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 area of activity is southeastern New Mexico, west Texas, the Texas/Louisiana Gulf Coast, both on and offshore, Latin America and the Ukraine. At December 31, 1999, the Company's estimated net proved reserves, using constant prices which were in effect at such date, totaled 14.7 MMBbl of oil, 2.1 MMBbl of natural gas liquids ("NGL"), and 130 Bcf of natural gas for a total of 38.5 million barrels of oil equivalent ("MBOE"). On an equivalency basis, approximately 56% of the Company's estimated net proved reserves were natural gas and 79% were developed at such date. In addition, the Company has interests in natural gas processing plants in California and West Texas.
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").
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 ("New Credit Facility" or "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.
Subsequent to the Partnership Transactions, the Company identified for divestiture non-core properties including approximately 10% of the estimated net proved reserves attributable to the Partnership Transactions. These properties were primarily small working interests in geographically diverse locations, with generally lower operating margins and limited development potential. Such properties were sold in a series of transactions from May 1997 to December 1997 for aggregate consideration of $24 million. The net proceeds from these divestitures were used to repay indebtedness.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
In December 1998 Bellwether was the successful bidder for the Charapa field in Ecuador. With the successful bid, the Company was awarded with a contract for production and exploration of crude oil in the Charapa field. The contract provides the Company with approximately 50% 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 has committed to a $12 million work program over three years.
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 Energy Advisors Incorporated. ("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 95.45 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 (approximately 43% of the Carpatsky's equity), do not carry a preferential dividend and have majority voting rights over Carpatsky. In connection with this investment, Mr. J.P. Bryan, Chairman and Chief Executive Officer of Bellwether became the Chairman and CEO of Carpatsky and three Carpatsky directors retired and were replaced by three Bellwether appointees, giving Bellwether five of the new eight directorships of Carpatsky. Carpatsky conducts oil and gas exploration and production activities in the Republic of Ukraine.
Business Strategy
The Company is committed to providing outstanding performance in all categories of financial measurement in order to become a significant international exploration and production company. This vision is dictated by the following business strategy:
Acquire, Exploit and lastly, Explore. The Company believes that acquiring oil and gas reserves is the most effective way to increase shareholder value. Once a property has been acquired, the Company immediately employs and aggressive exploitation program to increase production, reduce operating costs and develop low risk exploration opportunities.
Emphasize Acquisition of International Properties with Significant Development Upside. The Company focuses on acquisition opportunities in the international arena in an effort to realize significant value in areas that other companies of Bellwether's size are not operating. The Company reviews acquisition opportunities spanning the globe, but focuses particularly in Latin America and Eastern Europe.
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 considers the Texas-Louisiana Gulf Coast, both on and offshore, Latin America and Eastern Europe to be its core areas. The Company may seek to establish additional core areas in the future which 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, whether operating, capital or overhead. In this regard the Company outsources certain non-strategic functions. Additionally, the Company will regularly review its property base
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
aggressively exploiting identified opportunities and divesting non-core or lower margin assets and redeploying capital to a higher use.
Concentrate on High Value Operated Properties. The Company will increase efficiency, establish greater control and enhance economic impact with respect to its activities through concentrating its holdings in a fewer number of higher value properties, a majority of which it will seek to operate. Achievement of this objective will be a principal targeting criteria in the execution of its acquisition and divestiture strategies. Toward this end the Company's exploration program will emphasize internal prospect generation as well as strategic relationships with prospect generators having demonstrated expertise within a particular play type or area of interest.
Be Technology Driven. The Company will seek to improve its success rates and reduce its finding and operating costs by employing the latest 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.
Use an Interdisciplinary Approach. The Company utilizes interdisciplinary teams comprised 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. The Company will target opportunities which offer multiple application of successful concepts and are on trend with and extensions of existing applications of such concepts.
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.
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 22%, 28% and 22% of fiscal year 1999, 1998 and transition period 1997 revenues, respectively. Sales to Valero Industrial Gas, L.P. accounted for 18.0% of fiscal 1997 revenues. Management of the Company does not believe that the loss of any single customer or contract would materially affect the Company's business. 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. While there is no 1999 production from Bellwether's Ecuadorian or Ukrainian assets, the Ecuador crude oil will be marketed by YPF and the Ukraine crude oil is sold on the spot market into the domestic market. 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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 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. As required by the Energy Policy Act of 1992, the FERC has revised its regulations governing the rates that may be charged by oil pipelines. The new rules, which were effective January 1, 1995, provide a simplified, generally applicable method of regulating such rates 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. 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 ("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
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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.
ITEM 2. PROPERTIES
Domestic Properties
The Company's domestic exploration, development and acquisition activities are focused in nine core areas: Central Gulf of Mexico; Western Gulf of Mexico; West Texas; South Texas; Northwest Texas; Texas Coast; Southwest Louisiana; Oregon; and New Mexico.
Central Gulf of Mexico - The primary fields in this area are East Cameron, Eugene Island, Ship Shoal, South Marsh Island, West Cameron and South Timbalier blocks in the Gulf of Mexico. All of the blocks are operated by others except East Cameron and Eugene Island 307 which are operated by the Company. The Central Gulf of Mexico core area represents approximately 15% of the Company's total present value of reserves discounted at 10% (NPV10%). The area is comprised of approximately 550 wells of which 163 are producing and have an average working interest of about 20%. The average reserve life is six and a half years.
Western Gulf of Mexico - The primary fields in this area are Cove, High Island Blocks A-334, A-552 and 71/88 and Matagorda Island Block 605 in the Gulf of Mexico. The Cove field and High Island Block A-552 are Company operated while the other fields are outside operated. The Western Gulf of Mexico core area represents approximately 9% of the Company's NPV10%. The area is comprised of approximately 35 wells of which 14 are producing and have an average working interest of about 40%. The average reserve life is six and a half years.
West Texas - The primary fields in this area are Waddell Ranch, Gomez, Happy and Brooks/Zan-Zan. All of the fields are outside operated, except the Happy field which the Company operates. The West Texas core area represents approximately 19% of the Company's NPV10%. The area is comprised of approximately 2,200 wells of which 1,400 are producing and have an average working interest of about 25%. The Waddell Ranch field is primarily under waterflood and represents 97% of total and producing wells in this core area. The average working interest for the Waddell Ranch field is about 10% and the field has a reserve life of 40 years. The average reserve life for all the fields in the West Texas core area thirty-five years.
