10-K405 1 h95356e10-k405.txt KCS ENERGY, INC. - 12/31/2001 -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- 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, 2001 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 of (I.R.S. Employer Identification No.) incorporation or organization)
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:
TITLE OF CLASS NAME OF EACH EXCHANGE 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 30,834,234 shares of the Common Stock held by non-affiliates of the Registrant at the $2.49 closing price on March 1, 2002 was $76,777,242. Number of shares of Common Stock outstanding as of the close of business on March 1, 2002: 34,946,577 DOCUMENTS INCORPORATED BY REFERENCE Part III incorporates information by reference to Notice of and Proxy Statement for the 2002 Annual Meeting of Shareholders to the extent indicated herein. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- KCS ENERGY, INC. FORM 10-K REPORT FOR THE YEAR ENDED DECEMBER 31, 2001 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. These non-cash charges represented $288.4 million of the 1998 net loss of $296.5 million. Also as a result of these charges, 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 those 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 entered into forbearance agreements with its banks, which among other things, precluded the Company from making interest payments on the Senior Notes and Senior Subordinated Notes. The Company did not make scheduled interest payments in July 1999 and was in default with respect to these notes. On December 28, 1999, the Company announced that it had reached an agreement on a proposed restructuring 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 (the parent company only) under Chapter 11 of the United States Bankruptcy Code ("Bankruptcy Code"). On January 18, 2000, the United States Bankruptcy Court for the District of Delaware ("Bankruptcy Court") entered an order granting KCS relief under Chapter 11 of Title 11 of the Bankruptcy Code and each of KCS' subsidiaries filed voluntary petitions under the Bankruptcy Code. See Note 2 to Consolidated Financial Statements. On January 30, 2001, the Bankruptcy Court confirmed the Company's 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 Notes and Senior Subordinated Notes, including interest on interest, and repaid $60.0 million of Senior Notes. The balance of the Senior Notes and the Senior Subordinated Notes were reinstated under amended indentures. 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. In the second quarter of 1999, oil and gas prices began to recover. As a result of cost cutting, a successful capital investment program and significantly improved prices the Company returned to profitability in 1999 and reported record earnings in both 2000 and 2001. In addition, the Company funded a capital investment 1 program of $69.1 million in 2000 and $87.2 million in 2001 and reduced its debt from a peak of $425 million in early 1999 to $204.8 million at December 31, 2001. 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. Of the Company's revenue in 2001, 32% was amortization of deferred revenue attributed to volumes delivered under the Production Payment as described in Note 2 to Consolidated Financial Statements. Other than this amortization of deferred revenue, no customer accounted for more than 10% of the Company's revenues in 2001, 2000 or 1999. Exploration and Production Activities During the three-year period ended December 31, 2001, the Company participated in drilling 277 gross (127.9 net) wells, of which 85% were successful. In 2001, the Company participated in drilling 106 gross (42.6 net) wells, of which 87% were successful. This included 71 development wells and 35 exploration wells with success rates of 92% and 77%, respectively. In 2001, 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, west Texas and Michigan. During 2001, the Company drilled 74 gross (36.0 net) wells in this region with a 96% success ratio. In the Gulf Coast region, the Company drilled 32 gross (6.6 net) wells in 2001 with a 66% success ratio. 2 In 2001, the Company acquired properties in the West Mission Valley field, located in Victoria and Goliad counties, Texas, further enhancing its production base in the south Texas Wilcox trend. The acquisition added 19.6 Bcfe net proved reserves, approximately 10,000 leasehold acres, several associated drilling prospects and workover opportunities. Volumetric Production Payment Program The Company has historically augmented 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 acquisition entitles the Company to a priority right to a specified volume of oil and gas reserves scheduled to be produced and delivered on an agreed delivery schedule. 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 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, 2001, 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, 2001, the Company has realized approximately $288.1 million from the sale of oil and gas acquired under the program, with 0.5 Bcf of conventional VPPs scheduled for future deliveries and 10.6 Bcfe of a VPP which was converted to a working interest. Due to limited capital availability the Company has made minimal VPP investments since 1999, and did not make any additional VPP investments in 2001. 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 As described below, the Company's oil and gas operations make it subject to certain risks. Volatile Nature of Oil and Gas Markets; Fluctuation in Prices. The Company's future financial condition and operating results highly depend 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, and are expected to continue to be, volatile. Prices for oil and gas fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty, and a variety of additional factors beyond the Company's control. These factors include: - worldwide political conditions (especially in the Middle East and other oil-producing regions), - the domestic and foreign supply of oil and gas, - the level of consumer demand, 3 - weather conditions, - domestic and foreign government regulations and taxes, and - the price and availability of alternative fuels and overall economic conditions. A decline in oil or gas 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 depend primarily on its ability to replace oil and gas reserves through acquisitions, development and exploratory drilling. Acquisitions may not be available at attractive prices. The decision to purchase, explore or develop a property depends in part on geophysical and geological analyses and engineering studies, which are often inconclusive or subject to varying interpretations. Consequently, there can be no assurance that the Company's acquisition, development and exploration activities will result in significant additional reserves. Nor can there be any assurance that the Company will be successful in drilling economically productive wells. Without acquisition or development of additional reserves, the Company's proved reserves and revenues will decline. Reliance on Estimates of Reserves and Future Net Cash Flows. This Form 10-K includes estimates by independent petroleum engineers of the Company's oil and gas reserves and future net cash flows. There are numerous uncertainties inherent in estimating quantities of oil and gas reserves, including many factors beyond the Company's control. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. To estimate oil and gas reserves and future net cash flow, reserve engineers make a number of assumptions, which may vary considerably from actual results. These assumptions include, for example, assumptions concerning: - the effects of regulation by government agencies, - future oil and gas prices, - operating costs, - severance and excise taxes, and - development costs. For these reasons, reserve estimates, classifications of reserves based on risk of recovery, and estimates of future net cash flows 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, possibly materially. The Company's projected reserves and future cash flows may be subject to revisions based upon production history, oil and gas prices, performance of counterparties under the Company's contracts, operating and development costs and other factors. This Form 10-K refers to the "PV-10 value" of the Company's reserves. The "PV-10 value" of reserves means the present value of estimated future net revenues, computed by applying year-end prices to estimated future production from the reserves, deducting estimated future expenditures, and applying a discount factor of ten percent (10%). The PV-10 values referred to in this Form 10-K should not be construed as the current market value of the Company's estimated oil and gas reserves. In accordance with applicable requirements of the Securities and Exchange Commission ("SEC"), PV-10 value 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 (i) the amount and timing of actual production and expenditures to develop and produce reserves, (ii) the supply and demand for oil and gas, and (iii) changes in government regulations or taxation. In addition, the 10% discount factor, which the SEC requires 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. 4 Exploration Risks. Exploratory drilling activities are subject to many risks, 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 be unprofitable due to a number of risks, including: - wells may not be productive, either because commercially productive reservoirs were not encountered or for other reasons; - wells that are productive may not provide sufficient net revenues to return a profit after drilling, operating and other costs; and - the costs of drilling, completing and operating wells are often uncertain. In addition, 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. These factors may include title problems, weather conditions, compliance with government requirements, and shortages or delays in the delivery of equipment and services. Marketing Risks. The Company's ability to market oil and gas at commercially acceptable prices depends 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 changes in these factors could negatively effect the Company's profitability. Acquisition Risks. Acquisitions of oil and gas businesses and properties 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. It is generally not feasible for the Company to review in-depth every property and all records involved in each acquisition. 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 potential. Even when problems are identified, the Company may assume certain environmental and other risks and liabilities in connection with acquired businesses and properties. Operating Risks. The Company's operations are subject to numerous operating risks inherent in the oil and gas industry which could result in substantial losses to the Company. These risks include, for example, fires, explosions, well blow-outs, pipe failure, oil spills, natural gas leaks or ruptures, or other discharges of toxic gases or other pollutants. The occurrence of these risks could result in substantial losses to the Company due to personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damage to the environment. Such occurrences could also subject the Company to clean-up obligations, regulatory investigation, penalties or suspension of operations. Further, 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 with major oil and gas companies, other independent oil and gas concerns and individual producers and operators to acquire oil and gas businesses, properties and equipment, and to hire personnel, necessary to explore for, develop, produce, transport and market oil and gas. Many of these competitors have financial and other resources that substantially exceed those available to the Company. Government Regulation. The Company's business is subject to numerous federal, state and local laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Administrative and legislative proposals are frequently introduced, at both the state and 5 federal level, which if adopted or enacted, might significantly affect the industry. The Company cannot predict whether, or when, such laws and regulations may be enacted or adopted, and cannot predict the cost of compliance with such changing laws and regulations or their effects on oil and gas use or prices. REGULATION General. The Company's business is affected by numerous 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. The Company believes that its operations comply in all material respects with all applicable laws and regulations. Although such laws and regulations have a substantial impact upon the energy industry, generally these laws and regulations do not appear to affect the Company any differently, or to any greater or lesser extent, than other similar companies in the energy industry. The following discussion describes certain laws and regulations applicable to the energy industry 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. Laws and regulations vary from state to state, but generally include laws to regulate drilling and production activities and to promote resource conservation. Examples of such state laws and regulations include laws which: - require permits and bonds to drill and operate wells; - regulate the method of drilling and casing wells; - establish surface use and restoration requirements for properties upon which wells are drilled; - regulate plugging and abandonment of wells; - regulate the disposal of fluids used or produced in connection with operations; - regulate the location of wells, including establishing the minimum size of drilling units and the minimum spacing between wells; - concern unitization or pooling of oil and gas properties; - establish maximum rates of production from oil and gas wells; and - restrict the venting or flaring of gas. 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 6 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 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. 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 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 orders. Such regulations specify, for example, lease operating, safety and conservation standards, well plugging and abandonment requirements, and surface restoration requirements. In addition, the BIA, BLM and MMS generally require lessees to post bonds or other acceptable surety to assure that their 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 7 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 fires, explosions, well blow-outs, pipe failure, oil spills, natural gas leaks or ruptures, or other discharges of toxic gases or other pollutants. The occurrence of these risks could result in substantial losses to the Company due to personal injury, loss of life, damage to or destruction of wells, production facilities or other property or equipment, or damage to the environment. Such occurrences could also subject the Company to clean-up obligations, regulatory investigation, penalties or 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 the types, quantities and concentration of substances that can be released into the environment; - 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 spilled or disposed of by the Company, 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, for damages to natural resources and for the costs of certain health studies. In addition, 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. The Company may be required to incur certain capital expenditures for air pollution control equipment in connection with maintaining or obtaining permits and approvals relating to air emissions. 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 operating in or near rivers, creeks, wetlands, coastal waters, offshore waters, and other U.S. waters to adopt and implement plans and procedures to prevent oil spills. 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 8 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. Among other matters, such laws may prohibit the discharge of waters produced in association with hydrocarbons into coastal waters. To comply with this prohibition, the Company may be required to incur capital expenditures or increased operating expenses. The CWA also regulates discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under a 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. Such coverage may require the Company to make minor modifications to existing facilities and operations that would not have a material effect on the Company. Pursuant to the Safe Drinking Water Act, underground injection control ("UIC") wells, including wells used in enhanced recovery and disposal operations associated with oil and gas exploration and production activities, are subject to regulation. Such regulations include permitting, bonding, operating, maintenance and reporting requirements. In 1999, the United States Department of Justice alleged that certain of the Company's UIC wells in Toole and Liberty counties, Montana are not in compliance 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 is commonly encountered 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. The nature and extent of both the Sun L.P. and InterCoast indemnities were recently classified by an Agreed Judgment entered in a Harris County Texas District Court. See Note 10 to the Consolidated Financial Statements included herein. 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. 9 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 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 145 persons on December 31, 2001. ITEM 2. PROPERTIES. OIL AND GAS PROPERTIES The following table sets forth data as of December 31, 2001 regarding the number of gross and net producing wells, and the estimated quantities of proved oil and gas reserves attributable to the Company's principal operating regions.
