10-K405 1 h85182e10-k405.txt KCS ENERGY INC - YEAR ENDED DECEMBER 31, 2000 1 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO COMMISSION FILE NUMBER 1-11698 KCS ENERGY, INC. (Exact name of registrant as specified in its charter) DELAWARE 22-2889587 (State or other jurisdiction (IRS Employer of incorporation or organization) Identification No.) 5555 SAN FELIPE ROAD, HOUSTON, TEXAS 77056 (Address of principal executive offices) (Zip Code)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 877-8006 Securities registered pursuant to Section 12(b) of the Act:
NAME OF EACH EXCHANGE TITLE OF EACH CLASS ON WHICH REGISTERED ------------------- --------------------- COMMON STOCK, par value $0.01 per share New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: TITLE OF CLASS -------------- COMMON STOCK, par value $0.01 per share INDICATE BY CHECK MARK WHETHER THE REGISTRANT (1) HAS FILED ALL REPORTS REQUIRED TO BE FILED BY SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 DURING THE PRECEDING 12 MONTHS (OR FOR SUCH SHORTER PERIOD THAT THE REGISTRANT WAS REQUIRED TO FILE SUCH REPORTS), AND (2) HAS BEEN SUBJECT TO SUCH FILING REQUIREMENTS FOR THE PAST 90 DAYS. YES [X] NO [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10K. [X] The aggregate market value of the 25,669,448 shares of the Common Stock held by non-affiliates of the Registrant at the $5.05 closing price on March 1, 2001 was $129,630,712. Number of shares of Common Stock outstanding as of the close of business on March 1, 2001: 29,408,810 DOCUMENTS INCORPORATED BY REFERENCE Part III incorporates information by reference to Notice of and Proxy Statement for the 2001 Annual Meeting of Shareholders to the extent indicated herein. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 2 KCS ENERGY, INC. FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2000 PART I ITEM 1. BUSINESS. GENERAL DEVELOPMENT OF BUSINESS KCS Energy, Inc. ("KCS" or the "Company") is an independent oil and gas company engaged in the acquisition, exploration and production of natural gas and crude oil with operations predominately in the Mid-Continent and Gulf Coast regions. The Company also purchases reserves (priority rights to future delivery of oil and gas) through its Volumetric Production Payment ("VPP") program. The Company was formed in 1988 in connection with the spin-off of the non-utility businesses of NUI Corporation, a New Jersey-based natural gas distribution company that had been engaged in the oil and gas exploration and production business as well as numerous other businesses since the late 1960s. During 1998, due to very low prices for natural gas and crude oil and to disappointing performance of certain properties in the Rocky Mountain area, the Company incurred significant losses, primarily due to $268.5 million of pretax non-cash ceiling writedowns of its oil and gas assets and a reduction from $113.9 million to zero in the book value of net deferred tax assets. As a result of these non-cash charges, the net loss in 1998 increased by $288.4 million. Also as a result of these adjustments, the Company had negative stockholders' equity and was in default of certain covenants in its bank credit facilities. As a consequence, the Company was prohibited from borrowing under these facilities. In addition, the Company's independent public accountants issued modified reports for 1998 and 1999 with respect to the ability of the Company to continue as a going concern, which also constituted a default under the bank credit agreements. The Company was also in default with respect to its Senior Notes and Senior Subordinated Notes after it did not make scheduled interest payments in July 1999. On January 18, 2000, the United States Bankruptcy Court for the District of Delaware ("Bankruptcy Court") entered an order granting KCS Energy, Inc. relief under Chapter 11 of Title 11 of the United States Bankruptcy Code ("Bankruptcy Code") and each of KCS' subsidiaries filed voluntary petitions under the Bankruptcy Code. See Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources and Note 2 to Consolidated Financial Statements. In the second quarter of 1999, oil and gas prices began to recover. This recovery in prices, together with lower operating and general and administrative expenses and a successful capital investment program resulted in the Company returning to profitability in 1999. Net income in 1999 was $4.3 million, or $0.15 per share. Prices continued to strengthen in 2000 and the Company's performance and financial condition improved significantly. For the year ended December 31, 2000, the Company reported record earnings of $41.5 million, or $1.42 per share and record cash flow from operating activities (before reorganization items) of $137.3 million, funded a $69.1 million capital investment program and increased its cash balances from $10.6 million at December 31, 1999 to $40.0 million at December 31, 2000. In addition, from the second quarter of 1999 through December 31, 2000, the Company reduced its bank debt by $73.3 million, reducing the outstanding principal balance from $150.0 million to $76.7 million. On January 30, 2001, the Bankruptcy Court confirmed the KCS Energy, Inc. plan of reorganization ("the Plan") under Chapter 11 of the Bankruptcy Code after the Company's creditors and stockholders voted to approve the Plan. On February 20, 2001, the Company completed the necessary steps for the Plan to go effective and emerged from bankruptcy. Under the Plan, the Company repaid its two bank credit facilities in full, paid past due interest on its Senior and Senior Subordinated Notes, including interest on interest, and repaid $60.0 million of Senior Notes. Trade creditors were paid in full and shareholders retained 100% of their common stock, subject to dilution from conversion of the new convertible preferred stock. See "Liquidity and Capital Resources" and Note 2 to Consolidated Financial Statements for more information regarding the Plan. 1 3 Forward-looking Statements The information discussed in this 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, as amended (the "Exchange Act"). All statements, other than statements of historical facts, included herein regarding planned capital expenditures, increases in oil and gas production, the number of anticipated wells to be drilled after the date hereof, the Company's financial position, business strategy and other plans and objectives for future operations, are forward-looking statements. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, they do involve certain assumptions, risks and uncertainties, and the Company can give no assurance that such expectations will prove to be correct. The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including the timing and success of the Company's drilling activities, the volatility of prices and supply and demand for oil and gas, the numerous uncertainties inherent in estimating quantities of oil and gas reserves and actual future production rates and associated costs, the usual hazards associated with the oil and gas industry (including blowouts, cratering, pipe failure, spills, explosions and other unforeseen hazards), and changes in regulatory requirements. Some of these risks (as well as others) are described more fully elsewhere in this Form 10-K. All forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. Oil and Gas Operations All of the Company's exploration and production activities are located within the United States. The Company competes with major oil and gas companies, other independent oil and gas concerns and individual producers and operators in the areas of reserve and leasehold acquisitions and the exploration, development, production and marketing of oil and gas, as well as contracting for equipment and hiring of personnel. Oil and gas prices have been volatile historically and are expected to be volatile in the future. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include political conditions in the Middle East and elsewhere, the foreign supply of oil and gas, the price of foreign imports, the level of consumer product demand, weather conditions, domestic and foreign government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. No single customer accounted for more than 10% of the Company's annual consolidated revenues in the three years ended December 31, 2000. Exploration and Production Activities During the three-year period ended December 31, 2000, the Company participated in drilling 245 gross (128.4 net) wells, of which 79% were successful. In 2000, the Company participated in drilling 96 gross (47.0 net) wells, of which 82% were successful. This included 74 development wells and 22 exploration wells with success rates of 89% and 59%, respectively. In 2000, the Company concentrated its drilling programs predominately in the Mid-Continent and Gulf Coast regions. In the Mid-Continent Region, the Company explores in Oklahoma (Anadarko and Arkoma basins), North Louisiana, Michigan and the Permian basin. During 2000, the Company drilled 62 gross (35.9 net) wells in this region with a 90% success ratio. In the Gulf Coast Region, the Company drilled 34 gross (11.1 net) wells in 2000 with a 68% success ratio. In 2000, the Company participated in a number of major exploration and development programs including: (a) the construction of an amine plant and the tie in of 4 wells to the Hartland Plant in Livingston County, Michigan, (b) the drilling of 5 wells at the West Arcadia and West Ada fields in north Louisiana, 2 4 (c) an 18 well development program in the Sawyer Canyon Field, Sutton County, Texas, (d) a significant discovery in the Austin Field, Goliad County, Texas and (e) continued development of the West Shugart Field, Eddy County, New Mexico and the Elm Grove Field, Bossier Parish, Louisiana. Volumetric Production Payment Program The Company augments its working interest ownership of properties with a VPP program, a method of acquiring oil and gas reserves scheduled to be delivered in the future at a discount to the current market price in exchange for an up-front cash payment. A VPP entitles the Company to a priority right to a specified volume of oil and gas reserves scheduled to be produced and delivered over a stated time period. Although specific terms of the Company's VPPs vary, the Company is generally entitled to receive delivery of its scheduled oil and gas volumes at agreed delivery points, free of drilling and lease operating costs and, in most cases, free of state severance taxes. The Company believes that its VPP program diversifies its reserve base and achieves attractive rates of return while minimizing the Company's exposure to certain development, operating and reserve volume risks. Typically, the estimated proved reserves of the properties underlying a VPP are substantially greater than the specified reserve volumes required to be delivered pursuant to the production payment. Since the inception of the VPP program in August 1994 through December 31, 2000, the Company has invested $213.6 million under the VPP program and has acquired proved reserves of 120.3 Bcfe of natural gas and oil. Through December 31, 2000, the Company has recognized approximately $254.1 million in revenue from the sale of oil and gas acquired under the program, with 6.2 Bcfe of conventional VPPs and 12.0 Bcfe of a Michigan VPP now owned as a working interest, scheduled for future deliveries. Due to limited capital availability during the Chapter 11 process, in 2000, the Company invested only $5.7 million in 2 VPP transactions, acquiring 2.5 Bcf of natural gas located in the Gulf of Mexico. Raw Materials The Company obtains its raw materials from various sources, which are presently considered adequate. While the Company regards the various sources as important, it does not consider any one source to be essential to its business as a whole. Patents and Licenses There are no patents, trademarks, licenses, franchises or concessions held by the Company, the expiration of which would have a material adverse effect on its business. Seasonality Demand for natural gas and oil is seasonal, principally related to weather conditions and access to pipeline transportation. Oil and Gas Risk Factors Set forth below, are certain risk factors to which the Company is subject as a result of its operations in the oil and gas industry. Volatile Nature of Oil and Gas Markets; Fluctuation in Prices. The Company's future financial condition and results of operations are highly dependent on the demand and prices received for the Company's oil and gas production and on the costs of acquiring, exploring for, developing and producing reserves. Oil and gas prices have been volatile historically and are expected to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include political conditions in the Middle East and elsewhere, domestic and foreign supply of oil and gas, the level of consumer demand, weather conditions, domestic and foreign government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. A decline in oil or gas 3 5 prices may adversely affect the Company's cash flow, liquidity and profitability. Lower oil or gas prices also may reduce the amount of the Company's oil and gas that can be produced economically. It is impossible to predict future oil and gas price movements with any certainty. Dependence on Acquiring and Finding Additional Reserves. The Company's prospects for future growth and profitability will depend primarily on its ability to replace reserves through acquisitions, development and exploratory drilling. The decision to purchase, explore or develop an interest or property will depend in part on the evaluation of data obtained through geophysical and geological analyses and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Acquisitions may not be available at attractive prices, and there can be no assurance that the Company's acquisition and exploration activities or planned development projects will result in significant additional reserves, or that the Company will have continuing success in drilling economically productive wells. Without acquiring or developing additional reserves, the Company's proved reserves and revenues will decline. Reliance on Estimates of Reserves and Future Net Cash Flows. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the Company's control. This Form 10-K includes estimates by independent petroleum engineers of the Company's oil and gas reserves and future net cash flows. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of oil and gas reserves and of future net cash flow depend upon a number of variable factors and assumptions, such as historical production from the area compared to production from other producing areas, the assumed effects of regulation by government agencies and assumptions concerning future oil and gas prices, operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary significantly. Actual production, revenues and expenditures with respect to the Company's reserves likely will vary from estimates, and such variances may be material. The Company's reserves and future cash flows may be subject to revisions, based upon production history, oil and gas prices, performance of counterparties under agreements to which the Company is a party, operating and development costs and other factors. The PV-10 values referred to in this Form 10-K should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company's properties. In accordance with applicable requirements of the Securities and Exchange Commission ("SEC"), PV-10 is generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and gas, curtailments or increases in consumption by natural gas purchasers and changes in government regulations or taxation. The present value will be affected by the timing of both the production and the incurrence of expenses in connection with development and production of oil and gas properties. In addition, the 10% discount factor, which is required by the SEC to be used to calculate present value for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company and its properties or the oil and gas industry in general. Exploration Risks. Exploratory drilling activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered, and there can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and gas may involve unprofitable efforts, not only from non-productive wells, but from wells that are productive but do not provide sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, compliance with government requirements and shortages or delays in the delivery of equipment and services. 4 6 Marketing Risks. The Company's ability to market oil and gas at commercially acceptable prices is dependent on, among other factors, the availability and capacity of gathering systems and pipelines, federal and state regulation of production and transportation, general economic conditions and changes in supply and demand. The Company's inability to respond appropriately to these changing factors could have a negative effect on the Company's profitability. Acquisition Risks. Acquisitions of oil and gas businesses, properties and volumetric production payments have been an important element of the Company's business, and the Company will continue to pursue acquisitions in the future. Even though the Company performs a review (including review of title and other records) of the major properties it seeks to acquire that it believes is consistent with industry practices, such reviews are inherently incomplete, and it is generally not feasible for the Company to review in-depth every property and all records. Even an in-depth review may not reveal existing or potential problems or permit the Company to become familiar enough with the properties to assess fully their deficiencies and capabilities, and the Company may assume environmental and other liabilities in connection with acquired businesses and properties. Operating Risks. The Company's operations are subject to numerous risks inherent in the oil and gas industry, including the risks of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's operations may be materially curtailed, delayed or canceled as a result of numerous factors, including the presence of unanticipated pressure or irregularities in formations, accidents, title problems, weather conditions, compliance with government requirements and shortages or delays in obtaining drilling rigs or in the delivery of equipment. In accordance with customary industry practice, the Company maintains insurance against some, but not all, of the risks described above. There can be no assurance that the levels of insurance maintained by the Company will be adequate to cover any losses or liabilities. The Company cannot predict the continued availability of insurance, or availability at commercially acceptable premium levels. Competitive Industry. The oil and gas industry is highly competitive. The Company competes for oil and gas business and property acquisitions and for the exploration, development, production, transportation and marketing of oil and gas, as well as for equipment and personnel, with major oil and gas companies, other independent oil and gas concerns and individual producers and operators. Many of these competitors have financial and other resources, which substantially exceed those available to the Company. Government Regulation. The Company's business is subject to certain federal, state and local laws and regulations relating to the drilling, production, transportation and marketing of oil and gas, as well as environmental and safety matters. Such laws and regulations have generally become more stringent in recent years, often imposing greater liability on an increasing number of parties. Because the requirements imposed by such laws and regulations are frequently changed, the Company is unable to predict the effect or cost of compliance with such requirements or their effects on oil and gas use or prices. In addition, legislative proposals are frequently introduced in Congress and state legislatures, which if enacted, might significantly affect the oil and gas industry. In view of the many uncertainties, which exist with respect to any legislative proposals, the effect on the Company of any legislation, which might be enacted, cannot be predicted. Regulation General. The Company's business is affected by numerous governmental laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Changes in any of these laws and regulations could have a material adverse effect on the Company's business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to the Company, the Company cannot predict the overall effect of such laws and regulations on its future operations. 