South Texas - The primary fields in this area are Belle Pepper, La Rica and McAllen Ranch. The Company operates all the fields in this area except for the McAllen Ranch field. The South Texas core area represents approximately 1% of the Company's total present value of 10% reserves. The area is comprised of approximately 30 wells of which 27 are producing. The Belle Pepper and La Rica fields have 100% working interest and the McAllen Ranch field has an average working interest of about 20%. The average reserve life for the South Texas core area is ten years.
Northwest Texas - The primary fields in this area are Giddings, Rocky Creek, Fort Trinidad and Matterhorn. The Giddings and Matterhorn fields are Company operated while the other fields are outside operated. The Northwest Texas core area represents approximately 6% of the Company's NPV10%. The area is comprised of approximately 200 wells of which 160 are producing and have an average working interest of about 27%. The average reserve life is twenty years.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Texas Coast - The primary fields in this area are Porter's Creek, which is Company operated, and McFarlan, which is outside operated. The Texas Coast core area represents approximately 4% of the Company's NPV10%. The area is comprised of 18 wells of which 17 are producing and have an average working interest of about 50%. The average reserve life is thirteen years.
Southwest Louisiana - The primary fields in this area are Second Bayou, which is Company operated, and West Chalkley, which is outside operated. The Southwest Louisiana core area represents approximately 6% of the Company's NPV10%. The area is comprised of 11 wells of which 10 are producing and have an average working interest of about 12%. The average reserve life is nine years.
Oregon - The only field in this area is the Mist field which is outside operated and has a 50% working interest. The Oregon core area represents approximately 3% of the Company's NPV10%. The area is comprised of 32 wells of which 11 are producing. The average reserve life is fifteen years.
New Mexico - The primary fields in this area are Lusk, Turkey Track, Crow Flats, Burton Flats and Empire. Currently five wells in the Lusk and Turkey Track fields are operated by the Company and all other wells are outside operated. As more wells are drilled in this core area, the Company will increase its operated areas. The New Mexico core area represents approximately 6% of the Company's NPV10%. The area is comprised of approximately 240 wells of which 230 are producing and have an average working interest of about 38%. The average reserve life is thirty-two years.
California - The primary field in this area is Point Pedernales which is operated by Nuevo Energy. The California core area represents approximately 2% of the Company's NPV10%. The area is comprised of 22 wells of which 10 are producing and have an average working interest of about 20%. The average reserve life is nine years.
International Properties
Ecuador - In December 1998 Bellwether was the successful bidder for the Charapa field in Ecuador. Negotiations with the Ecuadorian government took place throughout 1999 with Bellwether officially taking over operations of the field in January of 2000. Bellwether has committed to a $12 million work program over a three year period. Ecuador represents 8% of the Company's NPV 10%. Beginning in 2000, one well will be producing with approximately a 50% interest.
Ukraine - Bellwether owns an interest in two projects in the Ukraine through its ownership of Carpatsky Petroleum Inc. Carpatsky is developing a natural gas project in the Rudovsko-Chernozovodsky ("RC") field in central Ukraine, and owns an interest in the Bitkov field in western Ukraine. The RC project includes the acquisition and documentation of ownership rights in the RC field sufficient to support financing for development of the field. In addition, Carpatsky is seeking western purchasers for the gas reserves in the field to reduce exposure to default in payment for reserves experienced when gas was sold to Ukrainian purchasers. Bellwether's interest in reserves in the Ukraine were not material to Bellwether on December 31, 1999.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Reserves
Estimated net proved oil and gas reserves at December 31, 1999 increased approximately 34% from December 31, 1998. This increase was primarily caused by the acquisition of properties in New Mexico and the Gulf of Mexico and increased oil and gas prices. The Company has not filed oil or gas reserve information with any foreign government or Federal authority or agency which contain reserves materially different than those set forth herein.
The following table sets forth certain information, as of December 31, 1999, which relates to fields which hold approximately 94% of the Company's proved oil and gas reserves:
* Such 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 revenue.
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 and 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 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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. 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, 1999. 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 acreage is domestic.
Gross Net --------- -------
Developed Acreage............... 515,493 94,661 Undeveloped Acreage............. 1,138,200 396,847 --------- ------- Total....................... 1,653,693 491,508 ========= =======
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 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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Productive Wells
The following table sets forth Bellwether's gross and net interests in productive oil and gas wells as of December 31, 1999. Productive wells are defined as producing wells and wells capable of production. All of the wells listed are domestic.
Gross Net ----- ---
Oil Wells................. 1,323 211 Gas Wells................. 813 160 ----- --- Total................. 2,136 371 ===== ===
Production
The Company's principal production volumes during the fiscal year ended December 31, 1999 were from the states of Louisiana, Texas, Oregon and Alabama, from federal waters in offshore California and from the Gulf of Mexico in federal and state waters.
Data relating to production volumes, average sales prices, average unit production costs and oil and gas reserve information appear in Note 12 of the Notes to Consolidated Financial Statements - Supplemental Information.
Drilling Activity and Present Activities
During the last three fiscal years and the transition period ended December 31, 1997, the Company's principal drilling activities occurred in the continental United States and offshore Texas, Louisiana and California in federal and state waters.
The following table sets forth the results of drilling activity for the last three fiscal years and the transition period. Gross wells, as it applies to wells in the following tables, refers 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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
The Company had 8 wells in progress as of December 31, 1999. Gas Plants
As of December 31, 1999 the Company owned interests in the following gas plants:
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. Oil prices were lower in 1998 than in previous years and hit historic lows during the first quarter of 1999, but recovered significantly by year end 1999. 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 have
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 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, without successful exploration, development or acquisition activities, the Company's revenues will decline rapidly. 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, to 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) exploration and exploitation potential, 3) future oil and natural gas prices, 4) operating costs, 5) potential environmental and other liabilities and 6) 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.
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, Alabama, offshore California, the Gulf of Mexico, Latin America and Ukraine there is no assurance that the Company will not pursue acquisitions or properties located in other geographic areas.
In connection with the Partnership Transactions, Bellwether assumed or otherwise became liable for all obligations with respect to operations of the properties acquired in such transactions, including environmental and operational liabilities, unknown liabilities, and liabilities arising prior to the closing date.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 flows 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. 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 lease in Ecuador in 1998. Contract negotiations with the Ecuadorian government were completed in late 1999 with operations beginning January 2000. In addition, on December 30, 1999, the Company acquired an interest in Carpatsky, which has operations in Ukraine. Ownership of property interests and production operations in Ecuador, Ukraine and in any other areas outside of the United States in which the Company may choose to do business, are subject to the various risks interest in 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 expropriations, nationalization, war, insurrection and other political risks, risks of increase in taxes and governmental policies governing operations of foreign-based companies
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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.