PRODUCING WELLS ----------------------------- ESTIMATED PROVED RESERVES GAS OIL --------------------------- ------------- ------------- GAS OIL TOTAL GROSS NET GROSS NET (MMCF) (MBBLS) (MMCFE) ----- ----- ----- ----- ------- ------- ------- Mid-Continent Region............... 783 548.0 369 126.4 123,762 5,410 156,222 Gulf Coast Region.................. 262 92.2 48 22.5 65,892 1,234 73,296 Volumetric Production Payments (VPPs)........................... -- -- -- -- 487 -- 487 ----- ----- --- ----- ------- ----- ------- Total Company.................... 1,045 640.2 417 148.9 190,141 6,644 230,005 ===== ===== === ===== ======= ===== =======
MID-CONTINENT REGION In the Mid-Continent Region, the Company is pursuing opportunities primarily in Oklahoma (Anadarko and Arkoma basins), north Louisiana, west Texas and Michigan. 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 156.2 Bcfe as of December 31, 2001, representing approximately 68% of the Company's reserves. During the year ended December 31, 2001, in this region, the Company participated in drilling 74 gross (36.0 net) wells with a completion success rate of 96%. At December 31, 2001, the Company owned leasehold interests within the Mid-Continent Region covering approximately 381,647 gross (264,479 net) acres. 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 potential 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 73.3 Bcfe as of December 31, 2001, which represented approximately 32% of the Company's reserves. 10 During 2001 the Company drilled 32 gross (6.6 net) wells in the Gulf Coast Region with a completion success rate of 66%. The Company owns or controls approximately 239,074 gross (51,337 net) acres in the Gulf Coast Region. VOLUMETRIC PRODUCTION PAYMENT PROGRAM The Company has historically augmented 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 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, 2001 to be 0.5 Bcfe. Since the inception of the VPP program in late 1994 through December 31, 2001, 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. From inception through December 31, 2001, the Company has realized approximately $288.1 million from the sale of oil and gas acquired under the program, with 0.5 Bcf of conventional VPPs scheduled for future deliveries and 10.6 Bcfe of a VPP which was converted to a working interest. Due to limited capital availability the Company has made minimal VPP investments since 1999, and did not make any additional VPP investments in 2001. The properties that constitute the VPP program are located in the Gulf of Mexico. Although it has not done so in the past, the Company is exploring the use of joint venture partnerships or similar arrangements with third parties to fund its VPP program. OIL AND GAS RESERVES The reserve estimates and associated cash flows for all properties for the year ended December 31, 2001 were audited and for the years ended December 31, 2000 and December 31, 1999 were prepared by Netherland, Sewell & Associates, Inc. The following table sets forth, as of December 31, 2001 summary information with respect to estimates of the Company's proved oil and gas reserves based on year-end prices. Oil and gas prices at December 31, 2001 are not necessarily reflective of the prices that the Company expects to receive in the future. Accordingly, the 11 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, 2001 ------------ PROVED RESERVES: Natural gas (MMcf).......................................... 190,141 Oil (Mbbls)................................................. 6,644 Total (Mmcfe)............................................... 230,005 Future net revenues ($000).................................. $338,109 Present value of future net revenues ($000)................. $202,188 PROVED DEVELOPED RESERVES: Natural gas (MMcf).......................................... 139,137 Oil (Mbbls)................................................. 5,915 Total (Mmcfe)............................................... 174,627 Future net revenues ($000).................................. $271,144 Present value of future net revenues ($000)................. $173,528
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, 2001 spot price of $2.65 per MMBTU, adjusted by lease for BTU content, transportation fees and regional price differentials. Oil prices are based on a December 31, 2001 West Texas Intermediate posted price of $16.75 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 "Oil and Gas Risk Factors" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." ACREAGE The following table sets forth certain information with respect to the Company's developed and undeveloped leased acreage as of December 31, 2001. 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 operator may surrender the leases at any time by notice to the lessors, by the cessation of production, 12 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 VPPs acquired.
DEVELOPED ACRES UNDEVELOPED ACRES ----------------- ----------------- STATE GROSS NET GROSS NET ----- ------- ------- ------- ------- Texas.......................................... 113,506 66,367 83,286 25,983 Louisiana...................................... 37,945 23,940 18,070 8,306 Montana........................................ 56,915 16,940 -- -- New Mexico..................................... 4,265 2,895 1,120 820 Oklahoma....................................... 58,725 24,770 2,970 1,015 Wyoming........................................ 48,740 45,565 83,230 82,120 Offshore....................................... 84,258 7,040 -- -- Mississippi.................................... 3,120 692 12,925 2,287 Other.......................................... 11,502 6,932 144 144 ------- ------- ------- ------- Total..................................... 418,976 195,141 201,745 120,675 ======= ======= ======= =======
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, 2001, 2000 and 1999, is set forth below.
YEAR ENDED DECEMBER 31, ------------------------------------------ 2001 2000 1999 ------------ ------------ ------------ TYPE OF WELL GROSS NET GROSS NET GROSS NET ------------ ----- ---- ----- ---- ----- ---- Development: Oil........................................ 2 0.5 8 4.7 9 7.5 Natural gas................................ 63 29.0 58 33.2 45 19.5 Non-productive............................. 6 3.4 8 2.3 8 4.1 -- ---- -- ---- -- ---- Total................................... 71 32.9 74 40.2 62 31.1 == ==== == ==== == ==== Exploratory: Oil........................................ 4 0.9 4 1.4 1 0.5 Natural gas................................ 23 7.0 9 1.9 9 4.4 Non-productive............................. 8 1.8 9 3.5 3 2.3 -- ---- -- ---- -- ---- Total................................... 35 9.7 22 6.8 13 7.2 == ==== == ==== == ====
At December 31, 2001, the Company was participating in the drilling of 5 gross (1.1 net) wells. 13 PRODUCTION The following table presents certain information with respect to oil and gas production attributable to the Company's properties during the three years ended December 31, 2001, 2000 and 1999.
YEAR ENDED DECEMBER 31, --------------------------- 2001 2000 1999 ------- ------- ------- Production:(a) Gas (Mmcf)............................................ 36,873 41,089 50,471 Oil (Mbbl)............................................ 1,230 1,306 1,286 Liquids (Mbbl)........................................ 373 264 122 Summary (Mmcfe) Working interest................................... 41,966 38,642 36,133 Purchased VPP...................................... 4,525 11,866 22,786 ------- ------- ------- Total............................................ 46,491 50,508 58,919 Average Price:(b) Gas (per Mcf)......................................... $ 3.90 $ 3.69 $ 2.22 Oil (per bbl)......................................... 20.67 27.35 16.04 Liquids (per bbl)..................................... 13.74 13.31 11.25 Total (per Mcfe)...................................... $ 3.75 $ 3.77 $ 2.28 Lease operating expense per Mcfe........................ $ 0.65 $ 0.55 $ 0.49 Production tax per Mcfe................................. $ 0.18 $ 0.13 $ 0.06
--------------- (a) 2001 Production includes 15,716 Mmcfe dedicated to the Production Payment sold in February. See Notes 1 and 2 to Consolidated Financial Statements. (b) Includes the effects of hedging and, in 2001, amortization of deferred revenue attributed to deliveries under the Production Payment sold in February. 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 Note 10 to the Consolidated Financial Statements. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. No matter was submitted to a vote of security holders through the solicitation of proxies or otherwise during the three months ended December 31, 2001. PART II ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. In accordance with the terms of its Senior Notes Indenture and Credit Agreement, 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. 14 There were 1,157 stockholders of record of the Company's Common Stock on March 1, 2002. 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:
2001 ---------------------------------------------- JAN.-MAR. APR.-JUNE JULY-SEPT. OCT.-DEC. --------- --------- ---------- --------- Market Price High........................................ $6.50 $10.20 $6.74 $4.00 Low......................................... 4.19 5.24 2.91 2.53
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
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, 2001.