5 7 The Company believes that its operations comply in all material respects with all applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive an effect on the Company's method of operations than on other similar companies in the energy industry. The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing. State Regulations Affecting Production Operations. The Company's onshore exploration, production and exploitation activities are subject to regulation at the state level. Such regulation varies from state to state, but generally includes requiring permits for drilling wells, maintaining bonding requirements to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, plugging and abandoning wells, and the disposal of fluids used in connection with operations. The Company's operations are also subject to various state conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, spacing of wells and the unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, restrict the venting or flaring of gas and impose certain requirements regarding the ratability of production. These regulations and requirements may affect the profitability of affected properties or operations, and the Company is unable to predict the future cost or impact of complying with such regulations. Regulations Affecting Sales and Transportation of Oil and Gas. Various aspects of the Company's oil and gas operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission (the "FERC") regulates the transportation of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 (the "NGA") and the Natural Gas Policy Act of 1978 (the "NGPA"), including some natural gas produced or marketed by the Company. In the past, the federal government has regulated the prices at which the Company's natural gas could be sold. Currently, "first sales" of natural gas by producers and marketers, and all sales of crude oil, condensate and natural gas liquids, can be made at uncontrolled market prices, but Congress could reenact price controls at any time. Commencing in April 1992, the FERC issued its Order No. 636 and related clarifying orders ("Order No. 636") which, among other things, restructured the interstate natural gas industry and required interstate pipelines to provide transportation services separate, or "unbundled," from the pipelines' purchases and sales of natural gas. Order No. 636 and certain related "restructuring proceedings" affecting individual pipelines were the subject of a number of judicial appeals and orders on remand by the FERC. Order No. 636 has largely been upheld on appeal. The FERC continues to address Order 636-related issues (including transportation capacity auctions, alternative and negotiated ratemaking, policy matters affecting gas markets and gas industry standards) in a number of pending proceedings. The FERC continues to examine its policies affecting the natural gas industry. It is not possible for the Company to predict what effect, if any, the ultimate outcome of the FERC's various initiatives will have on the Company's operations. Order No. 636 was issued to foster increased competition within all phases of the natural gas industry. Although Order No. 636 has provided the Company with increased access to markets and the ability to utilize new types of transportation services, the Company is required to comply with pipeline operating tariffs, including restrictive pipeline imbalance tolerances, and to respond to penalties for violations of those tariffs. The Company believes that Order No. 636 has not had any significant impact on the Company. The FERC continues to authorize the sale and abandonment from NGA regulation of natural gas gathering facilities previously owned by interstate pipelines. Such facilities (and services on such systems) may be subject to regulation by state authorities in accordance with state law. A number of states either have enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. For example, the Railroad Commission of Texas recently issued a code of conduct governing transportation and gathering services provided by intrastate pipelines and gatherers, and has required that services are to be provided to shippers without undue discrimination. Other states have implemented specific regulations covering gathering services. In general, state regulation of gathering facilities includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but does not generally entail regulation of the gathering rates charged. Natural gas gathering may receive greater regulatory scrutiny by 6 8 state agencies in the future, and in that event, the Company's gathering operations could be adversely affected; however the Company does not believe that it would be affected by such regulation any differently from other natural gas producers or gatherers. The effects, if any, of changes in existing state or FERC policies on the Company's gas gathering or gas marketing operations are uncertain. Sales of crude oil, condensate and natural gas liquids by the Company are not currently regulated and are made at market prices. The price the Company receives from the sale of these products is affected by the cost of transporting the products to market. Effective January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which generally index such rates to inflation, subject to certain conditions and limitations. The Company is not able to predict with certainty what effect, if any, these regulations will have on its business, but other factors being equal, the regulations may tend to increase transportation costs or reduce wellhead prices under certain conditions. Federal Regulations Affecting Production Operations. The Company also operates federal and Indian oil and gas leases, which are subject to the regulation of the United States Bureau of Land Management ("BLM"), the Bureau of Indian Affairs ("BIA") and the United States Minerals Management Service ("MMS"). MMS, BIA and BLM leases contain relatively standardized terms requiring compliance with detailed regulations and, in the case of offshore leases, orders pursuant to the Outer Continental Shelf Lands Act ("OCSLA") (which are subject to change by the MMS). Such regulations specify, for example, lease operating, safety and conservation standards, as well as well plugging and abandonment and surface restoration requirements. To cover the various obligations of lessees of federal and Indian lands, including lessees of Outer Continental Shelf ("OCS") lands, the BIA, BLM and MMS generally require lessees to post bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that any particular lease operator can obtain bonds or other surety in all cases. Under certain circumstances, the MMS, BIA or BLM may require operations on federal or Indian leases to be suspended or terminated. Any such suspension or termination could adversely affect the Company's interests. Effective June 1, 2000, the MMS amended its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. The amendments modify the valuation procedures for both arm's length and non-arm's length crude oil transactions to decrease reliance on posted oil prices and assign a value to crude oil that better reflects its market value. Similar changes have been proposed with regard to valuation of Indian royalty oil. The Company is not able to predict with certainty what effect, if any, these regulations will have on its business, but believes that the regulations will have no more an effect on the Company than on other similar companies in the energy industry. The MMS also continues to consider changes to the way it values natural gas for royalty payments. These changes would establish an alternative market-based method to calculate royalties on certain natural gas sold to affiliates or pursuant to non-arm's length sales contracts. Discussions among the MMS, industry officials and Congress are continuing, although it is uncertain whether and what changes may ultimately be proposed regarding gas royalty valuation. Additional proposals and proceedings that might affect the oil and gas industry are pending before Congress, the FERC, the MMS, the BLM, the BIA, state commissions and the courts. The Company cannot predict when or whether any such proposals may become effective. Historically, the natural gas industry has been very heavily regulated. There is no assurance that the current regulatory approach pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, it is not anticipated that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of the Company. Operating Hazards and Environmental Matters. The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blowouts, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures and discharge of toxic gases. The occurrence of any of these hazards could result in substantial losses to the Company due to injury 7 9 or loss of life, severe damage to or destruction of property, losses of natural resources, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. Although the Company believes it is adequately insured, such hazards may hinder or delay drilling, development and production operations. Oil and gas operations are subject to extensive federal, state and local laws and regulations that regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. These laws and regulations may require the acquisition of a permit before drilling commences; restrict or prohibit the types, quantities and concentration of substances that can be released into the environment or wastes that can be disposed of in connection with drilling and production activities; restrict drilling activities on certain lands, such as wetlands or other protected areas, and impose substantial liabilities for pollution resulting from drilling and production operations. Failure to comply with these laws and regulations may also result in civil and criminal fines and penalties. The Company's properties and any wastes generated by the Company that may have been disposed thereon or on other lands may be subject to federal or state environmental laws that could require the Company to remove the wastes or remediate contamination. For example, the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to assert claims for personal injury and property damage allegedly caused by the release of hazardous substances. See "Environmental Claims" below. Also, the Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the Company's operations. The EPA and state governments have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues. The Company does not believe that its operations will be materially adversely affected by any such requirements. In addition, the U.S. Oil Pollution Act ("OPA") requires owners and operators of facilities that could be the source of an oil spill into "waters of the United States" (a term defined to include rivers, creeks, wetlands and coastal waters) to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay for the costs of cleaning up an oil spill and compensating any parties damaged by an oil spill. Such financial assurances may be increased to as much as $150 million if a formal assessment indicates such an increase is warranted. The Company's operations are also subject to the federal Clean Water Act ("CWA") and analogous state laws. The Company may be required to incur certain capital expenditures in order to comply with prohibitions against the discharge of produced waters into coastal waters or increased operating expenses in connection with offshore operations in coastal waters. Pursuant to other requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. While certain of its properties may require permits for discharges of storm water runoff, the Company believes that it will be able to obtain, or be included under, such permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on the Company. Additionally, pursuant to the Safe Drinking Water Act, the EPA has adopted regulations concerning permitting and operations of underground injection control ("UIC") wells, including wells used in enhanced 8 10 recovery and disposal operations associated with exploration and production activities. The United States Department of Justice alleged that certain of the Company's UIC wells in Toole and Liberty counties, Montana in the Rocky Mountain area have not complied with such regulations in certain instances. The Company entered into a consent decree resolving this matter, which it believes will not have a material adverse effect on the Company. In addition, the disposal of wastes containing naturally occurring radioactive material, which are commonly generated during oil and gas production is regulated under state law. Typically, wastes containing naturally occurring radioactive material can be managed on-site or disposed of at facilities licensed to receive such waste at costs that are not expected to be material. Environmental Claims. The Company owns the following two oil and gas leases covering an aggregate of approximately 11,000 acres in Los Angeles County, California: a) Oil and Gas Lease dated June 13, 1935, from Newhall Land and Farming Company, as Lessor, to Barnsdall Oil Company, as Lessee (the "RSF Lease") and b) Oil and Gas Lease dated June 6, 1941, from the Newhall Corporation, as Lessor, to C.G. Willis, as Lessee (the "Ferguson Lease"). The RSF Lease and the Ferguson Lease are herein called "Leases." Oil and gas production from such lands commenced shortly after the RSF Lease was granted and has continued to date. From inception of the Leases until October 30, 1990, the Leases were owned by entities that through corporate succession and name change ultimately became Sun Operating Limited Partnership ("Sun L.P."). On October 30, 1990, Sun L.P. transferred the Leases to DKM Offshore Energy, Inc. ("DKM") and Neste Oil Services Inc. ("Neste"). In the assignment of the Leases, Sun L.P. indemnified DKM and Neste from environmental claims resulting from the indemnitors' operations provided that such environmental claims were made within ten years from October 30, 1990. Shortly after the transfer to DKM and Neste, DKM acquired Neste's rights and, subsequently, DKM became Medallion California Properties Company ("Medallion California"). Later, the Company acquired the stock of Medallion California. Also, Sun L.P. became Kerr-McGee Oil & Gas Onshore L.P. ("Kerr-McGee L.P."). In connection with the purchase of Medallion California by KCS, InterCoast Energy Company ("InterCoast") indemnified the Company and Medallion California for up to 90% of the costs of environmental remediation not assumed by Kerr-McGee L.P. InterCoast's parent, MidAmerican Capital Company ("MidAmerican"), guaranteed InterCoast's indemnity obligations. Kerr-McGee L.P. has identified 21 sites for cleanup on the lands covered by the Leases and has a Remedial Action Plan ("RAP") approved by the Los Angeles County Regional Water Quality Control Board to effect such cleanup. The primary contaminant identified for this cleanup is petroleum waste. The Company believes that Kerr-McGee L.P. will ultimately accomplish the RAP and that the Company has no exposure for remediation of these 21 sites. In addition to the 21 sites identified in the RAP, the Company has identified and analyzed samples from numerous additional sites and has found that certain of those sites are contaminated with petroleum waste. The Company has described those sites to the lessors, Kerr-McGee L.P., InterCoast and MidAmerican. The Company believes Kerr-McGee will ultimately be responsible for remediation of substantially all of these additional sites. Litigation is currently pending among Kerr-McGee L.P., InterCoast, MidAmerican and the Company seeking a declaratory judgment as to the nature and extent of the indemnities by Kerr-McGee L.P. and by InterCoast and MidAmerican. Litigation is also pending in which the Lessor of the RSF Lease seeks, among other remedies, damages and punitive damages for alleged environmental contamination and site restoration of the lands covered by the RSF Lease, and in which Medallion California claims indemnification is owed by Kerr-McGee L.P., InterCoast and MidAmerican. See Note 10 to the Consolidated Financial Statements included herein. Employees The Company and its subsidiaries employed a total of 164 persons on December 31, 2000. 9 11 ITEM 2. PROPERTIES. OIL AND GAS PROPERTIES The following table sets forth data as of December 31, 2000 regarding the number of gross producing wells and the estimated quantities of proved oil and gas reserves attributable to the Company's principal properties.
ESTIMATED PROVED RESERVES GROSS ------------------------------- PRODUCING OIL NATURAL GAS TOTAL LOCATION WELLS (MBBLS) (MMCF) (MMCFE) -------- --------- ------- ----------- ------- Mid-Continent Region: Sawyer Canyon and Sonora Fields, Texas............ 372 36 44,453 44,669 Manderson Field, Wyoming.......................... 49 554 15,142 18,466 Hartland Area, Michigan........................... 4 721 12,954 17,280 Elm Grove Field, Louisiana........................ 33 18 15,433 15,541 Newhall-Potrero Field, California................. 42 1,686 1,912 12,028 Mayfield/Hayes Properties, Michigan............... 7 377 5,447 7,709 Shugart, W. Field, New Mexico..................... 12 924 1,013 6,557 Battle Creek Field, Montana....................... 76 -- 3,792 3,792 Wilburton Field, Oklahoma......................... 12 -- 3,561 3,561 Arcadia, West Field, Louisiana.................... 5 15 3,441 3,531 Mills Ranch Field, Texas.......................... 24 52 3,211 3,523 Others............................................ 827 3,353 36,988 57,106 ----- ----- ------- ------- Total Mid-Continent Region................ 1,463 7,736 147,347 193,763 ----- ----- ------- ------- Gulf Coast Region: Langham Creek Area, Texas......................... 19 190 18,277 19,417 Non-operated Offshore Properties.................. 45 216 5,501 6,797 Provident City Field, Texas....................... 43 64 4,479 4,863 Padre, North Field, Texas......................... 1 15 3,455 3,545 Austin Deep Field, Texas.......................... 2 3 3,350 3,368 Others............................................ 209 762 22,141 26,713 ----- ----- ------- ------- Total Gulf Coast Region................... 319 1,250 57,203 64,703 ----- ----- ------- ------- Total Working Interest.................... 1,782 8,986 204,550 258,466 ----- ----- ------- ------- Volumetric Production Payments (VPPs)............... n/a -- 7,078 7,078 ----- ----- ------- ------- Total Company............................. 1,782 8,986 211,628 265,544 ===== ===== ======= =======
MID-CONTINENT REGION In the Mid-Continent Region, the Company is pursuing opportunities primarily in Oklahoma (Anadarko and Arkoma basins), north Louisiana, Michigan and the Permian basin. This region also includes producing properties in the Rocky Mountains. The Company views the Mid-Continent Region as providing a solid base for production replacement and plans to continue to exploit areas within the various basins that require additional wells for adequate reserve drainage and to drill low-risk exploration wells. These wells are generally step-out and extension type wells with moderate reserve potential. The Company endeavors to be the operator when it holds a majority of the working interest. Estimated proved reserves in the Mid-Continent Region were 193.8 Bcfe as of December 31, 2000, representing approximately 73% of the Company's reserves. During the year ended December 31, 2000, in this region, the Company participated in drilling 62 gross (35.9 net) wells with a completion success rate of 90%. At December 31, 2000, the Company owned leasehold interests within the Mid-Continent Region covering approximately 445,584 gross (326,366 net) acres. 10 12 GULF COAST REGION The Gulf Coast Region is primarily comprised of producing properties in south Texas, coastal Louisiana and the Mississippi Salt basin and minor non-operated offshore properties. The Company conducts development programs and pursues moderate-risk, higher-exposure exploration drilling programs. The Gulf Coast Region has prospects which are expected to provide the key area of future growth for the Company. Estimated proved reserves in the region were 64.7 Bcfe as of December 31, 2000, which represented approximately 24% of the Company's reserves. During 2000 the Company drilled 34 gross (11.1 net) wells in the Gulf Coast Region with a completion success rate of 68%. The Company owns or controls approximately 206,787 gross (42,601 net) acres in the Gulf Coast Region. VOLUMETRIC PRODUCTION PAYMENT PROGRAM The Company augments its working interest ownership of properties with its VPP program, a method of acquiring proved oil and gas reserves scheduled to be delivered in the future at a discount to the current market price in exchange for an up-front cash payment. A VPP entitles the Company to a priority right to a specified volume of oil and gas reserves scheduled to be produced and delivered over a stated period of time. Through a series of VPP transactions, the Company has acquired certain interests in seven federal leases off the coasts of Texas and Louisiana. Although specific terms of the Company's VPPs vary, the Company is generally entitled to receive delivery of its scheduled oil and gas volumes at agreed delivery points, free of drilling and lease operating costs and, in most cases, free of state severance taxes. After delivery of the oil and gas volumes, the Company arranges for further downstream transportation and sells such volumes to available markets. The Company believes that its VPP program diversifies its reserve base and achieves attractive rates of return while minimizing the Company's exposure to certain development, operating and reserve volume risks. Typically, the estimated proved reserves of the properties underlying a VPP are substantially greater than the specified reserve volumes required to be delivered pursuant to the production payment. Proved reserves associated with the VPP program were estimated as of December 31, 2000 to be 7.1 Bcfe, representing approximately 3% of the Company's reserves. Since the inception of the VPP program in late 1994 through December 31, 2000, the Company has invested $213.6 million in 30 separate transactions and has acquired proved reserves of 120.3 Bcfe, consisting of 110.0 Bcf of natural gas and 1.6 MMbbls of oil. This represents an average net acquisition cost of $1.78 per Mcfe, without the burden of development and lease operating expenses. Through December 31, 2000, the Company has recovered approximately $254.1 million from the sale of oil and gas received under its VPP program. The properties which constitute the VPP program are principally located in the Gulf of Mexico. Due to limited capital availability during the Chapter 11 reorganization, during 2000, the Company invested only $5.7 million in 2 VPP transactions acquiring 2.5 Bcf of natural gas, located in the Gulf of Mexico. Although it has not done so in the past, the Company is exploring the expansion of the VPP program through joint venture partnerships or similar arrangements with third parties. OIL AND GAS RESERVES The reserve estimates and associated cash flows as of December 31, 2000 and December 31, 1999 for all properties were prepared by Netherland, Sewell & Associates, Inc. The reserve estimates and associated cash flows as of December 31, 1998 were prepared by KCS and several independent petroleum engineers. The reports for the KCS Medallion Resources, Inc.; KCS Mountain Resources, Inc.; KCS Resources, Inc.; and KCS Michigan Resources, Inc. properties, which collectively represent 100% of KCS's proved reserves on working interest properties, and 85.4% of KCS's total proved reserves as of December 31, 1998, were audited by Netherland, Sewell & Associates, Inc. pursuant to the principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. The independent reserve engineers' 11 13 estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by the Company or third-party operators. The following table sets forth, as of December 31, 2000, summary information with respect to estimates of the Company's proved oil and gas reserves. The present value of future net revenues in the table should not be construed to be the current market value of the estimated oil and gas reserves owned by the Company.