Carpatsky's activities are focused in the RC field, which has substantial gas reserves. Carpatsky is seeking to acquire and fully document its ownership interests in the RC field. Currently, Carpatsky operates under a joint activities agreement with a state majority owned oil company. The joint activities agreement gives Carpatsky the right to receive proceeds from a portion of the production from the field in exchange for payment of a portion of the costs. The portions of production received and costs paid vary depending on the amount paid by Carpatsky under the joint activities agreement. The joint activities agreement is not currently referred to in the RC field license granted by the government of the Ukraine. In addition, the current license covers only production from a pilot project designed to determine the productive boundaries of the field. Carpatsky is seeking to have the RC field license granted directly to it or to an entity in which it has an ownership interest, and to have the license changed to a development license. No assurances can be made that Carpatsky will be successful in these activities.
Administrative Services Agreement; Reliance on Torch
The Company currently has 24 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, land, legal and technical support (See Note 4 to the Consolidated Financial Statements). The Company believes that its relationship with Torch provides the Company with 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
Director, Mr. J. P. Bryan, was elected Chairman and Chief Executive Officer effective August 2, 1999. Mr. Bryan is Senior Managing Director of and a holder of common stock of the parent corporation of Torch. Mr. Bryan has limited involvement in the day to day operations of Torch.
Torch also renders administrative 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 Master Services Agreement provides for procedures to reconcile conflicts of interest between these other companies and the Company, 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 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
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
prices and expenditures for future development and exploitation activities, and 3) of 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 gas equivalent basis, oil was converted to gas 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 peculiar 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 liability for: 1) personal injuries, 2) property damage, 3) oil spills, 4) discharge of hazardous materials, 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 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 may lose substantial portions of its properties in the event of certain environmental damages.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 require: 1) 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.
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. 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. The Company recently 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
PART II
ITEM 5.
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 822 stockholders of record as of March 10, 2000. 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.
Treasury Stock Repurchases
In September 1998, the Board of Directors of the Company authorized the open market repurchase of up to $5 million of the Company's common stock during 1998, at times and prices deemed attractive by management. As of December 31, 1999, the Company had repurchased 311,000 shares of common stock in open market transactions, at an average purchase price of $6.13 per share.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
ITEM 6.
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).
(1) Includes operations from the Partnership Transactions beginning April 1, 1997. (2) Reflects operations from Odyssey and Hampton mergers beginning August 1994 and February 1995, respectively.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
ITEM 7.
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. Prior to April 1997, the Company had grown and diversified its operations primarily through acquisitions and subsequent development of the acquired properties. Subsequent to April 1997 the Company has employed a more balanced growth strategy combining strategic acquisitions of producing properties with technology driven exploration and development 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 exploitation 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 ("Partnership Transactions"). 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 "Offerings") and borrowings under a new credit facility ("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. This resulted in a six-month transition period of July 1, 1997 through December 31, 1997 ("transition period").
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. 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. No such write down was required for the year ended December 31, 1999.
The Company periodically uses derivative financial instruments to manage oil and gas price risk. Settlements of gains and losses on price swap contracts are generally based upon the difference between the contract price and the average closing NYMEX or other floating index price and are reported as a component of oil and gas revenue during the period in which the underlying commodity is produced. Gains or losses attributable to the termination of swap contracts are deferred and recognized in revenue when the hedged oil and gas is sold.
Financing Activities
The Company's outstanding indebtedness totals $130.0 million at December 31, 1999; $100 million is attributable to 10 7/8% Senior Subordinated Notes due in 2007 while $30.0 million is outstanding under a senior revolving unsecured credit facility with an ultimate maturity date of November 2003.
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 current borrowing base of $55.0 million, and a maturity date of November 5, 2003.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 1/2 of 1% plus the Federal Funds Rate. For LIBOR borrowings, the interest rate will vary from LIBOR plus 1.0% to LIBOR plus 1.75% based upon the borrowing base usage. In connection with the acquisition of oil and gas properties, $30 million was drawn under this facility. As of December 31, 1999, $30.0 million was outstanding under the Senior Credit Facility. The Senior Credit Facility contains various covenants including certain required financial measurements for current ratio, consolidated tangible net worth and interest coverage ratio. In addition, the Senior Credit Facility includes certain limitations on restricted payments, dividends, incurrence of additional funded indebtedness and asset sales.
In October 1996, the Company entered into a syndicated credit facility in an amount up to $50.0 million with an initial borrowing base of $27.0 million, to be re-determined semi-annually. This credit facility was unsecured and was retired in April 1997. In February 1995, the Company entered into a credit facility with a commercial bank providing an initial borrowing base of $29.8 million. The borrowings under the credit facility were secured by the Company's interest in oil and gas properties, a gathering system and two gas plants. The Credit Facility was retired in October 1996.
In April 1997, the Company issued $100.0 million of 10 7/8% senior subordinated notes ("Notes") that mature April 1, 2007 for net proceeds of $97.0 million. Interest on the Notes is payable semi-annually on April 1 and October 1 commencing on October 1, 1997. The Notes contain certain covenants, including limitations on: 1) the incurrence of debt, 2) on other senior subordinated indebtedness, 3) on restricted payments and 4) on liens as well as restrictions 5) on the disposition of proceeds of asset sales and 6) on 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 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. 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.
In April 1997, the Company issued 4.4 million common shares in a public offering. The net proceeds of the offering were $34.1 million.
Liquidity and Capital Resources
The Company's principal sources of capital for the last three years and for the six month transition period have been the sale of Notes, borrowings under bank credit facilities, the public sale of common stock and cash flow from operations. The Company sold $100 million in Notes in fiscal 1997. Borrowings from banks were 30.0 million, $4.9 million, $1.5 million and $57.3 million for the fiscal years 1999 and 1998, the transition period 1997 and fiscal year ended June 30, 1997 respectively. The Company issued 4.4 million shares of common stock in a public offering in April 1997 for net proceeds of $34.1 million. Cash flow from operations before change in assets and liabilities totaled $30.8 million, $30.4 million, $21.8 million and $23.3 million for the fiscal years 1999 and 1998, the transition period 1997 and fiscal year 1997, respectively. Cash flow from operations before changes in working capital for the fiscal year 1998 was adversely impacted by a 22% reduction in the average price received for the Company's oil and gas production as compared to the average price received during the transition period 1997. In a series of transactions from May through December 1997, the Company divested non-core assets representing approximately 10% of its estimated net proved reserves for $24.3 million. Also, the Company divested additional non-core assets in September and October 1999 for approximately $4.9 million.
