one within a fifty (50) mile radius of the greater 4 Houston, Texas metropolitan area, except for required travel on the Company's business to an extent substantially consistent with the Executive's business obligations under this Agreement; or (v) there is any material breach by the Company of any provision of this Agreement. Upon the Executive's termination of this Agreement for Good Reason, the Executive shall be entitled to the Severance Payment and other benefits specified in Section 5(f) hereof. (e) Voluntary Termination. Notwithstanding anything to the contrary herein, the Executive shall be entitled to voluntarily terminate this Agreement and his employment with the Company at his pleasure upon sixty (60) days written notice to such effect. In such event, the Executive shall not be entitled to any further compensation other than any unpaid Salary and benefits accrued through the date of termination. At the Company's option, the Company may pay to the Executive the salary and benefits that the Executive would have received during such sixty (60) day period in lieu of requiring the Executive to remain in the employment of the Company for such sixty (60) day period. (f) Termination Benefits Upon Involuntary Termination or Termination for Good Reason. In the event that (i) the Company terminates this Agreement and the Executive's employment with the Company for any reason other than for Cause (as defined in Section 5(a) hereof) or the death or disability (as defined in Sections 5(b) and 5(c) hereof) of the Executive, or (ii) the Executive terminates this Agreement and his employment with the Company for Good Reason (as set forth in Section 5(d) hereof), then the Company shall pay the Executive, within thirty (30) days after the date of termination, an amount (the "Severance Payment") equal to (x) two (2) times the Executive's highest annual Salary in existence at any time during the last two (2) years of employment immediately preceding the date of termination, and (y) two (2) times the highest annual bonus paid to the Executive during such two-year period, minus applicable withholding and authorized salary reductions (the "Severance Payment"). In addition, following other such termination, the Executive shall be entitled to the following benefits (collectively, the "Additional Benefits"); (i) immediate vesting of any of the Executive's outstanding options to purchase securities of the Company which were not vested by their own terms on the date of termination and the extension of the Executive's right to exercise all the Executive's options to purchase securities of the Company for a period equal to the lesser of (A) one (1) year following the date of termination or (B) the remaining term of the applicable option; (ii) continued coverage, at the Executive's cost, under the Company's group health plan for the applicable coverage period under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended ("COBRA") but only if Executive elects such COBRA continuation in accordance with the time limits and applicable COBRA regulations; and 5 (iii) an amount, in cash, equal to the sum of (A) any unreimbursed expenses incurred by the Executive in the performance of his duties hereunder through the date of termination, plus (B) any accrued and unused vacation time or other unpaid benefits as of the date of termination. The parties agree that, because there can be no exact measure of the damages which would occur to the Executive as a result of termination of employment, such payments contemplated in this Section 5(f) shall be deemed to constitute liquidated damages and not a penalty and the Company agrees that the Executive shall not be required to mitigate his damages. The termination compensation in this Section 5(f) shall be paid only if the Executive executes a termination agreement releasing all legally waivable claims arising from the Executive's employment. (g) Termination and Benefits upon a Change in Control. (i) In the event of a Change in Control, as defined in this Section 5(g), then in lieu of the Severance Payment contained in Section 5(f) hereof, if the Executive is terminated without Cause or the Executive terminates his employment for Good Reason within the twelve (12) month period immediately following a Change in Control the Company shall pay to the Executive a lump sum amount equal to: (x) two (2) times the Executive's highest annual salary paid during the last two (2) years immediately preceding the date of termination, and (y) two (2) times the highest annual bonus paid to the Executive while employed by the Company, provided, however, in the event of a Change of Control prior to the receipt by Executive of a bonus, a bonus of $100,000.00 shall be imputed for the purposes of computing the Payment as defined in this paragraph, minus applicable withholding and authorized salary reductions (the "Payment"). In the event that the excise tax relating to "parachute payments" under Section 280G of the Code applies to the Payment, then the Company shall pay the Executive an additional payment in an amount such that, after payment of federal income taxes (but not the excise tax) on such additional payment, the Executive retains an amount equal to the excise tax originally imposed on the Payment. The Executive