DECEMBER 31, 2000 ------------ PROVED RESERVES: Natural gas (MMcf).......................................... 211,628 Oil (Mbbls)................................................. 8,986 Total (MMcfe)............................................... 265,544 Future net revenues ($000s)................................. $1,728,500 Present value of future net revenues ($000s)................ $1,104,479 PROVED DEVELOPED RESERVES: Natural gas (MMcf).......................................... 173,995 Oil (Mbbls)................................................. 7,885 Total (MMcfe)............................................... 221,305 Future net revenues ($000s)................................. $1,445,141 Present value of future net revenues ($000s)................ $ 946,048
There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and future amounts and timing of development expenditures, including underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Estimates of proved undeveloped reserves are inherently less certain than estimates of proved developed reserves. The quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, geologic success and future oil and gas sales prices all may differ from those assumed in these estimates. In addition, the Company's reserves may be subject to downward or upward revision based upon production history, purchases or sales of properties, results of future development, prevailing oil and gas prices and other factors. Therefore, the present value shown above should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company's properties. In accordance with SEC guidelines, the estimates of future net revenues from the Company's proved reserves and the present values thereof are made using oil and gas sales prices in effect as of the dates of such estimates and are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including, in the case of natural gas contracts, the use of fixed and determinable contractual price escalations. Gas prices are based on either a contract price or a December 31, 2000 spot price of $9.529 per MMBTU, adjusted by lease for BTU content, transportation fees and regional price differentials. The spot price on March 21, 2001 was $5.17 per MMBTU. Oil prices are based on a December 31, 2000 West Texas Intermediate posted price of $23.75 per barrel, adjusted by lease for gravity, transportation fees and regional posted price differentials. The prices for natural gas and oil are subject to substantial seasonal fluctuations, and prices for each are subject to substantial fluctuations as a result of numerous other factors. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." 12 14 ACREAGE The following table sets forth certain information with respect to the Company's developed and undeveloped leased acreage as of December 31, 2000. The leases in which the Company has an interest are for varying primary terms, and many require the payment of delay rentals to continue the primary term. The leases may be surrendered by the operator at any time by notice to the lessors, by the cessation of production, fulfillment of commitments, or by failure to make timely payments of delay rentals. Excluded from the table are the Company's interests in the properties subject to volumetric production payments.
DEVELOPED ACRES UNDEVELOPED ACRES ----------------- ----------------- STATE GROSS NET GROSS NET ----- ------- ------- ------- ------- Texas.......................................... 104,568 63,314 57,291 16,009 Louisiana...................................... 37,670 24,038 19,085 10,275 Montana........................................ 51,889 33,844 12,290 10,447 New Mexico..................................... 3,783 2,808 19,213 8,695 Oklahoma....................................... 56,188 23,900 3,125 1,150 Wyoming........................................ 62,035 58,695 92,197 89,799 Offshore....................................... 84,258 7,040 -- -- Other.......................................... 37,887 16,111 10,892 2,842 ------- ------- ------- ------- Total................................ 438,278 229,750 214,093 139,217 ======= ======= ======= =======
DRILLING ACTIVITIES All of the Company's drilling activities are conducted through arrangements with independent contractors. Certain information with regard to the Company's drilling activities during the years ended December 31, 2000, 1999 and 1998, is set forth below.
YEAR ENDED DECEMBER 31, ------------------------------------------ 2000 1999 1998 ------------ ------------ ------------ TYPE OF WELL GROSS NET GROSS NET GROSS NET ------------ ----- ---- ----- ---- ----- ---- Development: Oil........................................ 8 4.7 9 7.5 9 6.4 Natural gas................................ 58 33.2 45 19.5 33 16.2 Non-productive............................. 8 2.3 8 4.1 13 9.1 -- ---- -- ---- -- ---- Total.............................. 74 40.2 62 31.1 55 31.7 == ==== == ==== == ==== Exploratory: Oil........................................ 4 1.4 1 0.5 6 3.5 Natural gas................................ 9 1.9 9 4.4 3 2.2 Non-productive............................. 9 3.5 3 2.3 10 6.2 -- ---- -- ---- -- ---- Total.............................. 22 6.8 13 7.2 19 11.9 == ==== == ==== == ====
At December 31, 2000, the Company was participating in the drilling of 11 gross (3.1 net) wells. 13 15 PRODUCTION AND SALES The following table presents certain information with respect to oil and gas production attributable to the Company's properties and average sales prices during the three years ended December 31, 2000, 1999 and 1998.
YEAR ENDED DECEMBER 31, --------------------------- 2000 1999 1998 ------- ------- ------- Production: Gas (MMcf)................................................ 41,089 50,471 50,070 Oil (Mbbl)................................................ 1,306 1,286 1,650 Liquids (Mbbl)............................................ 264 122 96 Summary (MMcfe) Working interest....................................... 38,642 36,133 40,151 VPP.................................................... 11,866 22,786 20,396 ------- ------- ------- Total............................................. 50,508 58,919 60,547 Average Price: Gas (per Mcf)............................................. $ 3.69 $ 2.22 $ 2.11 Oil (per bbl)............................................. 27.35 16.04 11.41 Liquids (per bbl)......................................... 13.31 11.25 7.93 Total (per Mcfe).......................................... $ 3.77 $ 2.28 $ 2.07
OTHER FACILITIES Principal offices of the Company and its operating subsidiaries are leased in modern office buildings in Houston, Texas and Tulsa, Oklahoma. The Company believes that all of its property, plant and equipment are well maintained, in good operating condition and suitable for the purposes for which they are used. ITEM 3. LEGAL PROCEEDINGS. Information with respect to this Item is contained in Notes 2 (regarding bankruptcy proceedings) and 10 (regarding other litigation) to the Consolidated Financial Statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Beginning in November 2000, holders of KCS Energy, Inc. common stock ("stockholders") were solicited for a vote on (a) the Company's Third Amended Joint Plan of Reorganization and (b) the Second Amended Joint Plan of Reorganization proposed by the Official Committee of Unsecured Creditors ("Committee") and Credit Suisse First Boston Corporation. The voting record date was October 20, 2000 and the voting deadline was January 5, 2001. On December 26, 2000, the Company reached an agreement with the Committee and Credit Suisse First Boston on a consensual plan of reorganization. The terms of the consensual plan were included in the Company's Fourth Amended Joint Plan of Reorganization, which was submitted to stockholders and noteholders in January 2001. On January 30, 2001, it was announced that the stockholders and creditors accepted the Company's Fourth Amended Joint Plan of Reorganization (the "Plan") by the requisite vote and the Plan was confirmed by the United States Bankruptcy Court for the District of Delaware. See Note 2 to Consolidated Financial Statements and Management's Discussion and Analysis of Financial Condition and Results of Operations. The voting results were as follows: voting stockholders -- 14,593,210 shares for, 158,785 shares against; voting senior noteholders -- $135,960,000 in principal amount for; none against; voting senior subordinated noteholders -- $90,822,000 in principal amount for, $6,308,000 in principal amount against. In votes taken with respect to Plans of Reorganization under Chapter 11 of Title 11 of the United States Bankruptcy Code, abstentions and broker non-votes are not tabulated. However, based on the Company's calculations, 14,513,815 shares of the Company's common stock, $14,040,000 in principal amount of Senior Notes and $34,178,000 in principal amount of Senior Subordinated Notes were not voted. 14 16 PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. In accordance with the terms of its debt agreements, the Company is currently prohibited from paying cash dividends. See Note 5 to Consolidated Financial Statements. The Company paid regular quarterly dividends from the first quarter of 1992 through the first quarter of 1999. The last dividend for $585,000 was declared in December 1998 and paid in February 1999. The aggregate amount of dividends declared in 1998 was $2,345,000. There were 1,006 stockholders of record of the Company's Common Stock on March 1, 2001. The Company's Common Stock is traded on the New York Stock Exchange under the symbol KCS. Listed below are the high and low closing sales prices for the periods indicated:
2000 ---------------------------------------------- JAN.-MAR. APR.-JUNE JULY-SEPT. OCT.-DEC. --------- --------- ---------- --------- Market Price High........................................ $2.13 $1.50 $2.69 $4.38 Low......................................... 0.75 0.75 0.88 1.69
1999 ---------------------------------------------- JAN.-MAR. APR.-JUNE JULY-SEPT. OCT.-DEC. --------- --------- ---------- --------- Market Price High........................................ $3.25 $1.44 $1.25 $1.06 Low......................................... 1.25 0.38 0.63 0.63
15 17 ITEM 6. SELECTED FINANCIAL DATA. The following table sets forth the Company's selected financial data for each of the five years ended December 31, 2000.
2000 1999 1998(1) 1997(2) 1996 --------- --------- --------- -------- -------- DOLLARS IN THOUSANDS (EXCEPT PER SHARE DATA) Revenue...................... $ 191,989 $ 138,618 $ 131,324 $143,689 $108,374 Income (loss) from continuing operations................. 41,523 4,340 (296,520) (97,385) 21,717 Income (loss) from discontinued operations.... -- -- -- 5,302 (1,845) Net income (loss)............ 41,523 4,340 (296,520) (92,083) 19,872 Total assets................. 347,335 284,932 308,878 502,414 511,820 Debt......................... 351,705 381,819 410,335 292,445 310,347 Stockholders' equity (deficit).................. (108,320) (149,843) (154,204) 145,070 125,622 Per common share (Basic): Income (loss) from continuing operations... 1.42 0.15 (10.08) (3.37) 0.94 Income (loss) from discontinued operations.............. -- -- -- 0.18 (0.08) Net income (loss).......... 1.42 0.15 (10.08) (3.19) 0.86 Per common share (Diluted): Income (loss) from continuing operations... 1.42 0.15 (10.08) (3.37) 0.92 Income (loss) from discontinued operations.............. -- -- -- 0.18 (0.08) Net income (loss).......... 1.42 0.15 (10.08) (3.19) 0.84 Per common share: Stockholders' equity (deficit)............... (3.70) (5.12) (5.27) 4.93 5.42 Dividends.................. $ -- $ -- $ 0.08 $ 0.08 $ 0.06
--------------- (1) Includes $174.5 million after tax non-cash ceiling test writedowns of oil and gas assets and a $113.9 million reduction to zero of the book value of net deferred tax assets. Together, these adjustments accounted for $288.4 million, or $9.80 per share, of the 1998 loss. (2) Includes a $107.3 million after tax, or $3.72 per share, non-cash ceiling test writedown of oil and gas assets. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following is a discussion and analysis of the Company's financial condition and results of operations and should be read in conjunction with the Company's Consolidated Financial Statements (including the notes thereto) included elsewhere in this Form 10-K. GENERAL During 1998, due to very low prices for natural gas and crude oil and to disappointing performance of certain properties in the Rocky Mountain area, the Company incurred significant losses, primarily due to $268.5 million of pretax non-cash ceiling writedowns of its oil and gas assets and a reduction from $113.9 million to zero in the book value of net deferred tax assets. As a result of these non-cash charges, the net loss in 1998 increased by $288.4 million. Also as a result of these adjustments, the Company had negative stockholders' equity and was in default of certain covenants in its bank credit facilities. As a consequence, the Company was prohibited from borrowing under these facilities. In addition, the Company's independent public accountants issued modified reports for 1998 and 1999 with respect to the ability of the Company to 16 18 continue as a going concern, which also constituted a default under the bank credit agreements. The Company was also in default with respect to its Senior Notes and Senior Subordinated Notes after it did not make scheduled interest payments in July 1999. On January 18, 2000, the Bankruptcy Court entered an order granting KCS Energy, Inc. relief under the Bankruptcy Code and each of KCS' subsidiaries filed voluntary petitions under the Bankruptcy Code. See "Liquidity and Capital Resources" and Note 2 to Consolidated Financial Statements. In the second quarter of 1999, oil and gas prices began to recover. This recovery in prices, together with lower operating and general and administrative expenses and a successful capital investment program resulted in the Company returning to profitability in 1999. Net income in 1999 was $4.3 million, or $0.15 per share. Prices continued to strengthen in 2000 and the Company's performance and financial condition improved significantly. For the year ended December 31, 2000, the Company reported record earnings of $41.5 million, or $1.42 per share and cash flow from operating activities (before reorganization items) of $137.3 million, funded a $69.1 million capital investment program and increased its cash balances from $10.6 million at December 31, 1999 to $40.0 million at December 31, 2000. In addition, from the second quarter of 1999 through December 31, 2000, the Company reduced its bank debt by $73.3 million, reducing the outstanding principal balance from $150 million to $76.7 million. On January 30, 2001, the Bankruptcy Court confirmed the KCS Energy, Inc. plan of reorganization ("the Plan") under Chapter 11 of the Bankruptcy Code after the Company's creditors and stockholders voted to approve the Plan. On February 20, 2001, the Company completed the necessary steps for the Plan to go effective and emerged from bankruptcy. Under the Plan, the Company repaid its two bank credit facilities in full, paid past due interest on its Senior and Senior Subordinated Notes, including interest on interest, and repaid $60 million of Senior Notes. Trade creditors were paid in full and shareholders retained 100% of their common stock, subject to dilution from conversion of the new convertible preferred stock sold in connection with the Plan. See "Liquidity and Capital Resources" and Note 2 to Consolidated Financial Statements for more information regarding the Plan. Prices for oil and natural gas are subject to wide fluctuations in response to relatively minor changes in the supply of and demand for oil and natural gas, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include political conditions in the Middle East and elsewhere, domestic and foreign supply of oil and natural gas, the level of consumer demand, weather conditions and overall economic conditions. All references in the following discussion related to earnings per share are based upon the Company's diluted earnings per share. RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2000, 1999 AND 1998 Results of Operations Income before reorganization items for the year ended December 31, 2000 was $57.0 million compared to $4.3 million for the year ended December 31, 1999. This increase was attributable to significantly higher natural gas and oil prices together with lower operating and general and administrative expenses. Net income for the year ended December 31, 2000 was $41.5 million, or $1.42 per share, compared to net income of $4.3 million, or $0.15 per share, for the year ended December 31, 1999. Reorganization items totaled $15.4 million, of which $6.1 million was a non-cash write-off of deferred debt issuance costs associated with the Company's Senior Notes and Senior Subordinated Notes. The remainder of the reorganization items was primarily for legal and financial advisory services. Net income for the year ended December 31, 1999 was $4.3 million, or $0.15 per share, compared to a net loss of $296.5 million, or $10.08 per share, for the year ended December 31, 1998. The net loss in 1998 included a $174.5 million after-tax non-cash ceiling test writedown of oil and gas properties and a $113.9 million non-cash valuation allowance to reduce to zero the book value of net deferred tax assets. As a result of these charges, the 1998 net loss was increased by $288.4 million, or $9.80 per share. Excluding the effect of the 1998 non-cash asset writedowns, 1998 net loss was $8.1 million, or $0.28 per share. The 17 19 significant improvement in the 1999 results of operations reflected higher gas and oil prices together with lower operating and general and administrative costs, partially offset by higher interest expense and restructuring costs. Revenue