2001 2000 1999 1998(1) 1997(2) -------- -------- -------- -------- -------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA) Revenue......................... $191,991 $191,989 $138,618 $131,324 $143,689 Income (loss) from continuing operations.................... 65,579 41,523 4,340 (296,520) (97,385) Income from discontinued operations.................... -- -- -- -- 5,302 Net income (loss)............... 65,579 41,523 4,340 (296,520) (92,083) Income (loss) available for common stockholders........... 63,818 41,523 4,340 (296,520) (92,083) Total assets.................... 346,726 347,335 284,932 308,878 502,414 Debt............................ 204,800 351,705 381,819 410,335 292,445 Stockholders' equity (deficit)..................... (39,460) (108,320) (149,843) (154,204) 145,070 Per common share (Basic): Income (loss) from continuing operations................. 2.02 1.42 0.15 (10.08) (3.37) Income from discontinued operations................. -- -- -- -- 0.18 Net income (loss)............. 2.02 1.42 0.15 (10.08) (3.19) Per common share (Diluted): Income (loss) from continuing operations................. 1.69 1.42 0.15 (10.08) (3.37) Income from discontinued operations................. -- -- -- -- 0.18 Net income (loss)............. 1.69 1.42 0.15 (10.08) (3.19) Per common share: Stockholders' equity (deficit).................. (1.14) (3.70) (5.12) (5.27) 4.93 Dividends..................... -- -- -- $ 0.08 $ 0.08
15 --------------- (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 KCS emerged from bankruptcy in February 2001 under the Plan (see Note 2 to Consolidated Financial Statements) in which the Company repaid its two bank credit facilities in full, paid past due interest on its Senior Notes and Senior Subordinated Notes, including interest on interest, and repaid $60.0 million of Senior Notes. The balance of the Senior Notes and the Senior Subordinated Notes were reinstated under amended indentures. 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 and background information. 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 industrial and consumer demand, weather conditions and overall economic conditions. RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999 RESULTS OF OPERATIONS Net income for 2001 was $65.6 million, or $2.02 per basic share ($1.69 diluted), compared to $41.5 million, or $1.42 per basic and diluted share in 2000. This increase was attributable to higher average realized natural gas prices, increased working interest production, higher other revenue and lower interest expense partially offset by lower production from the VPP program, lower oil prices and higher operating expenses. Reorganization items in 2001 were $2.9 million compared to $15.4 million in 2000. Net income for the year ended December 31, 2000 was $41.5 million, or $1.42 per basic and diluted share, compared to net income of $4.3 million, or $0.15 per basic and diluted share in 1999. This increase was attributable to significantly higher natural gas and oil prices together with lower operating and general and administrative expenses. Reorganization items in 2000 totaled $15.4 million. 16 REVENUE
2001 2000 1999 -------- -------- -------- Production: (a) Gas (Mmcf)......................................... 36,873 41,089 50,471 Oil (Mbbl)......................................... 1,230 1,306 1,286 Liquids (Mbbl)..................................... 373 264 122 Summary (Mmcfe) Working interest................................ 41,966 38,642 36,133 Purchased VPP................................... 4,525 11,866 22,786 -------- -------- -------- Total......................................... 46,491 50,508 58,919 Average Price: (b) Gas (per Mcf)...................................... $ 3.90 $ 3.69 $ 2.22 Oil (per bbl)...................................... 20.67 27.35 16.04 Liquids (per bbl).................................. 13.74 13.31 11.25 Total (per Mcfe).............................. $ 3.75 $ 3.77 $ 2.28 Revenue: Gas................................................ $143,882 $151,293 $112,128 Oil................................................ 25,428 35,711 20,624 Liquids............................................ 5,124 3,507 1,372 -------- -------- -------- Total......................................... $174,434 $190,511 $134,124 ======== ======== ========
--------------- (a) 2001 Production includes 15,716 Mmcfe dedicated to the Production Payment sold in February. See Notes 1 and 2 to Consolidated Financial Statements. (b) Includes the effects of hedging and, in 2001, amortization of deferred revenue attributed to deliveries under the Production Payment sold in February. Gas Revenue. In 2001, gas revenue was $143.9 million compared to $151.3 million in 2000. Higher natural gas prices during the first half of the year and a 9% increase in working interest production were offset by a 7.4 Bcf decrease in scheduled production from the VPP program and the dramatic decline in natural gas prices during the second half of 2001. Average realized gas prices during the first half of 2001 were $4.55 per Mcf compared to $3.19 during the second half of the year. The decrease in VPP production reflects the expiration of certain VPPs, limited investment in the program since 1999 and no investment in 2001. 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 10.4 Bcf decrease in scheduled VPP production. The decrease in VPP production reflects the expiration of certain VPPs and limited investment in the program. Oil and Liquids Revenue. In 2001, oil and liquids revenue decreased $8.7 million to $30.6 million primarily due to a 24% decrease in average realized oil prices. 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. Other Revenue, net. In 2001, other revenue was $17.6 million, of which $9.3 million was from the sale of emission reduction credits, $7.7 million from non-cash gains on derivative instruments that were not designated as oil and gas hedges when the Company adopted SFAS No. 133 (see Note 9 to Consolidated Financial Statements), and the remainder was primarily attributable to marketing and transportation revenue incidental to the Company's oil and gas operations. 17 In 2000, other revenue included $1.0 million from the settlement of certain claims 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 transportation revenue. LEASE OPERATING EXPENSES For the year ended December 31, 2001, lease operating expenses increased 10% to $30.5 million, compared to $27.8 million in 2000. The increased costs in 2001 reflect start-up costs associated with the Hartland gas processing plant in Michigan incurred during the first quarter of the year, higher ad valorem taxes, higher working interest production, and increased costs of workovers on oil and gas wells in order to maximize production during the first half of 2001 when natural gas prices were high. For the year ended December 31, 2000, lease operating expenses decreased 3% to $27.8 million, compared to $28.8 million in 1999 largely as the result of the sale of marginal, higher-cost oil and gas properties. PRODUCTION TAXES Production taxes, which are generally based on a percentage of revenue (excluding revenue from the VPP program), increased $1.6 million to $8.2 million in 2001, compared to $6.6 million in 2000 due to higher average natural gas prices and the increase in working interest production. Production taxes 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. GENERAL AND ADMINISTRATIVE EXPENSES General and administrative expenses ("G&A") were $8.9 million in 2001, which included approximately $1.4 million of cost associated with the retention bonus program for employees other than senior management that was put in place in October 2000 in order for the Company to retain its employees during the reorganization process. Excluding the effect of the retention bonus program, G&A in 2001 decreased 6% compared to 2000 as a result of lower salaries and wages due to a reduced workforce. G&A decreased $1.4 million, or 15%, to $8.4 million for the year ended December 31, 2000 compared to 1999. Reduction in the Company's workforce and other cost reduction initiatives throughout the Company were the primary reasons for the decreases. STOCK COMPENSATION Stock compensation in 2001 reflects the amortization of restricted stock grants issued pursuant to the Company's 2001 Employees and Directors Stock Plan. See Note 4 to Consolidated Financial Statements. 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 2001 and 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. BAD DEBT EXPENSE Bad debt expense was $4.1 million in 2001, primarily with respect to an allowance against receivables due from Enron entities, now in bankruptcy, for oil and gas sales and derivative instruments. The Company ceased 18 all sales to Enron entities after November 2001. See Note 9 to Consolidated Financial Statements for information with respect to derivative contracts with Enron entities. DEPRECIATION, DEPLETION AND AMORTIZATION (DD&A) 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, 2001, DD&A increased $7.9 million to $58.3 million. The DD&A rate increased to 32% of oil and gas revenues in 2001 compared to 26% in 2000 largely due to the dramatic decline in natural gas prices during the second half of the year and a higher depletable base. For the year ended December 31, 2000, DD&A decreased $0.5 million to $50.5 million compared to 1999. INTEREST AND OTHER INCOME Interest and other income was $1.3 million in 2001 which is primarily interest income associated with accumulated cash and cash equivalents. This compares to $0.1 million in 2000 and $0.7 million in 1999. In 2000 the Company also reported $1.0 million of interest income associated with accumulated cash and cash equivalents as a component of "Reorganization items" pursuant to SOP 90-7. INTEREST EXPENSE Interest expense was $21.8 million in 2001 compared to $41.5 million in 2000 and $40.0 million in 1999. The lower interest expense in 2001 reflects significantly lower outstanding debt. Interest expense in 2000 includes $4.2 million of interest on past due interest with respect to the Company's Senior Notes and Senior Subordinated Notes in accordance with the Plan (see Note 2 to Consolidated Financial Statements). 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. REORGANIZATION ITEMS For the year ended December 31, 2001, the Company recorded $2.9 million of reorganization items, primarily for legal and financial advisory services in connection with the completed Chapter 11 proceedings. 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 In connection with the adoption of SFAS No. 133, the Company recorded a liability of $43.8 million representing the fair market value of its derivative instruments upon adoption and an after-tax charge to other comprehensive income of $28.5 million from the cumulative effect of a change in accounting principle. During 2001, the Company reclassified $23.9 million of the liability as a non-cash reduction to oil and gas revenues and reduced its valuation allowance related primarily to net operating losses for a related tax benefit of $8.4 million. No income taxes were recorded in 2000 or in 1999 related to the Company's pre-tax book income as a portion of the valuation allowance account established in 1998 was reversed due to the Company's ability to utilize net operating loss carryforwards. See Note 8 to Consolidated Financial Statements. 