also is entitled to receive the Additional Benefits. "Change of Control" means or shall be deemed to have occurred if and when: (i) any "person" or "group" (as such terms are used in Section 13(d) and 14(d) of the Exchange Act) is or becomes the "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 50% of the total voting power of the outstanding voting stock of the Company; (ii) the Company is merged with or into or consolidated with another Person and, immediately after giving effect to the merger or consolidation, (a) less than 50% of the total voting power of the outstanding voting stock of the surviving or resulting Person is then "beneficially owned" (within the meaning of Rule 13d-3 under the Exchange Act) in the aggregate by the stockholders of the Company immediately prior to such merger or consolidation, and (b) any "person" or "group" (as defined in Section 13(d)(3) or 14(d)(2) of the Exchange Act) has become the direct or indirect "beneficial owner" (as defined in Rule 13d-3 under the Exchange Act) of more than 50% of the total voting power of the voting stock of the surviving or resulting Person; (iii) the Company sells, assigns, conveys, transfers, leases or 6 otherwise disposes of all or substantially all of the Company assets (either in one transaction or a series of related transactions); or (iv) the liquidation or dissolution of the Company. (ii) Notwithstanding the foregoing, in the event of a Change of Control between December 7, 2000 and January 15, 2001, the Company and Executive shall pay to the Executive a lump sum amount of $600,000.00 upon the date of the Change of Control. (h) Survival. Notwithstanding the termination of this Agreement under this Section 5, the provisions of Sections 7 and 8 of this Agreement, and all other provisions hereof which by their terms are to be performed following the termination hereof shall survive such termination and be continuing obligations. 6. CONSENT AND WAIVER BY THIRD PARTIES. The Executive hereby represents and warrants that he has obtained all necessary waivers and/or consents from third parties as to enable him to accept employment with the Company on the terms and conditions set forth herein and to execute and perform this Agreement without being in conflict with any other agreement, obligations or understanding with any such third party. 7. CONFIDENTIAL INFORMATION. The Executive acknowledges that in the course of his employment with the Company, he has received and will receive access to confidential information of a special and unique value concerning the Company and its business, including, without limitation, trade secrets, know- how, lists of customers, employee records, books and records relating to operations, costs or providing service and equipment, operating and maintenance costs, pricing criteria and other confidential information and knowledge concerning the business of the Company and its affiliates (hereinafter collectively referred to as "information") which the Company desires to protect. The Executive acknowledges that such information is confidential and the protection of such confidential information against unauthorized use or disclosure is of critical importance to the Company. The Executive agrees that he will not reveal such information to any one outside the Company. The Executive further agrees that during the term of this Agreement and thereafter he will not use or disclose such information. Upon termination of his employment hereunder, the Executive shall surrender to the Company all papers, documents, writings and other property produced by him or coming into his possession by or through his employment hereunder and relating to the information referred to in this Section 7, and the Executive agrees that all such materials will at all times remain the property of the Company. The obligation of confidentiality, non-use and non-disclosure of know-how set forth in this Section 7 shall not extend to know-how (i) which was in the public domain prior to disclosure by the disclosing party, (ii) which comes into the public domain other than through a breach of this Agreement, (iii) which is disclosed to the Executive after the termination of this Agreement by a third party having legitimate possession thereof and the unrestricted right to make such disclosure, or (iv) which is necessarily disclosed in the course of the Executive's performance of his duties to the Company as contemplated in this Agreement. The agreements in this Section 7 shall survive the termination of this Agreement. 7 8. NO SOLICITATION. To support the agreements contained in Section 7 hereof, from the date hereof and for a period twelve (12) months after the Executive's employment with the Company is terminated for any reason, the Executive shall not, either directly or indirectly, through any person, firm, association or corporation with which the Executive is now or may hereafter become associated, (i) hire, employ, solicit or engage any then current employee of the Company or its affiliates, or (ii) use in any competition, solicitation or marketing effort any information as to which the Executive has a duty of confidential treatment under paragraph 7 above. 