2000 1999 1998 -------- -------- -------- Production: Gas (MMcf)......................................... 41,089 50,471 50,070 Oil (Mbbl)......................................... 1,306 1,286 1,650 Liquids (Mbbl)..................................... 264 122 96 Summary (MMcfe) Working interest................................ 38,642 36,133 40,151 VPP............................................. 11,866 22,786 20,396 -------- -------- -------- Total...................................... 50,508 58,919 60,547 Average Price: Gas (per Mcf)...................................... $ 3.69 $ 2.22 $ 2.11 Oil (per bbl)...................................... 27.35 16.04 11.41 Liquids (per bbl).................................. 13.31 11.25 7.93 Total (per Mcfe)........................... $ 3.77 $ 2.28 $ 2.07 Revenue: Gas................................................ $151,293 $112,128 $105,778 Oil................................................ 35,711 20,624 18,824 Liquids............................................ 3,507 1,372 761 -------- -------- -------- Total...................................... $190,511 $134,124 $125,363 ======== ======== ========
Gas Revenue. In 2000, gas revenue increased $39.2 million to $151.3 million compared to $112.1 million in 1999 due to a 66% increase in average realized gas prices and a 7% increase in working interest production, partially offset by a 48% decrease in VPP production. The decrease in VPP production in 2000 was primarily attributable to the sale of VPP producing properties in mid-1999, the expiration of certain VPPs and limited investment in VPPs during the Chapter 11 reorganization. In 1999, gas revenue increased $6.3 million to $112.1 million compared to $105.8 million in 1998 primarily due to a 5% increase in average realized gas prices. Oil and Liquids Revenue. In 2000, oil and liquids revenue was $39.2 million compared to $22.0 million in 1999 due to the 71% increase in average realized oil prices and a 12% increase in production. In 1999, oil and liquids revenue was $22.0 million compared to $19.6 million in 1998. A 39% increase in average realized oil and liquids prices in 1999 added $7.6 million in revenue which was partially offset by a 19% decrease in production, due to the sale of producing properties and the restructuring of two contracts. Other Revenue, net. In 2000, other revenue included $1.0 million from the settlement of certain obligations related to a 1996 acquisition and $0.7 million from the sale of emission reduction credits. Other revenue in 1999 included $1.6 million from production tax refunds and adjustments, $1.5 million from the settlement of a production tax dispute, $0.8 million from the sale of emission reduction credits and $1.1 million from certain marketing and gathering net revenues incidental to the Company's oil and gas operations. Other revenue in 1998 included $4.0 million related to production tax refunds and approximately $2.0 million from marketing and gathering net revenues incidental to the Company's oil and gas exploration and production operations. 18 20 Lease Operating Expenses For the year ended December 31, 2000, lease operating expenses decreased 3% to $27.8 million, compared to $28.8 million in 1999. In 1999, lease operating expenses decreased 11% to $28.8 million, compared to $32.3 million in 1998. The lower expense levels in 2000 compared to 1999 and in 1999 compared to 1998 reflect cost-reduction initiatives taken by the Company and the sale of marginal higher-cost oil and gas properties. Production Taxes Production taxes, which are generally based on a fixed percentage of revenue (excluding VPP revenue), increased $3.1 million to $6.6 million in 2000 compared to 1999 primarily due to higher oil and gas prices and the attendant effect on revenue. Production taxes decreased $0.5 million to $3.5 million in 1999 compared to 1998 primarily due to lower non-VPP oil and gas revenue and production tax rates in the Rocky Mountain area. General and Administrative Expenses General and administrative expenses ("G&A") decreased $1.0 million to $8.8 million for the year ended December 31, 2000 compared to 1999. In 1999, G&A decreased $1.5 million to $9.8 million compared to 1998. Reduction in the Company's workforce and other cost reduction initiatives throughout the Company were the primary reasons for the decreases. Restructuring Costs Restructuring costs in 1999 were $1.9 million and consisted primarily of legal and financial advisory fees incurred in connection with the pursuit of a restructuring transaction. Such costs are reported as "Reorganization items" in 2000 pursuant to AICPA Statement of Position 90-7 "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code" ("SOP 90-7") and are discussed below. Depreciation, Depletion and Amortization The Company provides for depletion on its oil and gas properties using the future gross revenue method based on recoverable reserves valued at current prices. For the year ended December 31, 2000, depreciation, depletion and amortization ("DD&A") decreased $0.5 million to $50.5 million compared to 1999. For the year ended December 31, 1999, DD&A decreased $8.9 million to $51.0 million compared to 1998 mainly as a result of the decline in the average depletion rate to 36.8% compared to 46.6% in 1998, which was partially offset by higher oil and gas revenues. The significant decline in the depletion rate in 1999 was largely attributable to higher oil and gas prices and the 1998 writedown of oil and gas properties. 1998 Writedown of Oil and Gas Properties In accordance with the full cost accounting method and procedures prescribed by the Securities and Exchange Commission ("SEC"), capitalized costs of oil and gas properties net of accumulated amortization are limited to the sum of the present value of estimated future net revenues from proved oil and gas reserves at current prices, discounted at 10%, plus the lower of cost or fair value of unproved properties. To the extent that the capitalized costs exceed this limitation at the end of any fiscal quarter, such excess costs are charged to expense. The SEC precludes the reversal of such charges to expense if conditions improve in subsequent periods. In 1998, the Company recorded a $268.5 million pretax non-cash ceiling writedown of its oil and gas properties mainly due to depressed natural gas and oil prices and the disappointing performance of certain properties in the Rocky Mountain region. This included approximately $65 million for price declines subsequent to December 31, 1998. Average realized natural gas prices were $2.15 per Mcf at December 31, 1998 and declined during the first part of 1999 to $1.67 per Mcf. 19 21 Interest Expense Interest expense was $41.5 million in 2000 compared to $40.0 million in 1999. In accordance with the Company's Plan of reorganization (See Note 2 to Consolidated Financial Statements), interest expense in 2000 includes $4.2 million of interest on past due interest, compounded semi-annually, with respect to the Company's Senior Notes and Senior Subordinated Notes. Lower average borrowings on the Company's bank debt resulted in a decrease in bank interest expense of $4.1 million in 2000 compared to 1999, partially offset by higher average interest rates in 2000. Interest expense increased $4.2 million to $40.0 million in 1999 compared to 1998. Of this increase, approximately $2.4 million was attributable to higher average borrowings, $0.4 million was attributable to higher average interest rates, with the remainder of the increase primarily attributable to less capitalized interest due to lower drilling activity in 1999 and increased amortization of deferred financing costs. Reorganization Items During 2000, the Company recorded $15.4 million of net reorganization items, $6.1 million of which was a non-cash write-off of deferred debt issuance costs associated with the Company's Senior Notes and Senior Subordinated Notes in accordance with SOP 90-7. The balance reflects restructuring costs of $10.3 million primarily for legal and financial advisory services. The Company earned interest income of $1.0 million on cash accumulated during the Chapter 11 proceedings which partially offset the foregoing charges. Income Taxes No income tax expense was recorded in 2000 or in 1999 related to the Company's pretax book income. The income tax effect of the pretax book income was reflected as a reversal of a portion of the valuation allowance of the Company's net deferred tax assets. See Note 8 to Consolidated Financial Statements. Income tax expense was $16.0 million in 1998, which reflected the establishment of a valuation allowance to reduce to zero the book value of net deferred tax assets. Due to the significant losses recorded in 1998 and the uncertainty of future oil and natural gas commodity prices, management concluded at that time that this valuation allowance was required in accordance with SFAS No. 109. In making its assessment, management considered several factors, including the uncertainty in the Company's ability to generate sufficient income in order to realize its future tax benefits, and concluded that the Company could no longer consider the realization of its net deferred tax assets "more likely than not." The valuation allowance will be monitored for potential adjustments as future events so indicate. LIQUIDITY AND CAPITAL RESOURCES Reorganization The Company's liquidity and financial condition improved significantly in the year 2000. The Company reported earnings of $41.5 million, or $1.42 per share and cash flow from operating activities (before reorganization items) of $137.3 million, funded a $69.1 million capital investment program and increased its cash balances from $10.6 million at December 31, 1999 to $40.0 million at December 31, 2000. In addition, since the second quarter of 1999, the Company reduced its bank debt by $73.3 million, reducing the outstanding principal balance from $150.0 million to $76.7 million. On January 30, 2001, the Bankruptcy Court confirmed the Company's Plan of reorganization under Chapter 11 of the Bankruptcy Code. On February 20, 2001, the Company completed the necessary steps for the Plan to go effective and emerged from bankruptcy. Under the terms of the Plan, the Company: 1) secured a new exit facility in the form of a volumetric production payment ("VPP") and repaid all amounts outstanding under its existing bank credit facilities, 2) sold $30.0 million of new convertible preferred stock, 3) paid to the holders of the Company's 11% Senior Notes, on a pro rata basis, cash equal to the sum of (a) $60.0 million plus the amount of past due accrued and 20 22 unpaid interest of $15.1 million on $60.0 million of the Senior Notes as of the effective date, compounded semi-annually at 11% per annum and (b) the amount of past due accrued and unpaid interest of $21.5 million on $90.0 million of the Senior Notes as of January 15, 2001, compounded semi-annually at 11% per annum, 4) paid to the holders of the Company's 8 7/8% Senior Subordinated Notes, cash in the amount of past due accrued and unpaid interest of $23.7 million as of January 15, 2001, compounded semi-annually at 8 7/8% per annum, 5) renewed the remaining outstanding $90.0 million principal amount of Senior Notes and $125.0 million principal amount of Senior Subordinated Notes under amended indentures governing the Senior Notes and Senior Subordinated Notes, but without a change in interest rates (See Note 5 to Consolidated Financial Statements), and 6) paid pre-petition trade creditors in full. Shareholders retained 100% of their common stock, subject to dilution from conversion of the new convertible preferred stock. The VPP exit facility covered approximately 43.1 Bcfe (38.3 Bcf of gas and 797,000 barrels of oil) of proved reserves to be delivered in accordance with an agreed schedule over the next five years. Net proceeds from the sale of this VPP were approximately $176 million. In connection with the VPP, the Company terminated certain hedge instruments related to property interests conveyed for a cash payment of $28.0 million. The following illustrates the Company's condensed balance sheet as of December 31, 2000 as adjusted to reflect the implementation of the Plan as if it had occurred as of December 31, 2000.
DECEMBER 31, 2000 ----------------------- AS ADJUSTED ACTUAL ----------- --------- Cash and cash equivalents................................... $ 19,564 $ 39,994 Other current assets........................................ 51,651 51,651 Property, plant and equipment............................... 254,900 254,900 Deferred charges and other assets........................... 28,785 790 --------- --------- Total Assets...................................... $ 354,900 $ 347,335 ========= ========= Other current liabilities................................... $ 42,415 $ 42,415 --------- --------- Short-term debt............................................. -- 76,705 Senior notes................................................ 90,000 150,000 Senior subordinated notes................................... 125,000 125,000 --------- --------- Total debt........................................ 215,000 351,705 Accrued interest on public debt............................. -- 58,198 Pre-petition accounts payable............................... -- 1,978 Deferred revenue (VPP)...................................... 175,688 -- Deferred credits and other liabilities...................... 1,359 1,359 Convertible preferred stock................................. 30,000 -- Stockholders' (deficit) equity.............................. (109,562) (108,320) --------- --------- $ 354,900 $ 347,335 ========= =========
As a result of the Company's performance in 2000 and its emergence from bankruptcy in February 2001, the Company's independent public accountants issued an unqualified report for 2000. For 1998 and 1999, the Company's independent public accountants issued modified reports with respect to the ability of the Company to continue as a going concern. Cash Flow from Operating Activities For the year ended December 31, 2000, net income adjusted for non-cash charges and reorganization items increased 87% to $109.0 million compared to $58.2 million in the prior year, primarily due to higher average realized natural gas and oil prices, lower lease operating costs and lower G&A. Net cash provided by operating activities before reorganization items increased 92% to $137.3 million compared to $71.5 million in 1999. The net increase in accounts payable and accrued liabilities, inclusive of accrued interest in 2000 21 23 compared to 1999 was primarily due to accrued interest on the Senior Notes and Senior Subordinated Notes and accrued restructuring costs. Net income adjusted for non-cash charges increased to $58.2 million for the year ended December 31, 1999, compared to $53.1 million in 1998. Net cash provided by operating activities was $71.5 million during 1999, compared to $44.0 million for 1998. The increase reflects higher average realized natural gas and oil prices and lower operating and G&A expenses, partially offset by higher interest and restructuring costs. The remainder of the increase in 1999 cash flow from operating activities, compared to 1998, was largely attributable to the non-payment of $13.8 million on July 15, 1999 of accrued interest on the Senior Notes and Senior Subordinated Notes and the timing of cash receipts and disbursements. Investing Activities During 2000, the Company's oil and gas capital expenditures were $62.6 million of which $36.0 million was for development activities; $7.3 million for the acquisition of proved reserves and $19.3 million for lease acquisitions, seismic surveys and exploratory drilling. Other capital expenditures were $6.5 million of which $6.2 million was for the construction of a gas processing facility. Capital expenditures for the year ended December 31, 1999 were $60.2 million, of which $25.2 million was for development activities; $25.8 million for the acquisition of proved reserves; $9.0 million for lease acquisitions, seismic surveys and exploratory drilling, and $0.2 million for other assets. Capital expenditures for the year ended December 31, 1998 were $165.5 million, of which $66.8 million was for development drilling; $73.5 million for the acquisition of proved reserves under the Company's VPP program; $23.1 million for lease acquisitions, seismic surveys and exploratory drilling, and $2.1 million for other assets. Capital expenditures for 2001 are currently budgeted at $80.0 million. The Company believes that its cash flow from operations should be sufficient to meet its short-term operating requirements and that it has sufficient resources available to support its business and long-term growth strategies. However, there can be no assurance that the Company can continue to maintain its current production levels through oil and gas reserve replacement. 22 24 MARKET RISK DISCLOSURE The Company has utilized, and may continue to utilize, swaps, collars, futures contracts and options to manage the price risk associated with the production of natural gas and oil. During 2000, the Company accounted for these transactions as hedges and, accordingly, gains or losses were deferred until the underlying product is produced. These hedging arrangements have the effect of fixing for specified periods the prices the Company will receive for the volumes to which the hedge relates. While these hedging arrangements are structured to reduce the Company's exposure to decreases in the price associated with the underlying commodity, they also limit the benefit the Company might otherwise have received from any price increases associated with the hedged commodity. In accordance with Item 305 of Regulation S-K, the Company has elected the tabular method to disclose market-risk related to derivative financial instruments as well as other financial instruments. The following table sets forth the Company's hedged positions at December 31, 2000. The Company accounts for oil and natural gas futures contracts, options and commodity price swaps in accordance with SFAS No. 80 "Accounting for Futures Contracts." See Notes 1 and 9 to the Consolidated Financial Statements for a further discussion of the Company's accounting policy related to these contracts.