19 LIQUIDITY AND CAPITAL RESOURCES The Company emerged from bankruptcy on February 20, 2001 having improved its financial condition by reducing its bank debt from a peak of $425 million in early 1999 to $215 million. See Note 2 to Consolidated Financial Statements. In addition, the strong natural gas price environment afforded the Company the resources to pay down an additional $10.2 million of the 11% Senior Notes in 2001 and carry out a substantial capital investment program thereby enhancing its producing property base, leasehold acreage and prospect inventory. Natural gas prices have since declined dramatically. Henry Hub spot market prices reached a low of $1.66 per MMBTU in November and averaged $2.39 per MMBTU for the fourth quarter of 2001 compared to an average of $4.51 for the first nine months of the year. The decline in natural gas prices is a result of reduced consumer and industrial demand as a result of abnormally warm weather conditions, general economic conditions, the September 11th tragedy and other factors, which have resulted in higher than normal levels of natural gas storage inventory. As a result of the depressed natural gas prices, the Company and the industry as a whole have cut back drilling activities. The Company believes that natural gas prices will improve significantly as the economy improves thereby increasing demand and the current low level of drilling activity leads to reductions to supply. CASH FLOW FROM OPERATING ACTIVITIES For the year ended December 31, 2001, net income adjusted for non-cash charges and reorganization items was $68.7 million compared to $109.0 million in 2000 as higher net income and non-cash expenses were offset by $63.1 million of non-cash amortization of deferred revenue associated with the Production Payment sold as described in Note 2 to Consolidated Financial Statements. Net cash provided by operating activities was $183.4 million in 2001 compared to $128.0 million in 2000. In addition to the items noted above, 2001 reflects the net proceeds of $175.0 million from the sale of the Production Payment, the $28.0 million cost of terminating certain derivative instruments in connection with the emergence from Chapter 11 and the payment of $71.5 million of interest expense ($49.1 million of which pertains to prior years). For the year ended December 31, 2000, net income adjusted for non-cash charges and reorganization items was $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 compared to 1999 was primarily due to the suspension of interest payments on the Senior Notes and Senior Subordinated Notes during the period of reorganization and accrued restructuring costs. INVESTING ACTIVITIES Capital expenditures for the year ended December 31, 2001 were $87.2 million, of which $42.9 million was for development activities, $26.8 million for the acquisition of proved reserves, $15.3 million for lease acquisitions, seismic surveys and exploratory drilling, and $2.2 million for other assets. Capital expenditures for the year ended December 31, 2000 were 69.1 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. OUTLOOK FOR 2002 As indicated above, based on the lower oil and gas prices in effect, and the January 2003 maturity of the 11% Senior Notes, of which $72.5 million are currently outstanding, the Company has curtailed its planned 20 capital expenditures for 2002 to be between $40 million and $55 million. In addition, the Company plans to sell $25 to $50 million of non-core assets, the proceeds of which will largely be used to redeem Senior Notes. The Company anticipates that cash flow and proceeds from asset sales, combined with additional amounts which could be refinanced or made available under its credit facility should be more than sufficient to carry out its business operations and meet the Senior Note maturity obligations. The Company is committed to modify its capital investment and asset divestiture programs if necessary in order meet its Senior Note obligations. During the first two months of 2002, the Company averaged approximately $4.8 million per month on its capital investment program, compared to an average of $7.1 million per month in 2001. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Oil and gas prices have historically been volatile. The Company has utilized, and may continue to utilize, derivative contracts, including swaps, futures contracts, options and collars to manage this price risk. Effective January 1, 2001, the Company adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities". See Note 9 to Consolidated Financial Statements. While these derivative contracts 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 receive from any price increases. 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 derivative positions at December 31, 2001. All these derivative contracts were with Enron North America Corp. See Notes 1 and 9 to the Consolidated Financial Statements. Descriptions of the Company's derivative instruments are included in Note 9. The Company entered into an agreement with a third party for additional derivative transactions subsequent to year end.
SWAPS @ $4.02 PER MMBTU IF NYMEX ABOVE $2.50 PUTS @ $3.00 PER MMBTU ---------------------------- ------------------------ UNREALIZED UNREALIZED VOLUME GAIN VOLUME GAIN ------------ ---------- --------- ---------- MMBTU ($000S) MMBTU ($000S) 2002 1st Qtr........................ -- $ -- -- $ -- 2nd Qtr........................ 910,000 1,272 910,000 344 3rd Qtr........................ 920,000 1,155 920,000 217 4th Qtr........................ 310,000 372 310,000 56 --------- ------ --------- ---- Total..................... 2,140,000 $2,799 2,140,000 $617
COLLARS: FLOOR AT $2.50 PER MMBTU WRITTEN CALLS AT CEILING AT $3.52 PER MMBTU $4.05 PER MMBTU(a) ---------------------------- ------------------------ UNREALIZED UNREALIZED VOLUME GAIN VOLUME GAIN ------------ ---------- --------- ---------- MMBTU ($000S) MMBTU ($000S) 2002 1st Qtr........................ 900,000 $ 0 450,000 $ 0 --------- ------ --------- ---- Total..................... 900,000 $ 0 450,000 $ 0
--------------- (a) The written calls were a component of a composite transaction whereby the Company entered into a $4.05 swap and volumes would double if NYMEX price exceeded $4.05 per Mmbtu. The swap component was unwound on November 29, 2001. In addition to the above, the Company will deliver 11.2 Bcfe in 2002 under the Production Payment sold at an average price of $4.05 Mcfe as described in Note 2. 21 For 2001, the Company delivered approximately 34% of its production under the Production Payment sold in February at an average realized price of $4.05 per Mcfe and also entered into derivative arrangements designed to reduce price downside risk for approximately 30% of the balance of its production. For the year 2000, 26% of the Company's production was covered by such derivative contracts. The Company uses fixed and variable long-term debt to finance the Company's capital spending program and for general corporate purposes. The variable rate debt exposes the Company to market risk related to changes in interest rates. The Company's fixed rate debt was $204.8 million at a weighted average interest rate of 9.7% on December 31, 2001 and $275.0 million at 10.0% on December 31, 2000. The Company had no variable rate debt on December 31, 2001. The Company's variable rate debt and weighted average interest rate was $76.7 million at 9.5% on December 31, 2000. The reduction in both fixed and variable rate debt reflects the significant debt repayments made as part of the Plan (see Note 2 to Consolidated Financial Statements). 22 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, 2001 and 2000, 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, 2001. 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, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States. As explained in Note 9 to the consolidated financial statements, effective January 1, 2001, the Company changed its method of accounting for derivative instruments and hedging activities to conform with Statement of Financial Accounting Standard No. 133, "Accounting for Derivative Instruments and Hedging Activities." ARTHUR ANDERSEN LLP Houston, Texas March 13, 2002 23 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2001 2000 1999 --------- --------- --------- (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA) Oil and gas revenue......................................... $174,434 $190,511 $134,124 Other revenue, net.......................................... 17,557 1,478 4,494 -------- -------- -------- Total revenue........................................ 191,991 191,989 138,618 -------- -------- -------- Operating costs and expenses Lease operating expenses.................................. 30,456 27,801 28,751 Production taxes.......................................... 8,195 6,605 3,524 General and administrative expenses....................... 8,885 8,417 9,797 Stock compensation........................................ 1,419 -- -- Bad debt expense.......................................... 4,074 400 50 Restructuring costs....................................... -- -- 1,886 Depreciation, depletion and amortization.................. 58,314 50,451 50,967 -------- -------- -------- Total operating costs and expenses................... 111,343 93,674 94,975 -------- -------- -------- Operating income............................................ 80,648 98,315 43,643 Interest and other income................................... 1,319 101 702 Interest expense (contractual interest for 2000 was $36,220).................................................. (21,799) (41,460) (40,005) -------- -------- -------- Income before reorganization items and income taxes......... 60,168 56,956 4,340 -------- -------- -------- Reorganization items Write-off of deferred debt issuance costs related to senior notes and senior subordinated notes............. -- (6,132) -- Financial restructuring costs............................. (3,175) (10,334) -- Interest income........................................... 227 1,033 -- -------- -------- -------- Reorganization items, net............................ (2,948) (15,433) -- -------- -------- -------- Income before income taxes.................................. 57,220 41,523 4,340 Federal and state income tax benefit........................ (8,359) -- -- -------- -------- -------- Net income.................................................. 65,579 41,523 4,340 Dividends and accretion of issuance costs on preferred stock..................................................... (1,761) -- -- -------- -------- -------- Income available to common stockholders..................... $ 63,818 $ 41,523 $ 4,340 ======== ======== ======== Earnings per share of common stock Basic..................................................... $ 2.02 $ 1.42 $ 0.15 ======== ======== ======== Diluted................................................... $ 1.69 $ 1.42 $ 0.15 ======== ======== ======== Average shares outstanding for computation of earnings per share Basic..................................................... 31,668 29,266 29,263 Diluted................................................... 38,828 29,305 29,288 ======== ======== ========
The accompanying notes are an integral part of these financial statements. 24 KCS ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, ----------------------- 2001 2000 --------- --------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA) ASSETS Current assets Cash and cash equivalents................................. $ 22,927 $ 39,994 Trade accounts receivable, less allowance for doubtful accounts of $4,190 in 2001 and $450 in 2000............. 20,342 45,954 Other current assets...................................... 6,718 5,697 --------- --------- Current assets.......................................... 49,987 91,645 --------- --------- Property, plant and equipment Oil and gas properties, full cost method, less accumulated DD&A -- 2001 $837,096; 2000 $780,512.................... 268,517 245,169 Other property, plant and equipment, at cost less accumulated depreciation -- 2001 $9,026; 2000 $7,345.... 10,160 9,731 --------- --------- Property, plant and equipment, net...................... 278,677 254,900 --------- --------- Deferred charges and other assets........................... 2,142 790 --------- --------- Deferred taxes.............................................. 15,920 -- --------- --------- $ 346,726 $ 347,335 ========= ========= LIABILITIES AND STOCKHOLDERS' (DEFICIT) EQUITY Current liabilities Accounts payable.......................................... $ 26,041 $ 22,974 Accrued interest on public debt........................... 9,089 -- Other accrued liabilities................................. 17,910 19,441 Short-term debt........................................... -- 76,705 --------- --------- Current liabilities..................................... 53,040 119,120 --------- --------- Deferred credits and other liabilities Deferred revenue.......................................... 111,880 -- Other..................................................... 877 1,359 --------- --------- Deferred credits and other liabilities.................. 112,757 1,359 --------- --------- 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 --------- --------- Long-term debt Senior notes.............................................. 79,800 -- Senior subordinated notes................................. 125,000 -- --------- --------- Long-term debt.......................................... 204,800 -- --------- --------- Commitments and contingencies --------- --------- Preferred stock, authorized 5,000,000 shares; issued 30,000 shares redeemable convertible preferred stock, par value $.01 per share, liquidation preference $1,000 per share -- 16,365 shares outstanding in 2001................ 15,589 -- --------- --------- Stockholders' (deficit) equity Common stock, par value $0.01 per share, authorized 75,000,000 shares; issued 36,844,495 and 31,433,006, respectively............................................ 368 314 Additional paid-in capital................................ 162,540 145,098 Retained (deficit) earnings............................... (185,173) (248,991) Unearned compensation..................................... (1,292) -- Accumulated other comprehensive income.................... (11,162) -- Less treasury stock, 2,167,096 shares, at cost............ (4,741) (4,741) --------- --------- Stockholders' (deficit) equity.......................... (39,460) (108,320) --------- --------- $ 346,726 $ 347,335 ========= =========