9. NOTICES. All notices, requests, consents and other communications under this Agreement shall be in writing and shall be deemed to have been delivered on the date personally delivered or on the date mailed, postage prepaid, by certified mail, return receipt requested, or telegraphed and confirmed if addressed to the respective parties as follows: If to the Executive: Kent Alan Williamson c/o Bellwether Exploration Company 1331 Lamar, Suite 1455 Houston, Texas 77010-3039 If to the Company: Bellwether Exploration Company 1331 Lamar, Suite 1455 Houston, Texas 77010-3039 Attn: Chairman, Compensation Committee Either party hereto may designate a different address by providing written notice of such new address to the other party hereto. 10. SPECIFIC PERFORMANCE. The Executive acknowledges that a remedy at law for any breach or attempted breach of Section 7 or 8 of this Agreement will be inadequate, agrees that the Company shall be entitled to specific performance and injunctive and other equitable relief in case of any such a breach or attempted breach, and further agrees to waive any requirement of the securing or posting of any bond in connection with the obtaining of any such injunctive or any other equitable relief. 11. WAIVERS AND MODIFICATIONS. This Agreement may be modified, and the rights and remedies of any provision hereof may be waived, only in accordance with this Section 11. No modification or waiver by the Company shall be effective without the consent of at least a majority of the Compensation Committee of the Board of Directors then in office at the time of such modification or waiver. No waiver by either party of any breach by the other or any provision hereof shall be deemed to be a waiver of any later or other breach thereof or as a waiver of any other provision of this Agreement. This Agreement sets forth all the terms of the understandings between the parties with reference to the subject matter set forth herein and may not be waived, changed, discharged or terminated orally or by any course of dealing between the 8 parties, but only by an instrument in writing signed by the party against whom any waiver, change, discharge or termination is sought. 12. GOVERNING LAW. This Agreement shall be construed in accordance with the laws of the State of Texas. 13. SEVERABILITY. In case of one or more of the provisions contained in this Agreement for any reason shall be held to be invalid, illegal or unenforceable in any respect, such invalidity, illegality or unenforceability shall not affect any other provision of this Agreement, but this Agreement shall be construed as if such invalid, illegal or unenforceable provisions had never contained herein. 14. ARBITRATION. In the event that a dispute or controversy should arise between the Executive and the Company as to the meaning or application of any provision, term or condition of this Agreement, such dispute or controversy shall be settled by binding arbitration in Houston, Texas and for said purpose each of the parties hereto hereby expressly consents to such arbitration in such place. Such arbitration shall be conducted in accordance with the existing rules and regulations of the American Arbitration Association governing commercial transactions. The expense of the arbitrator shall be borne by the Company. IN WITNESS WHEREOF, each of the parties hereto has executed this Agreement as of the date and year first above written. COMPANY: BELLWETHER EXPLORATION COMPANY By: ------------------------------------------ Douglas G. Manner President and Chief Executive Officer EXECUTIVE: ------------------------------------------ Kent Alan Williamson 9 EX-21.1 4 0004.txt SUBSIDIARIES OF BELLWETHER EXHIBIT 21.1 Subsidiaries of Bellwether Exploration Company
State of Incorporation ---------------------- Black Hawk Oil Company Delaware Bellwether International Incorporated Delaware Bellwether Cayman, Inc. Delaware Petrobell, Inc. Delaware Pan American Energy Finance Corp Delaware
EX-23.2 5 0005.txt CONSENT OF RYDER SCOTT COMPANY [RYDER SCOTT LETTER HEAD] CONSENT OF INDEPENDENT PETROLEUM ENGINEERS As independent oil and gas consultants, Ryder Scott Company, L.P., hereby consents to the use of our reserve reports dated as of December 31, 1998, December 31, 1999, and December 31, 2000 and to all references to our firm included in or made a part of the Bellwether Exploration Company's Form 10-K to be filed with the Securities and Exchange Commission on or about March 29, 2001. /s/ RYDER SCOTT COMPANY, L.P. ----------------------------- RYDER SCOTT COMPANY, L.P. March 29, 2001 Houston, Texas EX-23.3 6 0006.txt CONSENT OF KPMG LLP EXHIBIT 23.3 The Board of Directors Bellwether Exploration Company: We consent to incorporation by reference in the registration statement (No. 333- 57827) on Form S-8 of Bellwether Exploration Company of our report dated March 9, 2001, relating to the consolidated balance sheets of Bellwether Exploration Company and subsidiaries as of December 31, 2000, and 1999, and the related consolidated statements of operations, changes in stockeholders' equity and cash flows for each of the years in the three-year period ended December 31, 2000, and all related schedules, which report appears in the December 31, 2000, annual report on Form 10-K of Bellwether Exploration Company. KPMG LLP Houston, Texas March 30, 2001 -----END PRIVACY-ENHANCED MESSAGE-----