COLLARS (PRICES PER MMBTU) SWAPS ---------------------------- ----------------------------------------------- FLOORS FROM $2.70 TO $5.25 @ $2.055 PER MMBTU @ $5.04 PER MMBTU CEILINGS FROM $4.00 TO $6.98 ---------------------- --------------------- ---------------------------- UNREALIZED UNREALIZED UNREALIZED VOLUME LOSS VOLUME GAIN (LOSS) VOLUME LOSS --------- ---------- ------- ----------- ----------- ------------ MMBTU ($000'S) MMBTU ($000'S) MMBTU ($000'S) 2001 1st Qtr. .......... 750,000 (5,595) 90,000 (403) 3,605,000 (16,734) 2nd Qtr. .......... 750,000 (2,754) 90,000 (63) -- -- 3rd Qtr. .......... 750,000 (2,474) 90,000 (28) -- -- 4th Qtr. .......... 750,000 (2,520) -- -- -- -- --------- ------- ------- ---- --------- ------- Total...... 3,000,000 (13,343) 270,000 (494) 3,605,000 (16,734) 2002................. 2,520,000 (6,106) -- -- -- -- 2003................. 2,040,000 (3,704) -- -- -- -- 2004................. 1,680,000 (3,284) -- -- -- -- 2005................. 1,120,000 (2,178) -- -- -- --
In connection with the Company's Plan of reorganization and the related production payment financing discussed in Note 2 to Consolidated Financial Statements, all of the above $2.055 swaps were repurchased in February 2001 for approximately $28 million. The Company uses fixed and variable rate long-term debt to finance the Company's capital spending program. These debt arrangements expose the Company to market risk related to changes in interest rates. The Company's weighted average interest rate on its fixed rate debt of $275.0 million at December 31, 2000 was 10.0%. The weighted average interest rate on its variable rate debt of $76.7 million at December 31, 2000 was 9.5%. 23 25 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To KCS Energy, Inc.: We have audited the accompanying consolidated balance sheets of KCS Energy, Inc. (a Delaware Corporation) and subsidiaries as of December 31, 2000 and 1999, and the related statements of consolidated operations, stockholders' (deficit) equity and cash flows for each of the three years in the period ended December 31, 2000. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of KCS Energy, Inc. and subsidiaries as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States. ARTHUR ANDERSEN LLP Houston, Texas March 15, 2001 24 26 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED OPERATIONS (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
FOR THE YEAR ENDED DECEMBER 31, ------------------------------- 2000 1999 1998 -------- -------- --------- Oil and gas revenue......................................... $190,511 $134,124 $ 125,363 Other revenue, net.......................................... 1,478 4,494 5,961 -------- -------- --------- Total revenue..................................... 191,989 138,618 131,324 Operating costs and expenses Lease operating expenses.................................. 27,801 28,751 32,306 Production taxes.......................................... 6,605 3,524 3,996 General and administrative expenses....................... 8,817 9,847 11,327 Restructuring costs....................................... -- 1,886 -- Depreciation, depletion and amortization.................. 50,451 50,967 59,888 Writedown of oil and gas properties....................... -- -- 268,468 -------- -------- --------- Total operating costs and expenses................ 93,674 94,975 375,985 -------- -------- --------- Operating income (loss)..................................... 98,315 43,643 (244,661) Interest and other income (expense), net.................... 101 702 (73) Interest expense (contractual interest for 2000 was $36,220).................................................. (41,460) (40,005) (35,787) -------- -------- --------- Income (loss) before reorganization items and income taxes..................................................... 56,956 4,340 (280,521) Reorganization items Write-off of deferred debt issuance costs related to senior notes and senior subordinated notes............. (6,132) -- -- Financial restructuring costs............................. (10,334) -- -- Interest income........................................... 1,033 -- -- -------- -------- --------- Reorganization items, net......................... (15,433) -- -- -------- -------- --------- Income (loss) before income taxes........................... 41,523 4,340 (280,521) Federal and state income taxes.............................. -- -- 15,999 -------- -------- --------- Net income (loss)........................................... $ 41,523 $ 4,340 $(296,520) ======== ======== ========= Net income (loss) per share of common stock Basic and Diluted......................................... $ 1.42 $ 0.15 $ (10.08) ======== ======== ========= Average shares outstanding for computation of earnings per share Basic..................................................... 29,266 29,263 29,428 Diluted................................................... 29,305 29,288 29,428 ======== ======== =========
The accompanying notes are an integral part of these financial statements. 25 27 KCS ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
DECEMBER 31, --------------------- 2000 1999 --------- --------- ASSETS Current assets Cash and cash equivalents................................. $ 39,994 $ 10,584 Trade accounts receivable................................. 45,954 21,941 Other current assets...................................... 5,697 7,571 --------- --------- Current assets.................................... 91,645 40,096 --------- --------- Property, plant and equipment Oil and gas properties, full cost method, less accumulated DD&A -- 2000 $780,512; 1999 $731,496................... 245,169 232,281 Other property, plant and equipment, at cost less accumulated depreciation -- 2000 $7,345; 1999 $5,930... 9,731 4,686 --------- --------- Property, plant and equipment, net................ 254,900 236,967 --------- --------- Deferred charges and other assets........................... 790 7,869 --------- --------- $ 347,335 $ 284,932 ========= ========= LIABILITIES AND STOCKHOLDERS' (DEFICIT) EQUITY Current liabilities Accounts payable.......................................... $ 22,974 $ 13,340 Accrued interest on public debt........................... -- 26,444 Other accrued liabilities................................. 19,441 11,262 Short-term debt........................................... 76,705 381,819 --------- --------- Current liabilities............................... 119,120 432,865 --------- --------- Deferred credits and other liabilities...................... 1,359 1,910 --------- --------- Liabilities subject to compromise: Senior notes.............................................. 150,000 -- Senior subordinated notes................................. 125,000 -- Accrued interest on public debt........................... 58,198 -- Pre-petition accounts payable............................. 1,978 -- --------- --------- Liabilities subject to compromise................. 335,176 -- --------- --------- Commitments and contingencies............................... --------- --------- Preferred stock, authorized 5,000,000 shares -- unissued.... -- -- --------- --------- Stockholders' (deficit) equity Common stock, par value $0.01 per share, authorized 50,000,000 shares; issued 31,433,006 and 31,435,406, respectively........................................... 314 314 Additional paid-in capital................................ 145,098 145,098 Retained (deficit) earnings............................... (248,991) (290,514) Less treasury stock, 2,167,096 shares, at cost............ (4,741) (4,741) --------- --------- Stockholders' (deficit) equity.................... (108,320) (149,843) --------- --------- $ 347,335 $ 284,932 ========= =========
The accompanying notes are an integral part of these financial statements. 26 28 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED STOCKHOLDERS' (DEFICIT) EQUITY (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
ADDITIONAL RETAINED STOCKHOLDERS' COMMON PAID-IN (DEFICIT) TREASURY (DEFICIT) STOCK CAPITAL EARNINGS STOCK EQUITY ------ ---------- --------- -------- ------------- Balance at December 31, 1997............ $312 $144,135 $ 4,011 $(3,388) $ 145,070 Stock issuances -- option and benefit plans.............................. 2 489 -- -- 491 Tax benefit on stock option exercises.......................... -- 453 -- -- 453 Net loss.............................. -- -- (296,520) -- (296,520) Dividends ($0.08 per share)........... -- -- (2,345) -- (2,345) Purchase of treasury stock............ -- -- -- (1,353) (1,353) ---- -------- --------- ------- --------- Balance at December 31, 1998............ 314 145,077 (294,854) (4,741) (154,204) Stock issuances -- option and benefit plans.............................. -- 21 -- -- 21 Net income............................ -- -- 4,340 -- 4,340 ---- -------- --------- ------- --------- Balance at December 31, 1999............ 314 145,098 (290,514) (4,741) (149,843) Net income............................ -- -- 41,523 -- 41,523 ---- -------- --------- ------- --------- Balance at December 31, 2000............ $314 $145,098 $(248,991) $(4,741) $(108,320) ==== ======== ========= ======= =========
The accompanying notes are an integral part of these financial statements. 27 29 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (DOLLARS IN THOUSANDS)
FOR THE YEAR ENDED DECEMBER 31, ------------------------------- 2000 1999 1998 -------- -------- --------- Cash flows from operating activities: Net income (loss)......................................... $ 41,523 $ 4,340 $(296,520) Non-cash charges (credits): Depreciation, depletion and amortization............... 50,451 50,967 59,888 Writedown of oil and gas properties.................... -- -- 268,468 Deferred income taxes.................................. -- -- (94,992) Tax valuation allowance................................ -- -- 113,944 Other non-cash charges and credits, net................ 1,640 2,862 2,291 Reorganization items................................... 15,433 -- -- -------- -------- --------- 109,047 58,169 53,079 Net changes in assets and liabilities: Trade accounts receivable.............................. (24,013) 14,607 3,567 Other current assets................................... 1,874 (1,921) 1,102 Accounts payable and accrued liabilities............... 19,791 (12,018) (19,400) Accrued interest on public debt........................ 31,754 13,797 5,085 Other, net............................................. (1,145) (1,171) 1,052 -------- -------- --------- Net cash provided by operating activities before reorganization items...................................... 137,308 71,463 44,485 Reorganization items (excluding non-cash write-off of deferred debt issuance costs)............................. (9,301) -- -- -------- -------- --------- Net cash provided by operating activities................... 128,007 71,463 44,485 -------- -------- --------- Cash flows from investing activities: Investment in oil and gas properties...................... (62,598) (60,000) (163,396) Proceeds from the sale of oil and gas properties.......... 694 27,718 6,962 Investment in other property, plant and equipment, net.... (6,480) 840 (2,082) -------- -------- --------- Net cash used in investing activities....................... (68,384) (31,442) (158,516) -------- -------- --------- Cash flows from financing activities: Proceeds from borrowings.................................. 292 16,300 276,600 Repayments of debt........................................ (30,414) (44,905) (158,800) Issuance of common stock.................................. -- 21 491 Purchase of treasury stock................................ -- -- (1,353) Dividends paid............................................ -- (585) (2,347) Deferred financing costs and other, net................... (91) (1,144) (4,486) -------- -------- --------- Net cash provided by (used in) financing activities......... (30,213) (30,313) 110,105 -------- -------- --------- Increase (decrease) in cash and cash equivalents............ 29,410 9,708 (3,926) Cash and cash equivalents at beginning of year.............. 10,584 876 4,802 -------- -------- --------- Cash and cash equivalents at end of year.................... $ 39,994 $ 10,584 $ 876 ======== ======== =========
The accompanying notes are an integral part of these financial statements. 28 30 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES KCS Energy, Inc. is an independent oil and gas company engaged in the acquisition, exploration, exploitation and production of natural gas and crude oil. Basis of Presentation The consolidated financial statements include the accounts of KCS Energy, Inc. and its wholly owned subsidiaries ("KCS" or "Company"). All significant intercompany accounts and transactions have been eliminated in consolidation. Certain previously reported amounts have been reclassified to conform to current year presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. As explained in Note 2, during 1999 and 2000 there were uncertainties regarding the Company's ability to continue as a going concern and, as a result, in 2000 the Company prepared its financial statements pursuant to AICPA Statement of Position No. 90-7 "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code" ("SOP 90-7"). Since these uncertainties no longer exist, the financial statements for periods ending after February 20, 2001 will be prepared assuming the Company will continue as a going concern. Cash Equivalents The Company considers as cash equivalents all highly liquid investments with a maturity of three months or less from date of purchase. Cash included balances of $1.5 million and $0.8 million at December 31, 2000 and 1999, respectively that were restricted to funding expenditures on certain oil and gas properties. Derivative Instruments The Company utilizes oil and natural gas futures contracts and commodity price swaps for the purpose of hedging the risks associated with fluctuating crude oil and natural gas prices. The Company accounted for such contracts in accordance with Statement of Financial Accounting Standard ("SFAS") No. 80 "Accounting for Futures Contracts" through December 31, 2000. These contracts permitted settlement by delivery of commodities and, therefore, were not financial instruments as defined by SFAS Nos. 107 and 119. Changes in the market value of these transactions were deferred until the sale of the underlying production was recognized. See Note 9 for further discussion of the Company's price risk management activities. In June 1998, the Financial Accounting Standards Board issued SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133, as amended, establishes new accounting and disclosure standards requiring that all derivative instruments be recorded in the balance sheet as an asset or liability, measured at fair value. SFAS No. 133 requires that changes in a derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Accounting for qualifying hedges allows gains and losses on a derivative instrument to be recognized with the related physical results of the hedged item in the income statement during the period of actual production. It also requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. The Company adopted this statement on January 1, 2001. Upon adopting SFAS No. 133 on January 1, 2001, the Company elected not to designate the existing derivatives as hedges. Accordingly, on January 1, 2001, the Company recorded a liability of $43.8 million representing the fair market value of its derivative instruments on that date and an after-tax loss from the cumulative effect of a change in accounting principle of $28.5 million. In February 2001, the Company 29 31 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) terminated certain derivative instruments discussed above related to its exit financing in connection with emergence from bankruptcy for a cash payment of $28 million which will be offset against the accrued liability to be recorded in connection with the implementation of SFAS No. 133. See Note 2. Imbalances The Company follows the sales method of accounting for natural gas revenues whereby revenues are recognized based on volume sold to the purchaser. The volume of gas sold may differ from the volume to which KCS is entitled based on its working interest. There were no material imbalances at December 31, 2000. Property, Plant and Equipment The Company follows the full cost method of accounting under which all costs incurred in acquisition, exploration and development activities are capitalized in a country-wide cost center. Such costs include lease acquisitions, geological and geophysical services, drilling, completion, equipment and certain general and administrative costs directly associated with acquisition, exploration and development activities. Interest costs related to unproved properties are also capitalized. General and administrative costs related to production and general overhead are expensed as incurred. The Company provides for depreciation, depletion and amortization of evaluated costs using the future gross revenue method based on recoverable reserves valued at current prices. Capitalized costs of oil and gas properties net of accumulated amortization and related deferred taxes are limited to the sum of the present value of estimated future net revenues from proved oil and gas reserves at current prices discounted at 10% plus the lower of cost or fair value of unproved properties. To the extent that the capitalized costs exceed this limitation at the end of any quarter, such excess is expensed. For the year ended December 31, 1998, the Company recorded a $268.5 million pretax non-cash ceiling writedown of its oil and gas properties. See Note 2 and "Management's Discussion and Analysis of Financial Condition and Results of Operations." Costs of unevaluated properties excluded from amortization were $5.6 million and $8.4 million at December 31, 2000 and 1999, respectively. Such costs relate to acquisitions and exploration efforts for which proved reserves have not been established. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. Proceeds from dispositions of oil and gas properties are credited to the cost center without recognition of gains or losses. Depreciation of other property, plant and equipment is provided on a straight-line basis over the estimated useful lives of the assets. Repairs of all property, plant and equipment and replacements and renewals of minor items of property are charged to expense as incurred. Transportation Costs In September 2000, the EITF reached a consensus on EITF Issue 00-10, "Accounting for Shipping and Handling Fees and Costs." Pursuant to the consensus, amounts paid related to certain transportation must be reported as an expense on the income statement rather than reporting revenues net of transportation as has been industry practice. In accordance with EITF Issue 00-10, the Company recorded transportation related amounts of $3.0 million, $2.1 million and $1.9 million in lease operating expenses with a corresponding increase to oil and gas revenue for 2000, 1999 and 1998, respectively. 30 32 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Income Taxes The Company accounts for income taxes in accordance with SFAS No. 109 "Accounting for Income Taxes." Deferred income taxes are recorded to reflect the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts at each year end. A valuation allowance is recognized if at the time it is anticipated that some or all of a deferred tax asset may not be realized. Earnings Per Share Basic earnings per share were computed by dividing net income by the weighted average number of common shares outstanding during the year as required by SFAS No. 128 "Earnings per Share." Diluted earnings per share have been computed by dividing net income by the weighted average number of common shares outstanding plus the incremental shares that would have been outstanding assuming the exercise of stock options. A reconciliation of shares used for basic earnings per share and those used for diluted earnings per share is as follows:
YEAR ENDED DECEMBER 31, ------------------------ 2000 1999 1998 ------ ------ ------ (AMOUNTS IN THOUSANDS) Average common stock outstanding............................ 29,266 29,263 29,428 Common stock equivalents.................................... 39 25 248 ------ ------ ------ Average common stock and common stock equivalents outstanding............................................... 29,305 29,288 29,676 ====== ====== ======
Common stock equivalents are not applicable for 1998 earnings per share as they would be anti-dilutive. Segment Reporting The Company operates in one reportable segment, as an independent oil and gas company engaged in the acquisition, exploration, exploitation and production of domestic oil and gas properties. The Company's operations are conducted entirely in the United States. No customer accounted for more than 10% of the Company's revenues in 2000, 1999 or 1998. Concentrations of Credit Risk The Company extends credit, primarily in the form of monthly oil and gas sales and joint interest owners receivables, to various companies in the oil and gas industry, which results in a concentration of credit risk. The concentration of credit risk may be affected by changes in economic or other conditions and may accordingly impact the Company's overall credit risk. However, the Company believes that the risk associated with these unsecured receivables is mitigated by the size and reputation of the companies to which the Company extends credit. 2. REORGANIZATION On January 30, 2001, the United States Bankruptcy Court for the District of Delaware (the "Bankruptcy Court") confirmed the KCS Energy, Inc. plan of reorganization ("the Plan") under Chapter 11 of Title 11 of the United States Bankruptcy Code after the Company's creditors and stockholders voted to approve the Plan. On February 20, 2001, the Company completed the necessary steps for the Plan to go effective and emerged from bankruptcy having reduced its debt from a peak of $425.0 million in early 1999 to $215.0 million and having cash on hand in excess of $30 million. During 2000 and until the Plan was effective, the Company conducted its operations and reported its results of operations and financial position as a debtor-in-possession pursuant to SOP 90-7. In connection therewith, the Company reported all liabilities which it deemed subject to compromise at amounts reasonably expected to be paid. 31 33 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Under the terms of the Plan the Company: 1) secured a new exit facility in the form of a volumetric production payment ("VPP") and repaid all amounts outstanding under its existing bank credit facilities, 2) sold $30.0 million of new convertible preferred stock, 3) paid to the holders of the Company's 11% Senior Notes, on a pro rata basis, cash equal to the sum of (a) $60.0 million plus the amount of past due accrued and unpaid interest of $15.1 million on $60.0 million of the Senior Notes as of the effective date, compounded semi-annually at 11% per annum and (b) the amount of past due accrued and unpaid interest of $21.5 million on $90.0 million of the Senior Notes as of January 15, 2001, compounded semi-annually at 11% per annum, 4) paid to the holders of the Company's 8 7/8% Senior Subordinated Notes, cash in the amount of past due accrued and unpaid interest of $23.7 million as of January 15, 2001, compounded semi-annually at 8 7/8% per annum, 5) renewed the remaining outstanding $90.0 million principal amount of Senior Notes and $125.0 million principal amount of Senior Subordinated Notes under amended indentures governing the Senior Notes and Senior Subordinated Notes, but without a change in interest rates (See Note 5), and 6) paid pre-petition trade creditors in full. Shareholders retained 100% of their common stock, subject to dilution from conversion of the new convertible preferred stock. The VPP exit facility covers approximately 43.1 Bcfe (38.3 Bcf of gas and 797,000 barrels of oil) of proved reserves to be delivered in accordance with an agreed schedule over the next five years. Net proceeds from the sale of this VPP were approximately $176 million. In connection with the VPP, the Company terminated certain derivative instruments related to property interests conveyed for a cash payment of $28.0 million. The following illustrates the Company's condensed balance sheet as of December 31, 2000 as adjusted to reflect the implementation of the Plan.