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 $25.9 million, $10.3 million, $5.5 million and $140 million for the fiscal years 1999 and 1998, the transition period 1997 and fiscal 1997, respectively. The Company's expenditures for exploration and development of its oil and gas properties totaled $31.3 million, $30.6 million, $13.7 million and $15.6 million for the fiscal years 1999 and 1998, the transition period ended December 31, 1997 and the fiscal year ended June 30, 1997, respectively.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Outlook
The Company has adopted a $55.2 million capital budget for the year ending December 31, 2000 primarily for development and exploratory drilling activities. The Company believes its working capital and net cash flows provided by operating activities are sufficient to meet these capital commitments. Additionally, the Company currently has a $55.0 million borrowing base under its Senior Credit Facility with $30.0 million outstanding borrowings at December 31, 1999. The Company is continuously reviewing acquisition opportunities and expects to conclude one or more acquisitions during 2000. Acquisitions are not included in the capital budget and will be funded through additional borrowings and/or the issuance of securities.
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 of 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.
Year 2000 Issues
The Year 2000 problem ("Y2k") refers to the inability of computer and other information technology systems to properly process date and time information. The problem was caused, in part, by the outdated programming practice of using two digits rather than four to represent the year in a date. The consequence of the Y2k problem is that information technology and embedded processing systems are at risk of malfunction, particularly during the transition between 1999 to 2000.
The estimated total costs for Y2k readiness were nominal. In addition, there have been no material capital expenditures for Y2k and there is not anticipated to be material capital expenditures because most major critical field operations do not have date sensitive equipment. The Company has experienced no material Y2k failures.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Results of Operations
For comparability with annual periods, amounts discussed in this section regarding the six month transition period 1997 have been annualized. These amounts may not be indicative of twelve month's operating results. The table below recaps the major components of financial and operating performance to be discussed (amounts in thousands):
(1) Annualized amounts were computed by multiplying Transition Period 1997 components by 2
(2) Average sales price is inclusive of the effect of natural gas and crude oil price hedges
(3) Exclusive of general and administrative expenses allocated to gas plants
(4) Exclusive of depreciation on gas plants
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Operations of the gas plant and the gathering system are summarized as follows:
Year Ended 1999 Compared to Year Ended 1998:
Net income for the year ended December 31, 1999 was $8.8 million or $.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 diluted. The loss in 1998 was due to a pre-tax $73.9 million impairment charge resulting from the Company's capitalized cost exceeding the discounted future net revenues on a after-tax basis of estimated proved oil and gas reserves.
Oil and gas revenues were $67.9 million for the year ended 1999, as compared to $73.2 million of oil and gas revenues for the year ended 1998. While oil and gas volumes were down approximately 10% in 1999 compared to 1998, oil prices were 10% higher in 1999. Oil prices increased from $11.64 per barrel in 1998 to $12.77 in 1999. Gas prices remained flat at $2.18 for 1999 and 1998. 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.
Gas plant net revenues were $1.5 million in 1999, as compared to $1.2 million in 1998. Contributing to this increase were increases in plant liquid prices of 27% over the prior year.
Production expenses for fiscal 1999 totaled $21.5 million, as compared to $25.4 million in fiscal 1998. On an MCF basis, production expenses were $.68 per MCF in 1999 as compared to $.72 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, but high lease operating and workover expenses. On an equivalent MCF basis production expenses decreased from $.72 per equivalent MCF in 1998 to $.68 per equivalent MCF in 1999.
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 mentioned above.
General and administrative expenses decreased in 1999 to $7.8 million from $8.5 million in 1998. A decrease in outsourcing costs from $4 million to $2.9 million was the major contribution to this decline. Until October 2000, 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 an equivalent MCF basis increased from $.24 per equivalent MCF in 1998 to $.25 per equivalent MCF 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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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.
Year Ended 1998 Compared with Annualized Transition Period 1997:
The year ended 1998 reflects a loss of $77.3 million as compared to net income of $7.1 million for the annualized transition period 1997. The loss in 1998 is directly attributable to oil and gas price declines of 31% and 20%, respectively, and the full cost ceiling impairment of $73.9 million. Such impairment resulted from the price declines as well as the downward revision in proved reserves.
Oil and gas revenues were $73.2 million for the year ended December 31, 1998, a decrease of 17% over the annualized transition period 1997. This decrease is primarily due to the decline in oil and gas prices mentioned above. Oil prices decreased from $16.52 per barrel in the annualized transition period 1997 to $11.64 in the year ended December 31, 1998. Gas prices decreased from $2.39 per Mcf in the annualized transition period 1997 to $2.18 per Mcf in the year ended December 31, 1998. The Company utilized various hedging transactions to manage a portion of the risks associated with natural gas and crude oil price volatility. As a result of these hedges, oil and gas revenues were increased by $3.6 million in the year ended December 31, 1998 and reduced by $1.6 million in the transition period 1997.
Gas plant revenues were $3.2 million in the year ended December 31, 1998, a decrease of 22% from the transition period 1997 gas plant revenues of $4.1 million. The decrease in average liquid prices of 30% is the primary reason gas plant revenues have declined. The average liquid price in the year ended 1998 was $10.19 per barrel while the annualized transition period 1997 average liquid price was $14.45 per barrel. Throughput volumes have remained steady at 14.3 MMcf per day in the year ended 1998 as compared to 14.9 MMcf per day in annualized transition period 1997. Plant shut-in days were less in the year ended 1998 with 8 days downtime in 1998 resulting from an accident in an adjacent plant and the tie-in of new equipment. Downtime in 1997 totaled 24 days (48 days annualized) for installation of an amine unit in September 1997 and repairs to the insulation in the incinerator. Gas plant expenses were $2.0 million in the year ended 1998 and $2.5 million in annualized transition period 1997.
Interest and other income increased to $1.3 million in the year ended 1998 from $1.2 million in annualized transition period 1997.