The accompanying notes are an integral part of these financial statements. 25 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED STOCKHOLDERS' (DEFICIT) EQUITY
ACCUMULATED ADDITIONAL RETAINED OTHER COMMON PAID-IN (DEFICIT) COMPREHENSIVE UNEARNED TREASURY STOCK CAPITAL EARNINGS INCOME COMPENSATION STOCK ------ ---------- --------- ------------- ------------ -------- (DOLLARS IN THOUSANDS) Balance at December 31, 1998........ $314 $145,077 $(294,854) $ -- $ -- $(4,741) Stock issuances -- option and benefit plans................... -- 21 -- -- -- -- Net income........................ -- -- 4,340 -- -- -- ---- -------- --------- -------- -------- ------- Balance at December 31, 1999........ 314 145,098 (290,514) -- -- (4,741) Net income........................ -- -- 41,523 -- -- -- ---- -------- --------- -------- -------- ------- Balance at December 31, 2000........ 314 145,098 (248,991) -- -- (4,741) Comprehensive income Net income...................... -- -- 65,579 -- -- -- Other comprehensive income, net of tax related to derivative instruments Cumulative effect of accounting change.......... Reclassification adjustments of cumulative effect of accounting change.......... Changes in fair value of hedging positions.......... Other Comprehensive income...... (11,162) Comprehensive income.............. Conversion of redeemable preferred stock........................... 46 13,724 -- -- -- -- Stock issuances -- option and benefit plans................... 6 2,906 -- -- (2,711) -- Stock compensation expense........ -- -- -- -- 1,419 -- Dividends and accretion of issuance costs on preferred stock........................... 2 812 (1,761) -- -- -- ---- -------- --------- -------- -------- ------- Balance at December 31, 2001........ $368 $162,540 $(185,173) $(11,162) $ (1,292) $(4,741) ==== ======== ========= ======== ======== ======= STOCKHOLDERS' COMPREHENSIVE (DEFICIT) INCOME EQUITY ------------- ------------- (DOLLARS IN THOUSANDS) Balance at December 31, 1998........ $ -- $(154,204) Stock issuances -- option and benefit plans................... -- 21 Net income........................ 4,340 4,340 ======= --------- Balance at December 31, 1999........ (149,843) Net income........................ 41,523 41,523 ======= --------- Balance at December 31, 2000........ (108,320) Comprehensive income Net income...................... 65,579 65,579 ------- Other comprehensive income, net of tax related to derivative instruments Cumulative effect of accounting change.......... (28,451) (28,451) Reclassification adjustments of cumulative effect of accounting change.......... 15,524 15,524 Changes in fair value of hedging positions.......... 1,765 1,765 ------- Other Comprehensive income...... (11,162) ------- Comprehensive income.............. $54,417 ======= Conversion of redeemable preferred stock........................... 13,770 Stock issuances -- option and benefit plans................... 201 Stock compensation expense........ 1,419 Dividends and accretion of issuance costs on preferred stock........................... (947) --------- Balance at December 31, 2001........ $ (39,460) =========
The accompanying notes are an integral part of these financial statements. 26 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, ------------------------------- 2001 2000 1999 --------- -------- -------- (DOLLARS IN THOUSANDS) Cash flows from operating activities: Net income................................................ $ 65,579 $ 41,523 $ 4,340 Non-cash charges (credits): Depreciation, depletion and amortization............... 58,314 50,451 50,967 Amortization of deferred revenue....................... (63,089) -- -- Deferred tax benefit................................... (8,359) -- -- Non-cash losses on derivative instruments.............. 15,779 -- -- Non-cash gains on derivative instruments............... (7,694) -- -- Allowance for bad debts................................ 4,074 400 -- Stock compensation..................................... 1,419 -- -- Other non-cash charges and credits, net................ (233) 1,240 2,862 Reorganization items................................... 2,948 15,433 -- --------- -------- -------- 68,738 109,047 58,169 Net changes in assets and liabilities: Proceeds from Production Payment, net.................. 174,969 -- -- Realized losses on derivative instruments terminated in connection with Plan of reorganization............... (27,995) -- -- Trade accounts receivable.............................. 21,872 (24,013) 14,607 Other current assets................................... (1,021) 1,874 (1,921) Accounts payable and accrued liabilities............... (1,042) 19,791 (12,018) Accrued interest on public debt........................ (49,109) 31,754 13,797 Other, net............................................. (45) (1,145) (1,171) --------- -------- -------- Net cash provided by operating activities before reorganization items...................................... 186,367 137,308 71,463 Reorganization items (excluding non-cash write-off of deferred debt issuance costs)............................. (2,948) (9,301) -- --------- -------- -------- Net cash provided by operating activities................... 183,419 128,007 71,463 --------- -------- -------- Cash flows from investing activities: Investment in oil and gas properties...................... (85,033) (62,598) (60,000) Proceeds from the sale of oil and gas properties.......... 5,100 694 27,718 Investment in other property, plant and equipment......... (2,159) (6,480) 840 --------- -------- -------- Net cash used in investing activities....................... (82,092) (68,384) (31,442) --------- -------- -------- Cash flows from financing activities: Proceeds from borrowings.................................. -- 292 16,300 Repayments of debt........................................ (146,905) (30,414) (44,905) Issuance of redeemable convertible preferred stock........ 28,412 -- -- Dividends paid............................................ -- -- (585) Deferred financing costs and other, net................... 99 (91) (1,123) --------- -------- -------- Net cash used in financing activities....................... (118,394) (30,213) (30,313) --------- -------- -------- Increase (decrease) in cash and cash equivalents............ (17,067) 29,410 9,708 Cash and cash equivalents at beginning of year.............. 39,994 10,584 876 --------- -------- -------- Cash and cash equivalents at end of year.................... $ 22,927 $ 39,994 $ 10,584 ========= ======== ========
The accompanying notes are an integral part of these financial statements. 27 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 in the United States 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. During 2000 and until the Plan was effective (see Note 2), the Company conducted its business 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 deemed subject to compromise at amounts reasonably expected to be paid. 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 balances at December 31, 2000 included $1.5 million that was restricted to funding expenditures on certain oil and gas properties. DERIVATIVE INSTRUMENTS Oil and gas prices have historically been volatile. The Company has entered and may continue to enter into derivative contracts to manage the risk associated with the price fluctuations affecting it by effectively fixing the price of certain sales volumes for certain time periods. Through December 31, 2000, the Company accounted for such contracts in accordance with Statement of Financial Accounting Standard ("SFAS") No. 80 "Accounting for Futures Contracts". 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. Effective January 1, 2001, the Company adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities." SFAS No. 133, as amended, establishes 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 derivative instruments that qualify as hedges requires gains and losses on such derivative instruments to be recognized in earnings in the period each such hedged transaction takes place. It also requires that a company formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. If derivatives originally qualifying and treated as hedges are terminated prior to maturity, the resulting gains or losses continue to be deferred until each such hedged transaction takes place or no longer meets qualifying conditions. See Note 9 for further discussion of the Company's price risk management activities. 28 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) FAIR VALUE OF FINANCIAL INSTRUMENTS The carrying value of certain financial instruments, including cash, cash equivalents, revolving credit debt, and short-term debt approximates estimated fair value due to their short-term maturities and varying interest rates. The estimated fair value of public debt is based upon quoted market values. Derivative financial instruments are carried at fair value. DEFERRED REVENUE As discussed in Note 2, the Company sold a Production Payment in connection with the Plan and recorded the net cash proceeds of approximately $175 million as deferred revenue on the balance sheet. In accordance with SFAS No. 19 "Financial Accounting and Reporting by Oil and Gas Producing Companies," deliveries under this Production Payment are recorded as non-cash oil and gas revenue with a corresponding reduction of deferred revenue at the average price per Mcf of natural gas and per barrel of oil received when the Production Payment was sold. The Company also reflects the production volumes and depletion expense as deliveries are made. However, the associated oil and gas reserves are excluded from the Company's reserve information and discounted future net cash flow data reported in Note 12. Since the sale of the Production Payment in February 2001 through December 31, 2001, the Company delivered 15.7 Bcfe, or 37% of the scheduled deliveries, and recorded $63.1 million of non-cash oil and gas revenue. Scheduled deliveries for 2002 are 11.2 Bcfe. 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 ("DD&A") of evaluated costs using the future gross revenue method based on recoverable reserves valued at current prices. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the DD&A calculation until a complete evaluation is made and it is determined whether or not proved reserves can be assigned to the properties. The costs of drilling an exploratory dry hole are included in the amortization base immediately upon determination that such a well is dry. Geological and geophysical costs not associated with specific unevaluated properties are included in the amortization base as incurred. Costs of unevaluated properties excluded from amortization were $8.5 million and $5.6 million at December 31, 2001 and 2000, respectively. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. Capitalized costs of oil and gas properties, net of accumulated DD&A 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. Proceeds from dispositions of oil and gas properties are credited to the cost center with no 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. 29 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) IMBALANCES The Company follows the sales method of accounting for natural gas revenues whereby revenues are recognized based on volume sold. The volume of gas sold may differ from the volume to which KCS is entitled based on its working interest. The Company has a reserve of $0.7 million for imbalances at December 31 for 2000 and 2001. STOCK COMPENSATION The cost of awards of restricted stock, determined as the fair market value of the shares at the date of grant is expensed ratably over the restricted period. See Note 4. 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 The following table sets forth the computation of basic and diluted earnings per share:
2001 2000 1999 ------- ------- ------- (AMOUNTS IN THOUSANDS EXCEPT PER SHARE DATA) Basic earnings per share: Net income............................................ $65,579 $41,523 $ 4,340 Less dividends and accretion of issuance costs on preferred stock.................................... 1,761 -- -- ------- ------- ------- Income available to common stockholders............... $63,818 $41,523 $ 4,340 ------- ------- ------- Average common stock outstanding...................... 31,668 29,266 29,263 ------- ------- ------- Basic earnings per share................................ $ 2.02 $ 1.42 $ 0.15 ======= ======= ======= Diluted earnings per share: Net income............................................ $65,579 $41,523 $ 4,340 ------- ------- ------- Average common stock outstanding...................... 31,668 29,266 29,263 Assumed conversion of convertible preferred stock..... 6,808 -- -- Dividends on convertible preferred stock.............. 232 -- -- Stock options and warrants............................ 120 39 25 ------- ------- ------- 38,828 29,305 29,288 ------- ------- ------- Diluted earnings per share.............................. $ 1.69 $ 1.42 $ 0.15 ======= ======= =======
OTHER COMPREHENSIVE INCOME Comprehensive income was $54.4 million in 2001, $41.5 million in 2000 and $4.3 million in 1999. In addition to net income, comprehensive income in 2001 includes accumulated other comprehensive loss of $11.2 million related to unrealized losses on derivative instruments. See Note 9 for further discussion of Other Comprehensive Income. 30 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 oil and gas properties. The Company's operations are conducted entirely in the United States. 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 may result 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 receivables is mitigated by the size and reputation of the companies to which the Company extends credit. NEW ACCOUNTING STANDARDS In July 2001, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standard ("SFAS") No. 143, "Accounting for Asset Retirement Obligations". SFAS No. 143 requires entities to record the fair value of a liability for legal obligations associated with the retirement obligations of tangible long-lived assets in the periods in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. The liability is accreted to the fair value at the time of settlement over the useful life of the asset, and the capitalized cost is depreciated over the useful life of the related asset. The standard is effective for fiscal years beginning after June 15, 2002, with earlier application encouraged. The Company is currently evaluating the effect of adopting SFAS No. 143 on its financial statements and has not yet determined the timing of adoption. In August 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS No. 144 addresses the financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121 but retains its fundamental provisions for the (a) recognition/measurement of impairment of long-lived assets to be held and used and (b) measurement of long-lived assets to be disposed of by sale. SFAS No. 144 also supersedes the accounting/reporting provisions of APB Opinion No. 30 for segments of a business to be disposed of but retains the requirement to report discontinued operations separately from continuing operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. SFAS No. 144 is effective for the Company beginning in 2002. The Company is currently evaluating the impact of this new standard. 2. REORGANIZATION On January 30, 2001, the Bankruptcy Court confirmed the Company's plan of reorganization ("the Plan") under 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 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. Under the terms of the Plan, the Company: 1) sold a 43.1 Bcfe (38.3 Bcf of gas and 797,000 barrels of oil) production payment ("Production Payment") to be delivered in accordance with an agreed schedule over a five year period for net proceeds of approximately $175 million and repaid all amounts outstanding under its existing bank credit facilities, 2) sold $30.0 million of 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 31 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 but without a change in interest rates, 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. Since the sale of the Production Payment in February 2001 through December 31, 2001, the Company delivered 15.7 Bcfe, or 37% of the required deliveries. For 2002, scheduled deliveries are 11.2 Bcfe. BACKGROUND During 1998, due to very low prices for natural gas and crude oil and to the 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 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 (the parent company only) under Chapter 11 of the Bankruptcy Code. 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 the Company's subsidiaries filed voluntary petitions under Chapter 11 of the Bankruptcy Code. On December 26, 2000, the Company, the unsecured creditors' committee and Credit Suisse First Boston reached agreement on the Plan. 32 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 3. RETIREMENT BENEFIT PLAN 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 compensation, as defined, 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, 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 $510,702 in 2001, $454,341 in 2000 and $221,520 in 1999. These amounts are included in general and administrative expense. 4. STOCK OPTION AND INCENTIVE PLANS On February 20, 2001 in connection with the Plan (see Note 2), the Company's 1992 Stock Plan and the 1994 Directors' Stock Plan and all outstanding options thereunder were cancelled. Also, 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. The 2001 Stock Plan provides that each non-employee director be granted stock options for 1,000 shares annually. This plan also provides that in lieu of cash, each non-employee director be issued KCS common stock with a fair market value equal to 50% of their annual retainer. The 2001 Stock Plan provides that the option price of shares issued be equal to the market price on the date of grant. All options expire 10 years after the date of grant. The 2001 Stock Plan provided for the issuance of up to 4,362,868 shares of KCS common stock. Restricted shares awarded under the 2001 Stock Plan have a fixed restriction period during which ownership of the shares cannot be transferred and the shares are subject to forfeiture if employment terminates. Restricted stock is considered to be currently issued and outstanding and has the same rights as other common stock. The cost of the awards of restricted stock, determined as the fair market value of the shares at the date of grant, is expensed ratably over the restricted period. Restricted stock totaling 479,297 shares was outstanding at December 31, 2001. At December 31, 2001, a total of 2,656,732 shares was available for future grants under the 2001 Stock Plan. 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 been determined consistent with SFAS No. 123, the Company's net income would have increased $2.7 million in 2001 and decreased $2.0 million in 2000 and $2.3 million in 1999. The impact on earnings per share would have been an increase of $0.09 per basic share ($0.07 diluted) in 2001, a decrease of $0.07 per basic and diluted share in 2000 and a decrease of $0.07 per basic and diluted share in 1999. 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 2001: risk-free interest rate of 5.4%; expected dividend yield of 0.00%; expected life of 10 years; expected stock price volatility of 85.3%. 33 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) As required under SFAS No. 123, a summary of the status of the stock options under the 2001 Stock Plan and the cancelled 1992 Stock Plan and the cancelled 1994 Directors' Stock Plan at December 31, 2001, 2000 and 1999 and changes during the years then ended is presented in the following tables:
2001 2000 1999 --------------------- -------------------- -------------------- WEIGHTED WEIGHTED WEIGHTED AVERAGE AVERAGE AVERAGE EXERCISE EXERCISE EXERCISE SHARES PRICE SHARES PRICE SHARES PRICE ---------- -------- --------- -------- --------- -------- Outstanding at beginning of year........................ 1,378,430 $10.66 1,519,630 $ 9.98 1,720,230 $10.37 Cancelled(a).................. (1,225,930) 11.75 -- -- -- -- Granted(b).................... 1,237,259 5.49 -- -- -- -- Exercised..................... (152,500) 1.86 -- -- -- -- Forfeited..................... (8,216) 5.51 (141,200) 3.40 (200,600) 13.34 ---------- ------ --------- ------ --------- ------ Outstanding at end of year.... 1,229,043 5.49 1,378,430 10.66 1,519,630 9.98 ---------- ------ --------- ------ --------- ------ Exercisable at end of year.... 6,000 $ 9.61 1,019,580 $10.03 899,355 $ 7.84 ---------- ------ --------- ------ --------- ------ Weighted average fair value of options granted............. $ 4.52 $ -- $ -- ------ ------ ------
--------------- (a) Cancelled in connection with the Company's plan of reorganization (b) Granted under new Stock Plan approved in the Company's plan of reorganization The following table summarizes information about stock options outstanding at December 31, 2001:
NUMBER WEIGHTED NUMBER RANGE OF OUTSTANDING AT AVERAGE WEIGHTED EXERCISABLE AT WEIGHTED EXERCISE DECEMBER 31, REMAINING AVERAGE DECEMBER 31, AVERAGE PRICES 2001 CONTRACTUAL LIFE EXERCISE PRICE 2001 EXERCISE PRICE ----------- -------------- ---------------- -------------- -------------- -------------- $5.21-$6.00 1,220,943 9.14 $5.47 -- $ -- 6.01- 9.61 8,100 9.38 8.87 6,000 9.61 ----------- --------- ---- ----- ----- ----- $5.21-$9.61 1,229,043 9.14 $5.49 6,000 $9.61 =========== ========= ==== ===== ===== =====
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 9,160 shares, 100 shares and 14,775 shares during 2001, 2000 and 1999, respectively. At December 31, 2001, there were 788,848 shares available for issuance under the Program. 34 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. DEBT Debt consists of the following:
DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- (DOLLARS IN THOUSANDS) 11% Senior Notes............................................ $ 79,800 $150,000 8 7/8% Senior Subordinated Notes............................ 125,000 125,000 Revolving Credit Agreement.................................. -- 34,241 Credit Facility............................................. -- 42,464 -------- -------- 204,800 351,705 Classified as short-term debt............................... -- 76,705 -------- -------- Long-term debt.............................................. $204,800 $275,000 ======== ========