DECEMBER 31, 2000 ----------------------- AS ADJUSTED ACTUAL ----------- --------- Cash and cash equivalents................................... $ 19,564 $ 39,994 Other current assets........................................ 51,651 51,651 Property, plant and equipment............................... 254,900 254,900 Deferred charges and other assets........................... 28,785 790 --------- --------- Total Assets...................................... $ 354,900 $ 347,335 ========= ========= Other current liabilities................................... $ 42,415 $ 42,415 --------- --------- Short-term debt............................................. -- 76,705 Senior notes................................................ 90,000 150,000 Senior subordinated notes................................... 125,000 125,000 --------- --------- Total debt........................................ 215,000 351,705 Accrued interest on public debt............................. -- 58,198 Pre-petition accounts payable............................... -- 1,978 Deferred revenue (VPP)...................................... 175,688 -- Deferred credits and other liabilities...................... 1,359 1,359 Convertible preferred stock................................. 30,000 -- Stockholders' (deficit) equity.............................. (109,562) (108,320) --------- --------- $ 354,900 $ 347,335 ========= =========
Background During 1998, due to very low prices for natural gas and crude oil and to disappointing performance of certain properties in the Rocky Mountain area, the Company incurred significant losses, primarily due to $268.5 million of pretax non-cash ceiling writedowns of its oil and gas assets and a reduction from 32 34 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) $113.9 million to zero in the book value of net deferred tax assets. As a result of these non-cash charges, the net loss in 1998 was increased by $288.4 million. Also as a result of these adjustments, the Company had negative stockholders' equity and was in default of certain covenants in its bank credit facilities. As a consequence, the Company was prohibited from borrowing under these facilities. In addition, the Company's independent public accountants issued modified reports for 1998 and 1999 with respect to the ability of the Company to continue as a going concern, which also constituted a default under the revolving bank credit agreements. Beginning in May 1999, the Company and its bank lenders entered into a series of forbearance agreements which provided, among other things, that the lenders would refrain from exercising certain of their rights and remedies as a result of existing defaults for a period of time and that the Company would make certain minimum monthly principal payments. From the time that the original forbearance agreements were entered into through December 31, 2000, the Company made principal payments to its banks of $73.3 million, reducing the outstanding loans from $150.0 million to $76.7 million. The forbearance agreements precluded the Company from making interest payments on its Senior Notes and Senior Subordinated Notes. From the commencement of the bankruptcy proceedings until the effective date of the Plan, the Company operated under a cash collateral agreement with its bank lenders. The cash collateral agreement provided, among other things, that the Company make monthly principal payments of $2.5 million and that the lenders have the right to review and approve the Company's projected use of cash during the bankruptcy proceedings. On December 28, 1999, the Company announced that it had reached an agreement on a proposed restructuring (the "Restructuring Agreement") with holders of more than two-thirds in amount of the Senior Subordinated Notes and holders of a majority in amount of the Senior Notes. To effectuate the Restructuring Agreement, the parties agreed that the Company would commence a case under Chapter 11 of the Bankruptcy Code by January 18, 2000. On January 5, 2000, however, certain entities filed an involuntary petition for relief against KCS Energy, Inc. (the parent company only) under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On January 18, 2000, the Bankruptcy Court entered an order granting KCS relief under Chapter 11 of the Bankruptcy Code. Also on January 18, 2000, each of KCS Energy Inc.'s subsidiaries filed voluntary petitions under Chapter 11 of the Bankruptcy Code with the Bankruptcy Court. During the bankruptcy proceedings the Company, the statutory committee of unsecured creditors (the "Committee") and Credit Suisse First Boston filed several proposed plans of reorganization with the Bankruptcy Court. Throughout the proceedings, the Company discussed alternatives with the Committee, holders of its Senior Notes and Senior Subordinated Notes and others with the goal of achieving a consensual plan of reorganization. On December 26, 2000, the Company, the Committee and Credit Suisse First Boston reached agreement on the Plan. The Company's performance and financial condition improved significantly in the year 2000. The Company reported record earnings of $41.5 million and cash flow from operating activities (before reorganization items) of $137.3 million, funded a $69.1 million capital investment program, significantly reduced its bank debt and increased its cash balances from $10.6 million at December 31, 1999 to $40.0 million at December 31, 2000. With the completion in February 2001 of the Plan, the Company believes that it will be able to meet its obligations and commitments in the normal course and conduct business as a going concern. Accordingly, the Company will discontinue presenting its financial statements pursuant to SOP 90-7 in 2001. 3. RETIREMENT BENEFIT PLANS The Company sponsors a Savings and Investment Plan ("Savings Plan") under Section 401(k) of the Internal Revenue Code. Eligible employees may contribute up to 16% of their base salary to the Savings Plan subject to certain IRS limitations. The Company may make matching contributions, which have been set by the Board of Directors at 50% of the employee's contribution (up to 6% of the employee's compensation, 33 35 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) subject to certain regulatory limitations). The Savings Plan also contains a profit-sharing component whereby the Board of Directors may declare annual discretionary profit-sharing contributions. Profit-sharing contributions are allocated to eligible employees based upon their pro-rata share of total eligible compensation. Contributions to the Savings Plan are invested at the direction of the employee in one or more funds or can be directed to purchase common stock of the Company at fair market value. Eligible employees vest in both the Company matching and discretionary profit-sharing contributions over a four-year period based upon years of service with the Company. Company contributions to the Savings Plan were $454,341 in 2000, $221,520 in 1999 and $393,851 in 1998. These amounts are included in general and administrative expenses. 4. STOCK OPTION AND INCENTIVE PLANS On February 20, 2001 in connection with the Company's Plan of reorganization, the Company's 1992 Stock Plan and the 1994 Directors' Stock Plan and all outstanding options thereunder were cancelled. The Plan was accepted by the Company's creditors and stockholders and confirmed by the Bankruptcy Court on January 30, 2001. See Note 2. As part of the Plan, the KCS Energy, Inc. 2001 Employees and Directors Stock Plan ("2001 Stock Plan") was adopted. The 2001 Stock Plan provides that stock options, stock appreciation rights, restricted stock and bonus stock may be granted to employees of KCS and that stock options and retainer stock may be granted to non-employee directors. Grants for up to 4,362,868 shares of KCS common stock may be made under the 2001 Stock Plan. The Company has an employee stock purchase program (the "Program") whereby all eligible employees and directors may purchase full shares from the Company at a price per share equal to 90% of the market value determined by the closing price on the date of purchase. The minimum purchase is 25 shares. The maximum annual purchase is the number of shares costing no more than 10% of the eligible employee's annual base salary, and for directors, 6,000 shares. The number of shares issued in connection with the Program was 100, 14,775 and 44,661 during 2000, 1999 and 1998, respectively. This plan was suspended by the board of directors in May 2000. At December 31, 2000, there were 798,008 shares available for issuance under the Program. Information Related to Cancelled Plans The following disclosures relate to the cancelled 1992 Stock Plan and the 1994 Directors Stock Plan. While these plans and the options outstanding thereunder were cancelled on February 20, 2001, such disclosures are required since the plans were in effect at December 31, 2000. The 1992 Stock Plan provided that stock options, stock appreciation rights, restricted stock and bonus stock could be granted to employees of KCS. The 1994 Directors' Stock Plan provided that each non-employee director be granted stock options for 2,000 shares annually. This plan also provided that in lieu of cash, each non-employee director be issued KCS stock with a fair market value equal to 50% of their annual retainer. In 1999, each non-employee director waived his annual retainer and in 2000 each non-employee director waived the stock portion of his retainer. Each plan provided that the option price of shares issued be equal to the market price on the date of grant and that all options expire 10 years after the date of grant. Restricted shares awarded under the 1992 Stock Plan had a fixed restriction period during which ownership of the shares could not be transferred and the shares were subject to forfeiture if employment terminated. Restricted stock has the same dividend and voting rights as other common stock and is considered to be currently issued and outstanding. The cost of the awards, determined as the fair market value of the shares at the date of grant, is expensed ratably over the period the restrictions lapse. Restricted stock totaling 32,600 shares was outstanding at December 31, 2000. 34 36 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) At December 31, 2000, a total of 544,752 shares were available for future grants under the 1992 Stock Plan and the 1994 Directors' Stock Plan. No grants were made pursuant to these plans in 2000 or 1999. As permitted under SFAS No. 123 "Accounting for Stock-Based Compensation" the Company has elected to continue to account for stock-based compensation under the provisions of APB Opinion No. 25 "Accounting for Stock Issued to Employees." Had compensation cost for the following plans been determined consistent with SFAS No. 123, the impact on the Company's net income (loss) would have been $2.0 million in 2000, $2.3 million in 1999 and $2.3 million in 1998. The impact on basic and diluted loss per share would have been $0.07 in 2000, $0.07 in 1999 and $0.08 in 1998. 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 used for grants in 1998: risk-free interest rate of 5.17%; expected dividend yield of 0.00%; expected life of 4.0 years; expected stock price volatility of 70.0%. As required under SFAS No. 123, a summary of the status of the stock options under the 1992 Stock Plan and the 1994 Directors' Stock Plan at December 31, 2000, 1999 and 1998 and changes during the years then ended is presented in the following tables:
2000 1999 1998 -------------------- -------------------- -------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE --------- -------- --------- -------- --------- -------- Outstanding at beginning of year....................... 1,519,630 $ 9.98 1,720,230 $10.37 1,063,800 $ 7.76 Granted...................... -- -- -- -- 899,300 12.57 Exercised.................... -- -- -- -- (123,320) 1.48 Forfeited.................... (141,200) 3.40 (200,600) 13.34 (119,550) 12.86 --------- ------ --------- ------ --------- ------ Outstanding at end of year... 1,378,430 10.66 1,519,630 9.98 1,720,230 10.37 --------- ------ --------- ------ --------- ------ Exercisable at end of year... 1,019,580 $10.03 899,355 $ 7.84 645,530 $ 5.93 --------- ------ --------- ------ --------- ------ Weighted average fair value of options granted......... $ -- $ -- $ 7.14 ====== ====== ======
The following table summarizes information about stock options outstanding at December 31, 2000:
NUMBER WEIGHTED AVERAGE WEIGHTED NUMBER WEIGHTED RANGE OF OUTSTANDING AT REMAINING AVERAGE EXERCISABLE AT AVERAGE EXERCISE PRICES DECEMBER 31, 2000 CONTRACTUAL LIFE EXERCISE PRICE DECEMBER 31, 2000 EXERCISE PRICE --------------- ----------------- ---------------- -------------- ----------------- -------------- $ 0.92-$ 3.12 120,000 0.93 $ 0.92 120,000 $ 0.92 3.13- 4.68 60,000 1.92 3.13 60,000 3.13 4.69- 7.01 385,000 6.98 5.70 243,750 5.87 7.02- 10.52 105,000 3.94 7.33 105,000 7.33 10.53- 18.81 708,430 6.34 16.13 490,830 15.75 ------------- --------- ---- ------ --------- ------ $ 0.92-$18.81 1,378,430 4.08 $10.66 1,019,580 $10.03 ============= ========= ==== ====== ========= ======
35 37 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. DEBT Debt consists of the following:
DECEMBER 31, ---------------------------------- AS ADJUSTED* ACTUAL ACTUAL 2000 2000 1999 ------------ -------- -------- (DOLLARS IN THOUSANDS) 11% Senior Notes.................................... $ 90,000 $150,000 $149,724 8 7/8% Senior Subordinated Notes.................... 125,000 125,000 125,000 Revolving Credit Agreement.......................... -- 34,241 49,501 Credit Facility..................................... -- 42,464 57,594 -------- -------- -------- Total debt................................ 215,000 351,705 381,819 Classified as short-term debt....................... -- 76,705 381,819 -------- -------- -------- Long-term debt...................................... $215,000 $275,000 $ -- ======== ======== ========
--------------- * As adjusted to reflect the implementation of the Company's Plan (See Note 2) as if the reorganization occurred on December 31, 2000. Senior Subordinated Notes On January 15, 1998, KCS Energy, Inc. (the "Parent") completed a public offering of $125.0 million of senior subordinated notes at an interest rate of 8 7/8% (the "Senior Subordinated Notes"). The Senior Subordinated Notes are noncallable for five years and are unsecured subordinated obligations of the Parent. The subsidiaries of the Parent have guaranteed the Senior Subordinated Notes on an unsecured subordinated basis. On February 20, 2001, in connection with the Company's Plan, the indenture governing the Senior Subordinated Notes was amended to, among other things, accelerate the maturity date of the Senior Subordinated Notes from January 15, 2008 to January 15, 2006. The Senior Subordinated Notes, as amended, contain certain restrictive covenants which, among other things, limit the Company's ability to incur additional indebtedness, require the repurchase of the Senior Subordinated Notes upon a change of control, and limit: a) the aggregate purchases and redemptions of the Company's Series A Convertible Preferred Stock for cash and b) the aggregate cash dividends paid on capital stock, collectively, to 50% of the Company's cumulative net income, as defined, during the period beginning after December 31, 2000. Senior Notes On January 25, 1996, KCS Energy, Inc. issued $150.0 million principal amount of 11% senior notes due 2003 (the "Senior Notes"). The Senior Notes mature on January 15, 2003 and bear interest at the rate of 11% per annum. The Senior Notes are redeemable at the option of the Parent, in whole or in part, at predetermined redemption prices set forth within the Senior Notes indenture. The subsidiaries of the Parent have guaranteed the Senior Notes on a senior unsecured basis. On February 20, 2001, in connection with the Company's Plan, certain amendments were made to the indenture governing the Senior Notes. The Senior Notes, as amended, contain certain restrictive covenants which, among other things, limit the Company's ability to incur additional indebtedness, require the repurchase of the Senior Notes upon a change of control, limit the Company's ability to purchase and redeem the Senior Subordinated Notes and the Company's common stock, prohibit the Company from purchasing or 36 38 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) redeeming the Series A Convertible Preferred Stock and prohibit the Company from paying any cash dividends on capital stock. Revolving Credit Agreement On February 20, 2001, outstanding principal, interest and fees under the Company's revolving credit agreement ("Revolving Credit Agreement") were paid in full as part of the Company's Plan. Prior to its repayment, the Revolving Credit Agreement was used for general corporate purposes, including working capital, and to support the Company's capital expenditure program. The obligations under the Revolving Credit Agreement were secured by substantially all of the oil and gas reserves acquired in a 1996 acquisition, a pledge of the common stock of certain KCS Energy, Inc. subsidiaries and certain VPP and other assets. Beginning in May 1999, the Company and its bank lenders entered into a series of forbearance agreements. See "Forbearance Agreements" below. The Revolving Credit Agreement permitted the borrowers under this facility to choose interest rate options based on the bank's prime rate or LIBOR and from maturities ranging up to 12 months. The applicable spread was based on the percentage of the borrowing base that is outstanding. A commitment fee ranging between 0.375% and 0.50% was paid on the unused portion of the borrowing base. The weighted average interest rate during 2000 was 9.07%. As of December 31, 2000, the weighted average interest rate under the Revolving Credit Agreement was 9.34% and $34.2 million was outstanding. The weighted average interest rate during 1999 was 7.87%. As of December 31, 1999, the weighted average interest rate under the Revolving Credit Agreement was 8.89% and $49.5 million was outstanding. Credit Facility On February 20, 2001, all outstanding principal, interest and fees under the Company's revolving credit facility ("Credit Facility") were paid in full as part of the Company's Plan. Prior to its repayment, the Credit Facility was used for general corporate purposes, including working capital, and to support the Company's capital expenditure program. Substantially all of the Company's oil and gas reserves (excluding those pledged under the Revolving Credit Agreement) were pledged to secure the Credit Facility. Beginning in May 1999, the Company and its bank lenders entered into a series of forbearance agreements. See "Forbearance Agreements" below. The Credit Facility permitted the borrowers to choose interest rate options based on the bank's prime rate or LIBOR and from maturities ranging up to 12 months. The applicable spread was based on the percentage of the borrowing base that was outstanding. A commitment fee ranging between 0.375% and 0.50% was paid on the unused portion of the borrowing base. The weighted average interest rate during 2000 was 9.36%. As of December 31, 2000, the weighted average interest rate under the Credit Facility was 9.60% and $42.5 million was outstanding. The weighted average interest rate during 1999 was 8.14%. As of December 31, 1999, the weighted average interest rate under the Credit Facility was 9.12% and $57.6 million was outstanding. Forbearance Agreements Beginning in May 1999, the Company and its bank lenders entered into a series of forbearance agreements which provided, among other things, that the bank lenders would refrain from exercising certain of their rights and remedies as a result of existing defaults for a period of time and the Company would make certain minimum monthly principal payments. From the time that the original forbearance agreements were entered into through December 31, 2000, the Company made principal payments to its banks of $73.3 million, reducing the outstanding principal from $150.0 million to $76.7 million. The forbearance agreements precluded the Company from making interest payments on the Senior Notes and the Senior Subordinated Notes. From the commencement of the bankruptcy proceedings until the effective date of the Plan, the 37 39 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Company operated under a cash collateral agreement with its bank lenders. The agreement provided, among other things, that the Company make monthly principal payments of $2.5 million and that the lenders have the right to review and approve the Company's projected use of cash during the bankruptcy proceedings. Other Information The estimated fair value of the Company's Senior Notes and Senior Subordinated Notes at December 31, 2000 were $139.5 million and $88.8 million, respectively. These values were estimated based upon the December 29, 2000 quoted market price of $93.0 for the Senior Notes and $71.0 for the Senior Subordinated Notes. The estimated fair value of the Company's Senior Notes and Senior Subordinated Notes at December 31, 1999 were $120.0 million and $34.4 million, respectively. These values were estimated based upon the December 31, 1999 quoted market price of $80.00 for the Senior Notes and $27.50 for the Senior Subordinated Notes. The carrying amount of the remaining debt at year-end 2000 and 1999 approximates fair value. The scheduled maturities of the Company's debt during the next five years, adjusted to reflect the implementation of the Company's Plan of reorganization, are as follows: 2001 $-0- million, 2002 $-0- million, 2003 $90.0 million, 2004 $-0- and 2005 $-0- million. Interest payments were $8.6 million in 2000, $25.4 million in 1999 and $30.0 million in 1998. 