Production expenses for the year ended December 31, 1998 were $25.4 million, a decrease of 8% from the transition period amount. On an MCF equivalency basis, production expenses for the year decreased to $.72 per equivalent MCF versus $.79 per equivalent MCF in the transition period 1997.
Depreciation, depletion and amortization for the year ended December 31, 1998 increased 21% to $39.7 million. The increase is due to the increase in the depreciation, depletion and amortization rate per MCF to $1.10 per MCF. This represents a 21% increase over the annualized transition period 1997 rate of $.90 per MCF. The rate increase is primarily due to a downward revision to proved reserves of 26 BCFE or 12% of the reserve quantities at the beginning of the year. Weak oil and gas prices were the most significant contributor to the reserve revision. Production performance also contributed to the revision, but to a lesser extent as the weak prices resulted in a shortened economic life for certain of the Company's properties.
An impairment expense of $73.9 million was required in the year ended 1998 because the Company's capitalized costs (net of depreciation, depletion and amortization) exceeded the discounted future net reserves on an after-tax basis of estimated proved oil and gas reserves. The decline in oil and gas reserves and discounted future net revenues is due largely to depressed oil and gas prices.
General and administrative expenses increased from $7.5 million in annualized transition period 1997 to $8.5 million in the year ended December 31, 1998. The closing of the Company's Dallas exploration office in March 1998 resulted in $.3 million of increased general and administrative expenses and certain transition costs related to the change of the Company's fiscal year also increased such expenses by approximately $.4 million. On
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
an equivalent MCF basis, general and administrative cost increased to $.24 per MCF in fiscal 1998 as compared to $.21 per MCF in the transition period 1997.
The large impairment mentioned above resulted in an increase in the Company's tax valuation allowance for the benefit for the current period's net loss from operations.
Annualized interest expense decreased 2% to $11.7 million from $12.0 million in fiscal 1997.
Annualized Transition Period 1997 Compared with Fiscal 1997:
Net income for the annualized transition period 1997 was $7.1 million as compared to net income of $4.6 million in the fiscal year 1997. The primary reason for the increase is the full year's production attributable to the Partnership Transactions in the annualized transition period 1997. The fiscal 1997 period reflects only 3 months of such activity.
Oil and gas revenues were $88.3 million for the annualized transition period 1997, an increase of 126% over the fiscal year ended June 30, 1997. This increase is due to a full year of production from the properties acquired in the Partnership Transactions, which closed in the fourth quarter of fiscal 1997. Annualized production on an equivalent MCFE basis increased 124% to 35,034 equivalent MCF in the transition period compared to 15,676 equivalent MCF of production in fiscal 1997.
During the period, the volatility of oil and gas prices also directly impacted revenues. Most significantly, natural gas prices increased in the transition period 1997 to $2.55 per Mcf from $2.29 per Mcf in fiscal 1997. During the transition period 1997 and fiscal 1997, the Company utilized various hedging transactions to manage a portion of the risks associated with natural gas and crude oil price volatility. As a result of these hedges, oil and gas revenues were reduced by $1.6 million in the transition period 1997 and by $18,000 in fiscal 1997.
Gas plant revenues were $4.1 million in the annualized transition period 1997, a decrease of 39% from fiscal 1997 gas plant revenues. The decrease, prior to annualization, was due to a 10 day shut-down of the plant in September to install an amine unit and a two week shut-down in December to repair the insulation in the incinerator (a total of 48 days on a annualized basis). Also, contributing to the decline in the annualized transition period 1997 gas plant revenues was a 14% decline from fiscal 1997 in plant liquids prices. Annualized gas plant expenses were $2.5 million in the transition period 1997 as compared to $3.3 million during fiscal 1997. The decrease in expenses is attributable to the plant shut-downs.
Production expenses for the annualized transition period 1997 were $27.7 million, an increase of 142% over the fiscal 1997 amount. The increase is primarily due to inclusion of the Partnership Transactions for all of transition 1997, while fiscal 1997 amounts reflect only one quarter for the Partnership Transactions. On an MCF equivalency basis, production expenses for the annualized transition period increased to $.79 per equivalent MCF versus $.73 per equivalent MCF in fiscal 1997. The increase in the per unit rate results from the suspension of production, but not production expenses, at the Point Pedernales field for most of the last quarter of the transition period and from out of period expenses recorded within the annualized 1997 transition period.
Depreciation, depletion and amortization for the annualized transition period 1997 increased 110% to $32.7 million. The impact of increased production in the transition period due to the Partnership Transactions was partially offset by a $.04 per MCF decrease in the depletion rate. Depreciation, depletion and amortization was $.90 per MCF in the annualized transition period 1997 as compared to $.94 per MCF in fiscal 1997.
General and administrative expenses increased from $4.0 million in fiscal 1997 to $7.5 million in annualized transition period 1997. The increase is primarily due to increased management fees resulting from the Partnership Transactions. Management fees are based on the Company's net assets and operating cash flows. On an MCF basis, general and administrative expenses decreased to $.21 per MCF in transition 1997 from $.23 per MCF in fiscal 1997.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Annualized interest expense increased 167% to $12 million from $4.5 million in fiscal 1997. The increase is primarily due to interest attributable to the $100 million of 10 7/8% Senior Subordinated Notes issued April 1997 to finance the Partnership Transactions.
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 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, 1999 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. The floating rate for the period from October 1, 1999 to April 1, 2000 is 9.64%. Through April 2002 the floating rate is capped at 10.875% and capped at 12.375% thereafter. A 10% increase in these floating rates would have the effect of increasing interest costs to the Company by $216,800 per year.
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 not yet determined the impact of this statement on the Company's financial condition or results of operations.
ITEM 7A.
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
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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.
The following tables detail the Company's hedges of future production, which were in place at December 31, 1999.