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 Plan, the indenture governing the Senior Notes was amended. 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 Subordinated Notes and the Company's common stock, prohibit the Company from purchasing or redeeming the Series A Convertible Preferred Stock and prohibit the Company from paying any cash dividends on capital stock. The Company redeemed $70.2 million of Senior Notes in 2001 of which $60.0 million was in connection with the Plan. Additionally, the Company redeemed $7.3 million of Senior Notes in January 2002. In order to meet its obligations under the Senior Notes due in January 2003, the Company has curtailed its planned capital expenditures for 2002 to be between $40 million and $55 million. In addition, the Company plans to sell $25 to $50 million of non-core assets, the proceeds of which will largely be used to redeem Senior Notes. The Company anticipates that cash flow and proceeds from asset sales, combined with additional amounts which could be refinanced or made available under its credit facility should be more than sufficient to carry out its business operations and meet the Senior Note maturity obligations. The Company is committed to modify its capital investment and asset divestiture programs if necessary in order meet its Senior Note obligations. SENIOR SUBORDINATED NOTES On January 15, 1998, the Company completed a public offering of $125.0 million of Senior Subordinated Notes at an interest rate of 8 7/8% (the "Subordinated Notes"). The Subordinated Notes are non-callable for five years and are unsecured subordinated obligations of the Parent. The subsidiaries of the Parent have guaranteed the Subordinated Notes on an unsecured subordinated basis. 35 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) On February 20, 2001, in connection with the Plan (see Note 2), the indenture governing the Subordinated Notes was amended to, among other things, accelerate the maturity date of the Subordinated Notes from January 15, 2008 to January 15, 2006. The 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 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. CREDIT AGREEMENT On November 28, 2001 the Company entered into a three-year credit agreement ("Credit Agreement") with certain banks. The Credit Agreement is to be used for general corporate purposes, including support of the Company's capital expenditure program, repurchase of the Senior Notes and working capital. The stated amount of this Credit Agreement is $100 million, with the amount that is available determined semi-annually based on the lenders' valuation of the Company's oil and gas reserves and other factors including the Company's other debt obligations and obligations under the Production Payment sold as discussed in Note 2. The initial amount available, or borrowing base, at December 31, 2001 was $32.5 million. Loans under the Credit Agreement are on a revolving basis, and the Company is permitted to choose interest rate options based on the lead bank's prime rate or LIBOR. The applicable margin above prime or LIBOR ranges between 0% and 3%, based on the type of interest rate chosen and the percentage of the borrowing base that is outstanding. A commitment fee of 0.5% is paid on the unused portion of the borrowing base. Substantially all of the Company's oil and gas assets are pledged to secure the Credit Agreement. The Credit Agreement contains certain restrictive covenants, including a minimum level of working capital, as defined, a ratio of adjusted EBITDA, as defined, to interest expense of not less than 2.75 to 1.0 and ratio of debt to adjusted EBITDA of less than 3.5 to 1.0. The Credit Agreement contains other restrictive covenants which, among other things, limit the Company's ability to incur additional indebtedness and sell assets, require payment upon a change of control, prohibit the Company from purchasing and redeeming the Company's common stock or the Series A Convertible Preferred Stock and prohibit the Company from paying any cash dividends on common stock. The Credit Agreement provides for acceleration, to November 15, 2002, of all payments due if the Senior Notes balance outstanding on that date is: 1) greater than $20 million or 2) greater than the sum of cash plus credit available under the agreement. At December 31, 2001, there were no outstanding loans under the Credit Agreement. In January 2002, the Company borrowed $10.8 million under the Credit Agreement, of which $7.3 million was used to repurchase Senior Notes. REVOLVING CREDIT AGREEMENT On February 20, 2001 all outstanding principal, interest and fees under the Company's revolving credit agreement ("Revolving Credit Agreement") were paid in full as part of the 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 subsidiaries and certain purchased VPP's 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 36 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) applicable spread was based on the percentage of the borrowing base 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 from January 1, 2001 until repayment on February 20, 2001 was 9.16%. 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. 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 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 from January 1, 2001 until repayment on February 20, 2001 was 9.37%. 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. 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 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, 2001 were $79.4 million and $85.0 million, respectively. These values were estimated based upon the December 31, 2001 quoted market price of $99.5 for the Senior Notes and $68.0 for the Senior Subordinated Notes. 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 carrying amount of the remaining debt at December 31, 2000 approximated fair value. 37 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The scheduled maturities of the Company's debt during the next five years are as follows: 2002 $-0- million, 2003 $79.8 million, 2004 $-0- million, 2005 $-0- million and 2006 $125.0 million. On February 20, 2001, in connection with the Plan, the Company paid $60.3 million to holders of the Senior Notes and the Senior Subordinated Notes for interest accrued but not paid during the bankruptcy period which included interest on interest. Total interest payments were $71.5 million in 2001, $8.6 million in 2000 and $25.4 million in 1999. The Company is currently in compliance with all debt covenants. 6. REDEEMABLE CONVERTIBLE PREFERRED STOCK In connection with the Plan (see Note 2), the Company issued 30,000 shares of Series A Convertible Preferred Stock, $0.01 par value ("Preferred Stock") at a price of $1,000 per share convertible at any time into a total of 10,000,000 shares of KCS Common Stock at a conversion price of $3.00 per share. Net proceeds from the issuance of the Preferred Stock was $28.4 million. The Preferred Stock pays a 5% per annum dividend payable quarterly in cash or, during the first two years following issuance, in shares of KCS common stock. The Preferred Stock is redeemable at the option of the Company after February 20, 2002 if the closing price of the Common Stock exceeds $6.00 per share for 25 out of 30 consecutive trading days or at the election of holders of a majority of the outstanding shares of Preferred Stock on or after January 31, 2009. In connection with the issuance of the Preferred Stock, the Company issued the placement agent warrants, which expire on February 19, 2006, to purchase 400,000 shares of KCS Energy, Inc. common stock at $4.00 per share. The Preferred Stock is not anticipated to have any voting rights, except upon certain defaults or failure to pay dividends and as otherwise required by law. The Preferred Stock ranks senior to Common Stock or any future issue of preferred stock. The Preferred Stock has a liquidation preference of $1,000 per share plus accrued and unpaid dividends. As a result of conversions of the Preferred Stock, 4.6 million of shares of common stock were issued in 2001. In addition 0.2 million shares of common stock were issued as dividends on the Preferred Stock. 7. LEASES Future minimum lease payments under current non-cancelable operating leases are as follows: $0.7 million in 2002, $0.7 million in 2003, $0.8 million in 2004, $0.8 million in 2005, $0.7 million in 2006 and $0.3 million thereafter. Lease payments charged to operating expenses amounted to $0.8 million, $0.6 million and $0.7 million during 2001, 2000 and 1999, respectively. 38 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, -------------------------------- 2001 2000 1999 --------- --------- -------- (DOLLARS IN THOUSANDS) Current benefit....................................... $ -- $ -- $ -- Deferred benefit, net................................. (8,359) -- -- -------- -------- ------- Federal income tax expense benefit.................... (8,359) -- -- State income tax (deferred benefit $600 in 2001 and $0 in 2000 and 1999)................................... -- -- -- -------- -------- ------- (8,359) -- -- ======== ======== ======= Reconciliation of federal income tax expense (benefit) at statutory rate to provision for income taxes: Income before income taxes............................ $ 57,220 41,523 $ 4,340 -------- -------- ------- Tax provision at 35% statutory rate................... 20,027 14,533 1,519 Valuation allowance................................... (28,401) (14,544) (1,532) Other, net............................................ 15 11 13 -------- -------- ------- $ (8,359) -- $ -- ======== ======== =======
The primary differences giving rise to the Company's net deferred tax assets are as follows:
DECEMBER 31, ----------------------- 2001 2000 ---------- ---------- (DOLLARS IN THOUSANDS) Income tax effects of: Property related items.................................... $ (1,879) $ 16,478 Alternative minimum tax credit carry forwards............. 378 378 Net operating loss carry forward.......................... 78,078 80,632 Statutory depletion carryforward.......................... 400 400 Deferred financing costs.................................. 1,140 1,670 Accrued expenses.......................................... 958 662 Bad debts................................................. 1,466 153 State income tax.......................................... 390 -- Deferred revenue and other................................ (2,505) (2,505) Valuation allowance....................................... (62,506) (97,868) -------- -------- $ 15,920 $ -- ======== ========