6. LEASES Future minimum lease payments under non-cancelable operating leases are as follows: $0.7 million in 2001, $0.5 million in 2002, $0.3 million in 2003, $0.3 million in 2004, $0.3 million in 2005 and $0.2 million thereafter. Lease payments charged to operating expenses amounted to $0.6 million, $0.7 million and $0.8 million during 2000, 1999 and 1998, respectively. 7. NEW YORK STOCK EXCHANGE LISTING In October 1999, the Company reported that it did not meet the current New York Stock Exchange ("NYSE") continued listing standards. These standards require a minimum share price of $1.00, a minimum market capitalization of $50 million and minimum book equity of $50 million. The Company has been trading pursuant to an approved business plan to return to compliance within a prescribed time frame. The NYSE has determined to forbear from initiating any formal removal action in view of the fact that the Company's stock price is now above $1.00 and the Company has successfully met one half of the conjunction test requiring that the Company return to $50 million each in stockholders' equity and market capitalization, as defined, and has made substantial progress on meeting the other component of the test. The Company's market capitalization at March 28, 2001 was approximately $163.8 million, excluding $30 million of convertible preferred stock. 38 40 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 8. INCOME TAXES Federal and state income tax provision (benefit) includes the following components:
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2000 1999 1998 --------- -------- ---------- (DOLLARS IN THOUSANDS) Current provision (benefit).......................... $ -- $ -- $ (3,248) Deferred provision (benefit), net.................... -- -- 19,702 -------- ------- --------- Federal income tax expense (benefit)................. -- -- 16,454 State income tax (provision) benefit (deferred provision $0 in 2000, $0 in 1999, and $750 in 1998).............................................. -- -- (455) -------- ------- --------- $ -- $ -- $ 15,999 ======== ======= ========= Reconciliation of federal income tax expense (benefit) at statutory rate to provision for income taxes: Income (loss) before income taxes.................. $ 41,523 $ 4,340 $(280,521) -------- ------- --------- Tax provision (benefit) at 35% statutory rate...... 14,533 1,519 (98,183) State income tax, net of federal income tax benefit......................................... -- -- (296) Statutory depletion................................ -- -- (20) Reversal of prior year Section 29 credits.......... -- -- 529 Valuation allowance................................ (14,544) (1,532) 113,944 Other, net......................................... 11 13 25 -------- ------- --------- $ -- $ -- $ 15,999 ======== ======= =========
The primary differences giving rise to the Company's net deferred tax assets are as follows:
DECEMBER 31, ---------------------- 2000 1999 --------- ---------- (DOLLARS IN THOUSANDS) Income tax effects of: Property related items.................................... $ 14,460 $ 24,865 Alternative minimum tax credit carry forwards............. 2,776 2,776 Net operating loss carry forward.......................... 80,632 84,771 Valuation allowance....................................... (97,868) (112,412) -------- --------- $ -- $ -- ======== =========
Income tax payments were $-0- million in 2000 and 1999, and $0.3 million in 1998. Also, in 1998, the Company received a federal income tax refund of $3.2 million. Historically, the Company has recorded tax benefits relating to its pretax book losses even though it has been in a net operating loss carryforward position for federal income tax purposes. SFAS No. 109 allows for such tax benefits to be recorded as deferred tax assets if management believes that it is "more likely than not" that these assets will be realized through the generation of future taxable income. Due to the significant losses recorded in 1998 and the uncertainty of future oil and natural gas commodity prices, management concluded at that time that a valuation allowance against net deferred tax assets was required in accordance with SFAS No. 109. In making its assessment, management considered several factors, including uncertainty of the Company's ability to generate sufficient income in order to realize its future tax benefits. Accordingly, the Company recorded a valuation allowance of $113.9 million as of December 31, 1998. The valuation allowance will be monitored for potential adjustments as future events so indicate. 39 41 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Deferred tax assets relate primarily to the Company's pre-tax book losses, the net operating loss and alternative minimum tax credit carryforwards. At December 31, 2000, the Company had tax net operating losses ("NOLs") of approximately $230.4 million available to offset future taxable income, of which approximately $14.5 million will expire in 2011, $82.7 million will expire in 2012, $73.8 million will expire in 2018, $34.1 will expire in 2019 and $25.3 million will expire in 2020. 9. FINANCIAL INSTRUMENTS The Company has, at times, utilized swaps, futures contracts and options to manage risks associated with fluctuations in the price of its natural gas and oil production. Commodity Price Swaps. Commodity price swap agreements require the Company to make or receive payments from the counterparties based upon the differential between a specified fixed price and a price related to those quoted on the New York Mercantile Exchange. During 2000, the Company accounted for these transactions as hedges and, accordingly, gains or losses were deferred until the time the underlying product is produced. At December 31, 2000, the Company was party to commodity price swap agreements covering approximately 3.3 million MMBtu, 2.5 million MMBtu and 4.8 million MMBtu of natural gas production for the years 2001 and 2002, and for the period 2003 through 2005, respectively. At December 31, 2000, the unrealized loss on these contracts was $29.1 million. At December 31, 1999, the Company had an unrealized loss of $5.8 million relating to commodity price swaps and had a deferred loss of $0.4 million from closed swap contracts relating to gas production in the year 2000. Futures and Options Contracts. Oil or natural gas futures contracts require the Company to sell oil or natural gas at a future time at a fixed price. Periodically, the Company uses these futures contracts to hedge price risk on a portion of its production. Option contracts provide the right, not the requirement, to buy or sell a commodity at a fixed price. By buying a "put" option, the Company is able to set a floor price for a specified quantity of its oil or gas production. By selling a "call" option, the Company receives an upfront premium to sell the right to buy a specified quantity of its oil or gas production at a fixed price. By selling call options and buying put options, the Company, at little or no cost, effectively places a "collar" on the price it will receive for that quantity of future production. At December 31, 2000, the Company had no open futures contracts, but had collars in place covering 3.6 million MMBtu of production in the first quarter of the year 2001 with an unrealized loss of $16.7 million. At December 31, 1999, the Company had no open futures contracts, but had collars in place covering 18,200 barrels of oil production in the second quarter of the year 2000 with a negligible unrealized loss. The Company realized $10.6 million in net hedging losses during 2000. None of the outstanding agreements impose cash margin requirements on the Company. 10. LITIGATION Royalty Suits The Company was a party to six lawsuits in the Texas State Courts involving various claims asserted by various holders of royalty interests under leases on the acreage that was dedicated to the Tennessee Gas Contract or pooled therewith. One suit involved claims by the holder of an overriding royalty interest in the dedicated acreage of certain rights in the Tennessee Gas Contract (the "Matthews Suit"). Of the other five, one sought a declaratory judgment on the royalty payment basis for non-dedicated acreage in which the Company owns no interest (the "Collins Suit"). The other four suits sought declaratory judgments to determine whether royalties payable to the holders of landowner royalty interests in the dedicated acreage should be based on the net proceeds received by the Company for gas sales under the Tennessee Gas Contract or on the spot market price (the "Las Blancas Suit," the "Gonzalez Suit," the "Los Santos Suit" and the "Jesus Yzaguirre Suit"). The Company paid royalties based upon the spot market price to the holders of 40 42 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) royalty interests (other than the overriding royalty interest) because the Company's leases, which cover only dedicated acreage, have market value royalty provisions. All of these suits, except the Jesus Yzaguirre Suit, have been concluded completely in favor of the Company with the Texas Supreme Court's denial of the royalty owners' motion for rehearing or the denial of their petition for review in the Los Santos Suit on May 11, 2000. In the Jesus Yzaguirre Suit, certain of the royalty owners counterclaimed against the Company, asserting that the largest lease contained therein had terminated in December 1975, and that they were entitled to the Tennessee Gas Contract price because of the execution of certain division orders in 1992 that allegedly varied the market value royalty provision of their lease. On May 30, 1997, the Company and these royalty owners reached a settlement of the lease termination claims, and on June 2, 1997, this issue was dismissed from the Jesus Yzaguirre Suit. On June 17, 1997, the Company and the royalty owners moved for summary judgment on the issue of the effect of division orders. The trial judge granted the Company's motion and denied the competing motion on August 12, 1997. On October 29, 1997, a final judgment was signed, and on November 19, 1997, the royalty owners gave notice of their appeal to the Fifth Circuit Court of Appeals in Dallas, Texas, and caused the appellate record to be filed. The royalty owners' brief was filed with the Fifth Court of Appeals on March 18, 1998. The Company filed its brief in response on April 16, 1998. The parties requested oral argument on the Appellants' issues that it was an error for the trial court to grant summary judgment for the Company on the unambiguous lease provisions requiring the Company to pay market value royalties and against them on their contention that the implied duty to market required the Company to pay royalties based upon the higher contract price; to grant summary judgment to the Company that the 1992 division orders did not override the express royalty provisions of their leases under Texas law; to grant summary judgment declaring that their counterclaims and affirmative defenses of fraud, negligent misrepresentations, conspiracy and estoppel, as well as allegations of oral promises and a course of conduct by the Company, did not change the unambiguous terms of the written leases; to exclude Appellants' expert witness testimony on "market value" as being inadmissible; to deny Appellants' efforts to transfer venue from Dallas County to Zapata County; and to refuse to abate this suit in favor of Appellants' later-filed suit against the Company in Zapata County. On October 28, 1999, the parties were notified that the Fifth Court of Appeals in Dallas had determined that oral argument would not significantly aid it in determining the legal and factual issues presented. Accordingly, the royalty owners' appeal was submitted for decision on January 4, 2000, without oral argument. On June 27, 2000, the Fifth Circuit Court of Appeals at Dallas, Texas affirmed the trial court's judgment in favor of the Company in the Jesus Yzaguirre Suit. The royalty owners did not move for a rehearing but on August 10, 2000, they applied to the Texas Supreme Court for review. On October 26, 2000, the Texas Supreme Court denied the royalty owners petition for review. The royalty owners filed a motion for a rehearing on November 10, 2000, and several friend-of-court briefs were filed in support of rehearing by the Texas Supreme Court. The Company filed a response on December 8, 2000, and on January 11, 2001, the Texas Supreme Court withdrew its prior order and granted the petition for review. On February 12, 2001, the royalty owners filed their brief on the merits on the issues of market-value royalties, implied duty to market, exclusion of their expert witness opinion testimony on market value and venue. On March 5, 2001, the Company's brief on the merits in response was filed. The briefing schedule in the Texas Supreme Court was concluded on March 20, 2001, with the reply brief of the royalty owners. This cause has been set for oral argument and submission on April 4, 2001 by the Texas Supreme Court. Given the inherent uncertainties of appellate matters and notwithstanding the disposition of the Los Santos Suit by the Texas Supreme Court and the Company's position on the issues of market value, implied covenants and venue is based upon established decisional law in Texas, the Company is unable to provide any assurance of a favorable outcome of the Texas Supreme Court's consideration of the royalty owners' petition for review in the Jesus Yzaguirre Suit. The royalty owners could obtain a reversal and remand for plenary trial upon showing that summary judgment was improper because there exists an issue of material fact or there was error in the venue or evidentiary ruling by the trial court. 41 43 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The amount at issue in the Jesus Yzaguirre Suit is a function of the quantity of natural gas for which Tennessee Gas paid at the contract price. As of January 1, 1997 (the date of the termination of the Tennessee Gas Contract) the amount of natural gas taken by Tennessee Gas attributable to the royalty interests involved in the Jesus Yzaguirre Suit was approximately 1.3 Bcf for which royalties have been paid by the Company at the average price of approximately $1.63 per Mcf, net of severance tax, compared to the average Tennessee Gas Contract price of approximately $7.60 per Mcf, net of severance tax. Consequently, if the Company loses in this litigation with these royalty interest owners, the Company faces a maximum liability of approximately $7.8 million, plus interest thereon. Environmental Suits There are two lawsuits currently pending concerning environmental and surface restoration issues on certain of the lands covered or formerly covered by the following two oil and gas leases: a) Oil and Gas Lease dated June 13, 1935, from Newhall Land and Farming Company, as Lessor, to Barnsdall Oil Company, as Lessee (the "RSF Lease") and b) Oil and Gas Lease dated June 6, 1941, from the Newhall Corporation, as Lessor, to C.G. Willis, as Lessee (the "Ferguson Lease"). The RSF Lease and the Ferguson Lease are herein called "Leases." Oil and gas production from such lands commenced shortly after the RSF Lease was granted and has continued to date. The Company is a defendant in a lawsuit brought by InterCoast Energy Company and MidAmerican Capital Company ("Plaintiffs") against KCS Energy, Inc., KCS Medallion Resources, Inc. and Medallion California Properties Company ("KCS Defendants"), and Kerr-McGee Oil & Gas Onshore LP and Kerr-McGee Corporation ("Kerr-McGee Defendants") currently pending in the 234th Judicial District Court of Harris County, Texas under Cause Number 1999-45998. The suit seeks a declaratory judgment declaring the rights and obligations of each of the Plaintiffs, the KCS Defendants and the Kerr-McGee Defendants in connection with environmental damages and surface restoration on lands covered by the Leases. From inception of the Leases until October 30, 1990, the Leases were owned by entities that through corporate succession and name change ultimately became Sun Operating Limited Partnership ("Sun L.P."). On October 30, 1990, Sun L.P. transferred the Leases to DKM Offshore Energy, Inc. ("DKM") and Neste Oil Services Inc. ("Neste"). In the assignment of the Leases, Sun L.P. indemnified DKM and Neste from environmental claims resulting from the indemnitors' operations provided that such environmental claims were made within ten years from October 30, 1990. Shortly after the transfer to DKM and Neste, DKM acquired Neste's rights and, subsequently, DKM became Medallion California Properties Company ("Medallion California"). Later, the Company acquired the stock of Medallion California Properties Company. Also, Sun L.P. became Kerr-McGee Oil & Gas Onshore L.P. ("Kerr-McGee L.P."). In connection with the sale of Medallion California to KCS, InterCoast Energy Company ("InterCoast") indemnified the Company and Medallion California for up to 90% of the costs of environmental remediation not assumed by Kerr-McGee L.P., and InterCoast's parent, MidAmerican Capital Company ("MidAmerican"), guaranteed InterCoast's indemnity obligations. Medallion California is a defendant in a lawsuit filed January 30, 2001, by The Newhall Land and Farming Company ("Newhall") against Medallion California and Kerr-McGee Corporation and several Kerr-McGee affiliates. The case is currently pending in Los Angeles County Superior Court under Cause Number BC244203. In the suit, Newhall seeks damages and punitive damages for alleged environmental contamination and surface restoration on the lands covered by the RSF Lease and also seeks a declaration that Newhall may terminate the RSF Lease or alternatively, that it may terminate those portions of the RSF Lease on which there is currently default under the Lease. Medallion California claims that Kerr-McGee and InterCoast and MidAmerican owe indemnities to Medallion California for defense and certain potential liability under Newhall's action, all as more particularly described in the Harris County, Texas litigation described above. 