OIL HEDGES
GAS HEDGES
* This agreement includes a put at $17.00 per barrel ** This agreement includes a put at $2.40 per Mcf
The fair value at December 31, 2000 of these swap agreements was a gain of $862,000. these energy swap agreements expose the Company to counterparty credit risk to the extent the counterparty is unable to meet its montly 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. As the swap provider is a major financial institution, 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% increase in the floating LIBOR rates would have the effect of increasing interest costs to the Company by $216,500 per year.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS AND SCHEDULES
Page Number -----------
Independent Auditors' Report.......................................... 32
Financial Statements:
Consolidated Balance Sheets as of December 31, 1999 and 1998,........ 33
Consolidated Statements of Operations for the Periods Ended December 31, 1999, 1998 and 1997, and June 30, 1997................. 35
Consolidated Statements of Changes in Stockholders' Equity for the Periods Ended December 31, 1999, 1998, 1997, and June 30, 1997...... 36
Consolidated Statements of Cash Flows for the Periods Ended December 31, 1999, 1998, 1997, and June 30, 1997.................... 37
Notes to Consolidated Financial Statements........................... 39
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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, 1999 and 1998 and the related consolidated statements of operations, changes in stockholders' equity and cash flows for the years ended December 31, 1999 and 1998, the six month period ended December 31, 1997 and the year ended June 30, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Bellwether Exploration Company and subsidiaries as of December 31, 1999 and 1998 and the results of their operations and their cash flows for the years ended December 31, 1999, 1998, the six month period ended December 31, 1997, and the year ended June 30, 1997 in conformity with generally accepted accounting principles.
KPMG LLP Houston, Texas March 16, 2000
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS ASSETS (Amounts in thousands)
See Notes to Consolidated Financial Statements.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS LIABILITIES AND STOCKHOLDERS' EQUITY (Amounts in thousands, except share information)
See Notes to Consolidated Financial Statements.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (Amounts in thousands, except per share data)
See Notes to Consolidated Financial Statements.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY (Amounts in thousands)
See Notes to Consolidated Financial Statements.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (Amounts in Thousands)
See Notes to Consolidated Financial Statements.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED) (Amounts in Thousands)
See Notes to Consolidated Financial Statements.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
1. ORGANIZATION
Bellwether Exploration Company ("the Company") was formed as a Delaware corporation in 1994 to succeed to the business and properties of its predecessor company pursuant to a merger, the primary purpose of which was to change the predecessor company's state of incorporation from Colorado to Delaware. The predecessor company was formed in 1980 from the consolidation of the business and properties of related oil and gas limited partnerships. References to Bellwether or the Company include the predecessor company, unless the context requires otherwise.
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 Ukrainian interests are currently reflected using the equity method. All significant intercompany accounts and transactions have been eliminated in consolidation.
Fiscal Year Change
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").
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. 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 MCF of production was approximately $ .72 in 1999, $1.10 in 1998, $.90 in transition period 1997, and $.94 in fiscal 1997.
The following table shows, by category of cost and date incurred, the domestic unproved property costs excluded from amortization (amounts in thousands):
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
The Latin American unproved property costs of $404,000 excluded from amortization was incurred in 1999 and was for acquisition costs.
Significant land and seismic costs have been incurred in the current and prior years by the Company and are still in the evaluation stage. While approximately $1.2 million has been evaluated and moved to the full cost pool in 1999, $16.3 million of such domestic costs remain to be evaluated.
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 1999. This category of costs will transfer into the full cost pool in 2000.
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 1999, 1997 or June 1997.
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 Diamond M - NGL - Torch Gas Plant Venture, backed-in for a 16.5% working interest in the Diamond M and Snyder gas plants. This resulted in the dissolution of the joint venture and the Company's reduced interest in the Diamond M and Snyder gas plants.
The Company sold its gas gathering subsidiary for $40,000 on March 1, 1999.
Gas Imbalances
The Company uses the sales method of accounting for gas imbalances. Under this method, gas sales are recorded when revenue checks are received or are receivable on the accrual basis. The Company had a net imbalance liability, at fair value, of $1.2 million and $.5 million, at December 31, 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 has taken steps to extend the productive life of such reserves.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Natural Gas and Crude Oil Hedging
Commodity derivatives utilized as hedges include 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, 1999 or 1998.
Oil and gas revenues were decreased by $4.0 million in the year ended December 31, 1999, increased by $3.6 million in the year ended December 31, 1998, decreased by $1.6 million in the six month transition period ended December 1997 and decreased by $18,000 in the fiscal year ended June 1997, as a result of such hedging activity.
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.
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, 1999 and 1998, the six month transition period ended December 31, 1997, and the fiscal year ended June 30, 1997, was $ 11.1 million, $11.1 million, $5.4 million and $1.5 million, respectively. Income tax refunds received in cash for December 31, 1999, were $437,000. Income taxes paid in cash for the year ended December 31, 1998, the transition period ended December 31, 1997 and the fiscal year ended June 30, 1997, were $1,408,000, $41,000 and $198,000, respectively. In April 1997, a portion of the purchase price of the Partnership Transactions included the issuance to Torch Energy Advisors Inc. ("Torch"), as consideration for advisory services, 150,000 shares of the Company's common stock valued at $1.2 million and a warrant to purchase 100,000 shares of common stock at $9.90 per share valued at $300,000.
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 not yet determined the impact of this statement on the Company's financial condition or results of operations.
Use of Estimates
Management of the Company has made a number of estimates and assumptions relating to the reporting of assets and liabilities 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
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
statements in conformity with generally accepted accounting principles. 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 MERGERS
During the last three fiscal years, the Company has completed the following mergers and acquisitions, all of which were recorded using the purchase method of accounting:
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 95.45 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 (approximately 43% of the Carpatsky's equity), do not carry a preferential dividend and have majority voting rights over Carpatsky. In connection with this investment, Mr. J.P. Bryan, Chairman and Chief Executive Officer of Bellwether became the Chairman and CEO of Carpatsky and three Carpatsky directors retired and were replaced by three Bellwether appointees, giving Bellwether five of the new eight directorships of Carpatsky. Carpatsky conducts oil and gas exploration and production activities in the Republic of Ukraine.
In December 1998 Bellwether was the successful bidder for the Charapa field in Ecuador. With the successful bid, the Company was awarded with a contract for production and exploration of crude oil in the Charapa field. The contract provides the Company with approximately 50% 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 productions. Negotiations with the Ecuadorian government took place throughout 1999 with Bellwether officially taking over operations of the field in January of 2000. Bellwether has committed to a $12 million work program over three years.
In April 1997, the Company closed acquisitions of oil and gas properties, totaling $141.1 million, after purchase price adjustments, including working capital of $13.9 million, from certain partnerships and other entities managed or sponsored by Torch. The acquisitions were financed by the sale of 4.4 million shares of common stock, the sale of $100.0 million of 10-7/8% senior subordinated notes due in 2007 and the use of $33.3 million of a new $90.0 million senior unsecured credit facility (including the repayment of $22.0 million on a then existing credit facility).