42 44 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) For a more in-depth discussion of the environmental condition of the property covered by the Leases, see "Regulation -- Environmental Claims." Other The Company and several of its subsidiaries have been named as co-defendants along with numerous other industry parties in an action brought by Jack Grynberg on behalf of the Government of the United States. The complaint, filed under the Federal False Claims Act, alleges underpayment of royalties to the Government of the United States as a result of alleged mismeasurement of the volume and wrongful analysis of the heating content of natural gas produced from federal and Native American lands. The complaint is substantially similar to other complaints filed by Jack Grynberg on behalf of the Government of the United States against multiple other industry parties. All of the complaints have been consolidated in one proceeding. In April 1999, the Government of the United States filed notice that it had decided not to intervene in these actions. The Company believes that the allegations in the complaint are without merit. The Company is also a party to various other lawsuits and governmental proceedings, all arising in the ordinary course of business. Although the outcome of all of the above proceedings cannot be predicted with certainty, management does not expect such matters to have a material adverse effect, either singly or in the aggregate, on the financial position or results of operations of the Company. It is possible, however, that charges could be required that would be significant to the operating results of a particular period. 11. QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERS --------------------------------------------- FIRST SECOND THIRD FOURTH --------- --------- --------- --------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA) 2000 Revenue...................................... $36,683 $45,388 $46,982 $62,936 Operating income............................. 14,236 22,517 24,802 36,760 Net income (loss)............................ $ (647) $14,837 $16,874 $10,459 Basic earnings (loss) per common share....... $ (0.02) $ 0.51 $ 0.58 $ 0.36 Diluted earnings (loss) per common share..... $ (0.02) $ 0.51 $ 0.58 $ 0.36
QUARTERS ------------------------------------- FIRST SECOND THIRD FOURTH ------- ------- ------- ------- 1999 Revenue...................................... $33,399 $33,853 $36,066 $35,300 Operating income............................. 7,946 10,034 14,678 10,985 Net income (loss)............................ $(1,918) $ 219 $ 4,756 $ 1,283 Basic earnings (loss) per common share....... $ (0.07) $ 0.01 $ 0.16 $ 0.04 Diluted earnings (loss) per common share..... $ (0.07) $ 0.01 $ 0.16 $ 0.04
The total of the earnings per share for the quarters does not equal the earnings per share elsewhere in the Consolidated Financial Statements as a result of the change in the number of shares outstanding during the applicable periods. 12. OIL AND GAS PRODUCING OPERATIONS (UNAUDITED) The following data is presented pursuant to SFAS No. 69 "Disclosures about Oil and Gas Producing Activities" with respect to oil and gas acquisition, exploration, development and producing activities, which is based on estimates of year-end oil and gas reserve quantities and forecasts of future development costs and 43 45 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) production schedules. These estimates and forecasts are inherently imprecise and subject to substantial revision as a result of changes in estimates of remaining volumes, prices, costs and production rates. Except where otherwise provided by contractual agreement, future cash inflows are estimated using year-end prices. Oil and gas prices at December 31, 2000 are not necessarily reflective of the prices the Company expects to receive in the future. Other than gas sold under contractual arrangements, including swaps, futures contracts and options, gas prices were based on NYMEX prices of $9.53, $2.33 and $2.15 at December 31, 2000, 1999 and 1998, respectively, and oil prices were based on West Texas Intermediate (WTI) prices of $23.75, $22.75 and $8.57 at December 31, 2000, 1999 and 1998, respectively. The analogous gas price on March 21, 2001 was $5.17. VPP volumes represent oil and gas reserves purchased from third parties which generally entitle the Company to a specified volume of oil and gas to be delivered over a stated time period. The related volumes stated herein reflect scheduled amounts of oil and gas to be delivered to the Company at agreed delivery points and future cash inflows are estimated at year-end prices. Although specific terms of the Company's VPPs vary, the Company is generally entitled to receive delivery of its scheduled oil and gas volumes, free of drilling and lease operating costs. PRODUCTION REVENUES AND COSTS Information with respect to production revenues and costs related to oil and gas producing activities is as follows:
FOR THE YEAR ENDED DECEMBER 31, ---------------------------------- 2000 1999 1998 ---------- --------- --------- (DOLLARS IN THOUSANDS) Revenue................................................... $ 190,511 $ 134,124 $ 125,363 ---------- --------- --------- Production (lifting) costs................................ 34,406 32,275 36,302 Technical support and other............................... 4,601 4,432 7,113 Depreciation, depletion and amortization.................. 50,316 50,816 59,746 Writedown of oil and gas properties....................... -- -- 268,468 ---------- --------- --------- Total expenses.................................. 89,323 87,523 371,629 ---------- --------- --------- Pretax income (loss) from producing activities............ 101,188 46,601 (246,266) Income tax benefit........................................ -- -- -- ---------- --------- --------- Results of oil and gas producing activities (excluding corporate overhead and interest)........................ $ 101,188 $ 46,601 $(246,266) ========== ========= ========= Capitalized costs incurred: Property acquisition.................................... $ 7,264 $ 25,847 $ 80,741 Exploration............................................. 36,032 8,949 15,865 Development............................................. 19,302 25,204 66,790 ---------- --------- --------- Total capitalized costs incurred................ $ 62,598 $ 60,000 $ 163,396 ========== ========= ========= Capitalized costs at year end: Proved properties....................................... $1,020,099 $ 955,340 $ 913,777 Unproved properties..................................... 5,582 8,437 17,718 ---------- --------- --------- 1,025,681 963,777 931,495 Less accumulated depreciation, depletion and amortization............................................ (780,512) (731,496) (682,913) ---------- --------- --------- Net investment in oil and gas properties.................. $ 245,169 $ 232,281 $ 248,582 ========== ========= =========
44 46 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DISCOUNTED FUTURE NET CASH FLOWS The following information relating to discounted future net cash flows has been prepared on the basis of the Company's estimated net proved oil and gas reserves in accordance with SFAS No. 69. Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
DECEMBER 31, ---------------------------------- 2000 1999 1998 ---------- --------- --------- (DOLLARS IN THOUSANDS) Future cash inflows............................... $2,234,831 $ 713,067 $ 639,062 Future costs: Production...................................... (451,763) (235,328) (183,550) Development..................................... (54,568) (41,751) (40,827) Discount -- 10% annually........................ (624,021) (143,198) (120,926) ---------- --------- --------- Present value of future net revenues............ 1,104,479 292,790 293,759 Future income taxes, discounted at 10%.......... (251,871) -- -- ---------- --------- --------- Standardized measure of discounted future net cash flows........................................... $ 852,608 $ 292,790 $ 293,759 ========== ========= =========
Had the Company's oil and gas reserves been valued using prices in effect at March 21, 2001, the present value of future net revenues would have been $581.8 million and the standardized measure of discounted future net cash flows would have been $508.7 million. Changes in Discounted Future Net Cash Flows from Proved Reserve Quantities
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2000 1999 1998 --------- --------- --------- (DOLLARS IN THOUSANDS) Balance, beginning of year........................ $ 292,790 $ 293,759 $ 374,882 Increases (decreases) Sales, net of production costs.................. (156,105) (101,849) (89,061) Net change in prices, net of production costs... 729,127 41,610 (104,375) Discoveries and extensions, net of future production and development costs............. 153,415 25,402 40,599 Changes in estimated future development costs... (9,953) 344 18,774 Change due to acquisition of reserves in place........................................ 34,087 41,142 93,200 Development costs incurred during the period.... 19,302 8,400 25,291 Revisions of quantity estimates................. (12,720) (10,666) (110,677) Accretion of discount........................... 29,279 28,068 41,049 Net change in income taxes...................... (251,871) -- 35,624 Sales of reserves in place...................... (344) (24,345) (5,918) Changes in production rates (timing) and other........................................ 25,601 (9,075) (25,629) --------- --------- --------- Net increase (decrease)......................... 559,818 (969) (81,123) --------- --------- --------- Balance, end of year.............................. $ 852,608 $ 292,790 $ 293,759 ========= ========= =========
45 47 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) RESERVE INFORMATION (UNAUDITED) The following information with respect to the Company's 2000 net proved oil and gas reserves are estimates prepared by Netherland, Sewell & Associates, Inc. Proved developed reserves represent only those reserves expected to be recovered through existing wells using equipment currently in place. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells or from existing wells after material recompletion expenditures. All of the Company's reserves are located within the United States.
2000 1999 1998 ---------------- ---------------- ----------------- GAS OIL GAS OIL GAS OIL MMCF MBBL MMCF MBBL MMCF MBBL ------- ------ ------- ------ ------- ------- Proved developed and undeveloped reserves Balance, beginning of year.... 227,119 8,341 257,690 8,693 326,168 19,063 Production.................... (41,089) (1,570) (50,471) (1,408) (50,070) (1,746) Discoveries, extensions, etc. ....................... 25,715 1,303 13,953 777 38,783 1,413 Acquisition of reserves in place....................... 5,921 293 31,857 906 50,705 557 Sales of reserves in place.... (213) (40) (18,118) (604) (8,948) (260) Revisions of estimates........ (5,825) 659 (7,792) (23) (98,948) (10,334) ------- ------ ------- ------ ------- ------- Balance, end of year.......... 211,628 8,986 227,119 8,341 257,690 8,693 ======= ====== ======= ====== ======= ======= Proved developed reserves Balance, beginning of year..................... 175,896 7,568 204,327 6,963 234,091 13,008 ------- ------ ------- ------ ------- ------- Balance, end of year........ 173,995 7,885 175,896 7,568 204,327 6,963 ======= ====== ======= ====== ======= =======
On February 20, 2001, the Company sold approximately 43.1 Bcfe through a volumetric production payment in connection with its Plan of reorganization. See Note 2. 46 48 PART III Item 10 -- Directors and Executive Officers of the Registrant, Item 11 -- Executive Compensation, Item 12 -- Security Ownership of Certain Beneficial Owners and Management, and Item 13 -- Certain Relationships and Related Transactions are incorporated by reference from the Company's definitive proxy statement relating to its 2001 Annual Meeting of Stockholders. PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K. (a) Financial statements, financial statement schedules and exhibits. (1) The following consolidated financial statements of KCS and its subsidiaries are presented in Item 8 of this Form 10-K.
PAGE ----- Report of Independent Public Accountants.................... 24 Statements of Consolidated Operations for the years ended December 31, 2000, 1999 and 1998.......................... 25 Consolidated Balance Sheets at December 31, 2000 and 1999... 26 Statements of Consolidated Stockholders' (Deficit) Equity for the years ended December 31, 2000, 1999 and 1998...... 27 Statements of Consolidated Cash Flows for the years ended December 31, 2000, 1999 and 1998.......................... 28 Notes to Consolidated Financial Statements.................. 29-46
(3) Exhibits See "Exhibit Index" located on page 48 of this Form 10-K for a listing of all exhibits filed herein or incorporated by reference to a previously filed registration statement or report with the Securities and Exchange Commission ("SEC"). (b) Reports on Form 8-K. On February 28, 2001, the registrant reported, under Item 3 of Form 8-K, that on February 20, 2001 it had completed the necessary steps for its plan of reorganization under Chapter 11 of Title 11 of the United States Bankruptcy Code to go effective and emerged from bankruptcy. 47 49 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. KCS ENERGY, INC. (Registrant) By: /s/ FREDERICK DWYER ---------------------------------- Frederick Dwyer Vice President, Controller and Secretary Date: 3/27/01 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities on the dates indicated.
SIGNATURE TITLE DATE --------- ----- ---- /s/ JAMES W. CHRISTMAS President & Chief Executive March 27, 2001 ----------------------------------------------------- Officer and Director James W. Christmas /s/ STEWART B. KEAN Chairman and Director March 27, 2001 ----------------------------------------------------- Stewart B. Kean /s/ G. STANTON GEARY Director March 27, 2001 ----------------------------------------------------- G. Stanton Geary /s/ JAMES E. MURPHY, JR. Director March 27, 2001 ----------------------------------------------------- James E. Murphy, Jr. /s/ ROBERT G. RAYNOLDS Director March 27, 2001 ----------------------------------------------------- Robert G. Raynolds /s/ JOEL D. SIEGEL Director March 27, 2001 ----------------------------------------------------- Joel D. Siegel /s/ CHRISTOPHER A. VIGGIANO Director March 27, 2001 ----------------------------------------------------- Christopher A. Viggiano By: /s/ FREDERICK DWYER March 27, 2001 ------------------------------------------------- Frederick Dwyer Vice President, Controller and Secretary
48 50 EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION ----------- ----------- (2)i -- Order of the United States Bankruptcy Court for the District of Delaware confirming the KCS Energy, Inc. Plan of Reorganization, filed as Exhibit 2 to Form 8-K on March 1, 2001. (3)i -- Restated Certificate of Incorporation of KCS Energy, Inc. -- filed herewith. ii -- Certificate of Designation, Preferences, Rights and Limitations of Series A Convertible Preferred Stock of KCS Energy, Inc. -- filed herewith. iii -- Restated By-Laws of KCS Energy, Inc. -- filed herewith. (4)i -- Form of Common Stock Certificate, $0.01 par Value, filed as Exhibit 4 of Registrant's Form 10-K Report for Fiscal 1988. ii -- Form of Common Stock Certificate, $0.01 par Value, filed as Exhibit 5 of Registrant's Form 8-A Registration Statement No. 1-11698 filed with the SEC, January 27, 1993. iii -- Indenture dated as of January 15, 1996 between KCS, certain of its subsidiaries and Fleet National Bank of Connecticut, Trustee, filed as Exhibit 4 to Current Report on Form 8-K dated January 25, 1996; First Supplemental Indenture dated December 2, 1996, Second Supplemental Indenture dated January 3, 1997 and Third Supplemental Indenture dated February 20, 2001 -- filed herewith. iv -- Form of 11% Senior Note due 2003 (included in Exhibit (4)(iii)). v -- Indenture dated as of January 15, 1998 between KCS, certain of its subsidiaries and State Street Bank and Trust Company and First Supplemental Indenture dated February 20, 2001 -- filed herewith. vi -- Form of 8 7/8% Senior Subordinated Note due 2006 (included in Exhibit (4)(v)). vii -- Form of Series A Convertible Preferred Stock Certificate, $0.01 par Value -- filed herewith. (10)i -- 1988 KCS Group, Inc. Employee Stock Purchase Program filed as Exhibit 4.1 to Form S-8 Registration Statement No. 33-24147 filed with the SEC on September 1, 1988.* ii -- Amendments to 1988 KCS Energy, Inc. Employee Stock Purchase Program filed as Exhibit 4.2 to Form S-8 Registration Statement No. 33-63982 filed with SEC June 8, 1993.* iii -- KCS Energy, Inc. 2001 Employees and Directors Stock Plan -- filed herewith. iv -- Purchase and Sale Agreement dated as of November 30, 1995 between the Company and Hawkins Oil of Michigan, Inc. (formerly Savoy Oil & Gas, Inc.), Conveyance of Production Payment dated as of November 30, 1995, Production and Delivery Agreement dated as of November 30, 1995, Option Agreement dated as of November 30, 1995, Drilling Participation Agreement dated December 7, 1995, Assignment and Bill of Sale (Working Interests) filed with the SEC as Exhibits 2.1 through 2.6 to Form 8-K on December 22, 1995. v -- Purchase and Sale Agreement dated September 8, 1995 by and between Natural Gas Processing Co., a Wyoming corporation, and KCS Resources, Inc., a Delaware corporation filed with the SEC as Exhibit 2.1 to Form 8-K on November 22, 1995. vi -- Purchase and Sale Agreement between KCS Resources, Inc., KCS Energy Services, Inc., KCS Michigan Resources, Inc. and KCS Medallion resources, Inc. as sellers and Star VPP, LP as Buyer dated as of February 14, 2001 -- filed herewith. (21) -- Subsidiaries of the Registrant -- filed herewith. (23)i -- Consent of Arthur Andersen LLP -- filed herewith. ii -- Consent of Netherland, Sewell and Associates, Inc. -- filed herewith.
--------------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit. 49