4. RELATED PARTY TRANSACTIONS
The Company is a party to a master services agreement and six specific contracts which requires 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 amounts of $.4 million to $2.8 million plus fees based upon percentages of production ranging from 1/2% to 2% depending on the product. Prior to 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
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
December 31, 1999, 1998 and 1997, and June 30, 1997, related fees paid to Torch amounted to $2.9 million, $4.0 million, $2.4 million and $2.3 million, respectively.
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 the Partnership Transactions. The Company's stock was valued at $1.2 million, and the warrant was valued at $300,000. In December 1993, Torch was issued a warrant to purchase 187,500 shares of the Company's common stock at a price of $6.40 per share for its advisory services in identifying and negotiating a merger; such warrants were exercised in connection with the Partnership Transactions with total proceeds to the Company of $684,000.
Torch was also a selling partner in the Partnership Transactions through its ownership of general partnership and working interests in the partnerships programs. As a result, Torch was paid $18.4 million for such interests.
On August 2, 1999, Mr. J. Darby Sere, previously Chairman and CEO, and Mr. William C. Rankin, previously Senior Vice President and Chief Financial Officer, left the Company to pursue other opportunities. Director, Mr. J. P. Bryan 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. Mr. Bryan has limited involvement in the day to day operations of Torch. Approximately $1.7 million of severance cost attributable to this management change were incurred in August 1999.
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 $947,500, $1,143,000, $757,000 and $646,000 in periods ended December 1999, 1998 and 1997, June 1997, respectively.
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 $357,800, $379,000, $217,000 and $650,000, for these costs in periods ended December 1999, 1998, 1997 and June 1997, 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. Operator's overhead charged for these activities for the periods ended December 31, 1999, 1998, 1997, and June 30, 1997 was $1,153,000, $1,349,000, $698,000 and $729,000, respectively.
Torch became the operator of the Snyder Gas Plant on December 1, 1993. In periods ended December 1999, 1998, 1997 and June 1997, the fees paid by the Company to Torch were $73,000, $72,000, $42,000 and $49,000, respectively.
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 April 1997, the Company issued 4.4 million shares of common stock for net proceeds to the Company of $34.1 million. Such proceeds were used in financing the Partnership Transactions. Also included in the April Offering were 719,264 shares sold by certain shareholders. Additional shares issued during fiscal 1997 included
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
125,000 shares issued upon exercise of a warrant and 150,000 shares issued to Torch for advisory services rendered in connection with the Partnership Transactions.
On September 12, 1997, the Company authorized and declared a dividend of one preferred stock purchase right for each share of common stock, par value $.01 per share, of the Company. The dividend was payable on September 26, 1997 to the holders of record of Common Shares as of the close of business on such date.
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 at employee stock options was immaterial in 1999 and approximately $324,000 was allocated directly to additional paid in capital in 1998. Such benefit was not material in prior periods.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Earnings Per Share
SFAS No. 128 requires 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):
Options and warrants on 203,000 of shares of common stock were not included in computing diluted earnings per share for 1998 because their effects were antidilutive.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Treasury Stock
In September 1998, the Company's Board of Directors authorized the repurchase of up to $5 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. The plans currently allow the Company 1,825,000 options; therefore, the remainder are subject to Shareholder approval of an amendment to the Company's plan.
A summary of activity in the stock option plans is set forth below:
Detail of stock options outstanding and options exercisable at December 31, 1999 follows:
The estimated weighted average fair value per share of options granted during 1999, 1998, transition period 1997 and fiscal 1997 was $11.68, $2.34, $1.78 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 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, transition period 1997 and fiscal 1997: expected stock price volatility of 40%; and risk free interest rate of 5.5% and 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):
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 returns by $4 million for the year 1999, increased returns by $3.6 million for the year 1998 and reduced revenues by $1.6 million and $18,000 for the transition period 1997 and for the fiscal years ended June 30, 1997, respectively. At December 31, 1999 the Company had unrealized net hedging gains of $862,000.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
The following tables detail the Company's hedges of future production, which were in place at December 31, 1999.
OIL HEDGES
GAS HEDGES
* This agreement includes a put at $17.00 per barrel ** This agreement includes a put at $2.40 per Mcf
The fair value at December 31, 1999 of these swap agreements was a gain of $862,000. 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.
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, 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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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, 1999 and 1998 (in thousands).
7. LONG-TERM DEBT
Long-term debt is comprised of the following at December 31, 1999 and 1998 (in thousands):
Debt maturities by fiscal year are as follows (amounts in thousands):
1999 $ --- 2000 --- 2001 --- 2002 --- 2003 30,000 Thereafter 100,000 -------- $130,000 ========
In October 1996, the Company entered into a syndicated credit facility ("Syndicated Credit Facility") in an amount up to $50.0 million with an initial borrowing base of $27.0 million, to be re-determined semi-annually. At Bellwether's option, the interest rate varied, based upon borrowing base usage, from London Interbank Offered Rate ("LIBOR") plus 7/8% to LIBOR plus 1-1/4%, or the greater of the prime rate or Federal Funds rate plus 1/2%. The Syndicated Credit Facility was unsecured and was retired in April 1997.
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. Bellwether may elect an interest rate based either on a margin plus LIBOR or the higher of the prime rate or the sum of 1/2 of 1% plus the Federal Funds Rate. For LIBOR borrowings, the interest rate will vary from LIBOR plus 0.875% to LIBOR
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
plus 1.25% based upon borrowing base usage. In connection with the acquisition of oil and gas properties, $33.3 million was drawn under this facility, including $22 million used to retire outstandings under the Syndicated Credit facility. At December 31, 1999, there were $30.0 million borrowings outstanding.
The Senior Credit Facility contains various covenants including certain required financial measurements for a current ratio, consolidated tangible net worth and interest coverage ratio. In addition, the Senior Credit Facility includes certain limitations on restricted payments, dividends, incurrence of additional funded indebtedness and asset sales.
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% which decreases annually to 100.00% on April 1, 2005 and thereafter, plus accrued and unpaid interest. In the event of 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.
8. INCOME TAXES
Income tax expense (benefit) is summarized as follows (in thousands):
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
The tax effect of temporary differences that give rise to significant portions of the deferred tax assets and liabilities at December 31, 1999 and 1998 is as follows:
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.
A tax benefit related to the exercise of employee stock options of approximately $324,000 was allocated directly to additional paid-in capital in 1998. Such benefit was not material in 1999 and prior periods.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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:
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 has undergone 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, 1999, the Company had net operating loss carryforwards of approximately $30.2 million, which will expire in future years beginning in 2000.
9. COMMITMENTS AND CONTINGENCIES
Lease Commitments
The minimum future payments under the terms of the Company's office space operating lease is as follows:
YEAR ENDED DECEMBER 31 ($ IN THOUSANDS) ---------------------- ---------------- 2000 382 2001 403 2002 415 2003 426 2004 430
Rent expense was $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. Upon the new Torch Master Service Agreement in October 1999, Bellwether began paying office rent.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 $11.8 million minimum investment program. In 2000, the first year of the commitment, the Company is budgeted to spend approximately $7.1 million in the Charapa field.
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 recently settled the case for the sum of $353,500 net to its interest.
10. Select Quarterly Financial Data (amounts in thousands, except per share data) (Unaudited):
The quarter ended December 31, 1998 reflects a $73.9 million full cost ceiling impairment, which resulted from low oil and gas prices at December 31, 1998.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
The quarter ended December 31, 1999 reflects increased oil and gas prices and increased production levels as result of increased drilling activities and the acquisition of Gulf of Mexico and New Mexico properties in the last half of 1999. In addition, the Company recognized a $2.7 million tax asset based upon increased future net reserves.
11. SEGMENT REPORTING
The Company has recently acquired interests in Ecuador and the Ukraine. (See Note) Relative to the Charapa field in Ecuador, capital expenditures as of December 31, 1999 totaled $843,000 primarily incurred for contract negotiation, development planning and accumulation of necessary tools, supplies and equipment. Field operations commenced in January of 2000. A loss of $172,000 for the year ended December 31, 1999 is attributable to Ecuadorian operations due to the recognition of start up costs and other administrative expenses.
The Company's Ukrainian interests were acquired December 30, 1999 through an acquisition of a controlling interest in the preferred stock of Carpatsky Petroleum Inc. At December 31, 1999 Bellwether's consolidated financial statements reflected $4.6 million in Investment in Outside Companies identified to the Ukrainian interests. No revenues or expenses related to the Ukrainian operations were recognized by the Company for the year ended December 31, 1999.
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 for fiscal 1999 and 1998 and the transition period 1997 and the year ended June 30, 1997. 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 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.
There are no reserves associated with the Company's Ukrainian investments as such amounts were immaterial at December 31, 1999.
COSTS INCURRED (IN THOUSANDS)
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
CAPITALIZED COSTS (IN THOUSANDS):
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Results of operations for producing activities (in thousands):
1) Ecuador and Ukraine activities did not commence production until 2000; therefore, no information for International operations is disclosed.
1) Average sales price is inclusive of the effect of natural gas and crude oil price swaps, which decreased revenues $4 million in 1999, increased revenues $3.6 million in 1998, decreased revenues $1.6 million in transition period 1997 and decreased revenues $18,000 in fiscal year ended June 30, 1997. 2) Ecuador and Ukraine activities commenced production in 2000; therefore, price and cost information is not disclosed.
The Company's estimated total proved and proved developed reserves of oil and gas as follows:
(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.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
Reserves continued:
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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 shown below:
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
The discounted future cash flows above were calculated using NYMEX equivalent prices of $25.60, $12.05, $18.32 and $19.80 per barrel and $2.33, $2.15, $2.58 and $2.35 per MMBTU, for December 31, 1999, 1998 and 1997 and June 30, 1997, respectively, adjusted to the wellhead to reflect adjustments for transportation, quality and heating content.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
On or about June 18, 1997 the Company replaced the firm of Deloitte and Touche, LLP as its principal independent accountant and auditors to audit all the Company's financial statements with the firm of KPMG LLP. The decision to make this change was influenced by the acquisition of Partnership properties and interests, which were previously audited by KPMG LLP. The Company does not and has not during the past three years had disagreements with Deloitte and Touche LLP or KPMG LLP concerning their audit or application of accounting principles according to GAAP.
PART III
ITEM 10.
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, 1999. Such information is incorporated herein by reference.
ITEM 11.
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, 1999. Such information is incorporated herein by reference.
ITEM 12.
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, 1999. Such information is incorporated herein by reference.
ITEM 13.
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, 1999. Such information is incorporated herein by reference.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. and 2. Financial Statements. See index to Consolidated Financial Statements and Supplemental Information in Item 8, which information is incorporated herein by reference.
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.)
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
3.4 By-laws of Bellwether Exploration Company (incorporated by reference to Exhibit 3.2 to the Company's Registration Statement No. 33-76570)
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)
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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).
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).
11.10 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.)
11.11 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 10Q for the quarter ended June 30, 1999.
11.12 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 10-Q for the quarter ended June 30, 1999.
11.13 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 10-Q for the quarter ended September 30, 1999).
11.14 Securities Purchase Agreement dated December 29, 1999 by and between the Company and Carpatsky Petroleum, Inc. - included herewith.
11.15 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., - included herewith.
11.16 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 - included herewith.
11.17 Master Service Agreement between the Company and Tecnie S.A.C. dated November 1, 1999 - included herewith.
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
16.1 Letter from predecessor auditors regarding change in certifying accountant (incorporated by reference to Exhibit 16-1 to the Company's Form 8K/A-1 dated July 8, 1997)
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
27 Financial Data Schedule
BELLWETHER EXPLORATION COMPANY AND SUBSIDIARIES
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/ J. P. Bryan ------------------- J. P. BRYAN Chairman of Board of Directors and Chief Executive Officer
Dated March 24, 2000
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.
SIGNATURES TITLE DATE
/s/ J. P. Bryan Chairman of Board of March 24, 2000 - -------------------- Directors and Chief J. P. Bryan Executive Officer
/s/ Robert Bensh Senior Vice President - March 24, 2000 - -------------------- Finance Robert Bensh
/s/ Dr. Jack Birks - -------------------- Director March 24, 2000 Dr. Jack Birks
/s/ Judith Allen - -------------------- Director March 24, 2000 Judith Allen
/s/ Vincent H. Buckley - ----------------------- Director March 24, 2000 Vincent H. Buckley
/s/ Habib Kairouz - -------------------- Director March 24, 2000 Habib Kairouz
/s/ A. K. McLanahan - -------------------- Director March 24, 2000 A. K. McLanahan
/s/ Townes G. Pressler - ---------------------- Director March 24, 2000 Townes G. Pressler