State income tax payments were $0.1 million in 2001. No income tax payments were made in 2000 and 1999. Due to the significant losses recorded in 1998 and the uncertainty of future oil and natural gas commodity prices, the Company 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, the Company considered several factors, including uncertainty of the Company's ability to generate sufficient income in order to realize its future tax benefits. A substantial portion of the valuation allowances provided by the Company relates to loss 39 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) and credit carryforwards. To determine the proper amount of valuation allowances with respect to these carryforwards, the Company evaluated all appropriate factors, including any limitations concerning their use resulting from consequences of its bankruptcy or otherwise and the year the carryforwards expire, as well as the levels of taxable income necessary for utilization. The Company believes that it will more likely than not be able to realize the benefit attributable to the loss and credit carryforwards for which valuation allowances are not provided. The valuation allowance will continue to be monitored for potential adjustments as future events so indicate. At December 31, 2001, the Company had tax net operating losses ("NOLs") of approximately $223.1 million available to offset future taxable income, of which approximately $6.5 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 $26.0 million will expire in 2020. 9. FINANCIAL INSTRUMENTS Oil and gas prices have historically been volatile. The Company has, at times, utilized derivative contracts, including swaps, futures contracts, options and collars, to manage this price risk. 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 for the period involved. Futures Contracts. Oil or natural gas futures contracts require the Company to sell and the counterparty to buy oil or natural gas at a future time at a fixed price. Option Contracts. Option contracts provide the right, not the obligation, 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 from selling the right for a counter party to buy a specified quantity of oil or gas production at a fixed price. Price Collars. Selling a call option and buying a put option creates a "collar" whereby the Company establishes a floor and ceiling price for a specified quantity of future production. Effective January 1, 2001, the Company adopted SFAS No. 133. SFAS No. 133, as amended, establishes accounting and disclosure standards requiring that all derivative instruments be recorded in the balance sheet as an asset or liability, measured at fair value. It further requires that changes in a derivative instrument's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. To qualify as a hedge, these transactions must be formally documented and designated as a hedge and the changes in their fair value must correlate with changes in the price of anticipated future sales of production. Changes in the market value of these contracts are deferred through other comprehensive income ("OCI") until the gain or loss is recognized on the hedged commodity. If these contracts are terminated prior to maturity, the resulting gains or losses continue to be deferred until the hedged commodity was scheduled to be recognized in income. If the contract is not designated as a hedge, changes in fair value are recorded currently in income. Upon adoption of SFAS No. 133, the Company recorded a liability of $43.8 million representing the fair market value of its derivative instruments at adoption, a related deferred tax asset of $15.3 million and an after-tax cumulative effect of change in accounting principle of $28.5 million to accumulated OCI. The Company elected not to designate its then existing derivative instruments as hedges which, subsequent to adoption of SFAS No. 133, would require that changes in a derivative investment's fair value be recognized currently in earnings. However, SFAS No. 133 requires the Company's derivative instruments that had been designated as cash flow hedges under accounting principles generally accepted prior to the initial application of SFAS No. 133 to continue to be accounted for as cash flow hedges with the transition adjustment reported as a cumulative-effect-type adjustment to accumulated OCI as mentioned above. 40 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In February 2001, the Company terminated certain derivative instruments in connection with its emergence from bankruptcy for a cash payment of $28.0 million, which was offset against the accrued liability recorded in connection with the adoption of SFAS No. 133. During the quarter ended March 31, 2001, as a result of market price decreases, the ultimate cost to settle the remaining derivative instruments in place at January 1, 2001 was reduced by $7.7 million. This non-cash gain was recorded in other revenue during the quarter. The actual cost to settle the remaining derivatives was $8.1 million. During 2001, $15.5 million, net of tax, of the above $28.5 million charged to OCI was reclassified into earnings. The $12.9 million remaining in accumulated other comprehensive income will be amortized into earnings over the original term of the derivative instruments, which extends through August 2005 ($4.4 million in 2002, $3.6 million in 2003, $2.9 million in 2004 and $2.0 million in 2005). During 2001, all derivative contracts, other than the derivatives terminated in connection with emergence from bankruptcy as discussed above, were with Enron North America Corp., a subsidiary of Enron Corp. At the end of November, the Company had price swap contracts, designated as hedges, covering 0.3 million MMBtu of December 2001 gas production; and price swaps and collars covering 6.2 million MMBtu of 2002 gas production. The value of these derivatives at that time was $2.7 million. Because of Enron's financial condition, the Company concluded that these derivative contracts no longer qualified for hedge accounting treatment. The Company unwound the December derivatives and certain swap contracts covering 1.0 million MMBtu of 2002 gas production. In December 2001, Enron North America Corp. and Enron Corp. filed for bankruptcy protection and did not pay the Company for the contracts that were unwound. At December 31, 2001, $2.3 million in unrealized gains related to 2002 gas production is included in accumulated OCI and will be reclassified into earnings over the original term of the derivative instruments. The related assets were reclassified as a receivable from Enron and a provision for doubtful accounts was established. At December 31, 2001, the Company was party to no derivative contracts other than the Enron contracts described above. The Company realized $22.1 million in net hedging losses and $8.6 million net non-hedge derivative losses during 2001. At December 31, 2000, the Company had collars in place covering 3.6 million MMBtu of gas production in the first quarter of the year 2001 with an unrealized loss of $16.7 million, and price swaps in place covering 10.6 million MMBtu of 2001 through 2005 gas production with an unrealized loss of $27.1 million. All the derivative contracts in place at December 31, 2000 were terminated or settled during the first quarter of 2001 as described above. 10. LITIGATION ENVIRONMENTAL SUITS The Company was a defendant in a lawsuit originally brought by InterCoast Energy Company and MidAmerican Capital Company ("Plaintiffs") against KCS Energy, Inc., KCS Medallion Resources, Inc. (now known as KCS Resources, Inc.) and Medallion California Properties Company ("KCS Defendants"), and Kerr-McGee Oil & Gas Onshore LP and Kerr-McGee Corporation ("Kerr-McGee Defendants") in the 234th Judicial District Court of Harris County, Texas under Cause Number 1999-45998. The suit sought 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 located in Los Angeles County, California which are covered by an Oil & Gas Lease dated June 13, 1935, from Newhall Land and Farming Company, as Lessor, to Barnsdall Oil Company, as Lessee (the "RSF Lease") and by an Oil and Gas Lease dated June 6, 1941, from the Newhall Corporation, as Lessor, to C. G. Willis, as Lessee (the "Ferguson Lease" and together with the RSF Lease, the "Leases"). The Kerr-McGee Defendants, KCS Defendants and Plaintiffs entered into an Agreed Interlocutory Judgment that contains clarification of the language of the 1990 Agreement between predecessors of the KCS Defendants and the Kerr-McGee Defendants (the "1990 Agreement") under which the Leases were 41 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) transferred from Kerr-McGee's predecessor to predecessors of Medallion California Properties Company ("MCPC"). The Court previously entered the Agreed Interlocutory Judgment, which essentially disposed of interpretation questions concerning the 1990 Agreement. After entry of the Agreed Interlocutory Judgment, the remaining issues in the case concerned the interpretation of the 1996 Stock Purchase Agreement through which certain of the KCS Defendants acquired the stock of MCPC. Specifically, the remaining issues involved the extent to which Plaintiffs are obligated to indemnify the KCS Defendants for environmental investigation costs previously incurred by the KCS Defendants and also for costs of defense and liability to the KCS Defendants, if any, in the California litigation described below. By Compromise and Settlement Agreement dated as of October 19, 2001, the Plaintiffs and KCS Defendants agreed: (i) to settle those issues dealing with the Plaintiffs' obligations to reimburse costs previously incurred in connection with defense of the California case described below; (ii) to provide prospectively for the control of defense and settlement and the sharing of defense costs in the California case described below; and (iii) to defer any disputes concerning the respective liability of Plaintiffs and KCS Defendants for any individual claims, if any, until the extent of such individual claim liability, after giving effect to indemnification obligations under the 1990 Agreement, is fully and finally determined. MCPC is a defendant in a lawsuit filed January 30, 2001, by The Newhall Land and Farming Company ("Newhall") against MCPC 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. MCPC claims that Newhall is not entitled to lease termination as a remedy and that Kerr-McGee and InterCoast and MidAmerican owe indemnities to MCPC for defense and certain potential liability under Newhall's action, all as more particularly described in the Harris County, Texas litigation described above. Discovery is ongoing, and the lawsuit is set for trial in January 2003. 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. 42 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 11. QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERS --------------------------------------------- FIRST SECOND THIRD FOURTH --------- --------- --------- --------- (DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA) 2001 Revenue...................................... $72,709 $49,038 $39,466 $30,778 Operating income............................. 44,097 22,941 13,334 276 Net income (loss)............................ $40,980 $19,228 $ 8,999 $(3,628) Basic earnings (loss) per common share....... $ 1.38 $ 0.63 $ 0.27 $ (0.11) Diluted earnings (loss) per common share..... $ 1.21 $ 0.48 $ 0.22 $ (0.11)
QUARTERS -------------------------------------------- FIRST SECOND THIRD FOURTH ------- ------- ------- ------- 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
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 are presented pursuant to SFAS No. 69 "Disclosure 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 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, 2001 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 Henry Hub spot market prices of $2.65, $9.53 and $2.33 per MMBTU adjusted by lease for BTU content, transportation fees and regional price differentials at December 31, 2001, 2000 and 1999, respectively. Oil prices were based on West Texas Intermediate (WTI) posted prices of $16.75, $23.75 and $22.75 at December 31, 2001, 2000 and 1999, respectively adjusted by lease for gravity, transportation fees and regional price differentials. Purchased VPP volumes represent oil and gas reserves acquired 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. 2001 reserves have been reduced to reflect the sale of the Production Payment of 38.3 Bcf of gas and 797,000 barrels of oil in connection with the Plan (see Note 2). 43 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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, ----------------------------------- 2001 2000 1999 ---------- ---------- --------- (DOLLARS IN THOUSANDS) Revenue(a)....................................... $ 174,434 $ 190,511 $ 134,124 ---------- ---------- --------- Production (lifting) costs and taxes............. 38,651 34,406 32,275 Technical support and other...................... 5,049 4,601 4,432 Depreciation, depletion and amortization......... 58,172 50,316 50,816 ---------- ---------- --------- Total expenses.............................. 101,872 89,323 87,523 ---------- ---------- --------- Pretax income (loss) from producing activities... 72,562 101,188 46,601 Income tax benefit............................... (8,359) -- -- ---------- ---------- --------- Results of oil and gas producing activities (excluding corporate overhead and interest).... $ 80,921 $ 101,188 $ 46,601 ========== ========== ========= Depreciation, depletion and amortization rate per dollar of revenue.............................. $ 0.33 $ 0.26 $ 0.38 ========== ========== ========= Capitalized costs incurred: Property acquisition........................... $ 26,770 $ 7,264 $ 25,847 Exploration.................................... 15,321 19,302 8,949 Development.................................... 42,942 36,032 25,204 ---------- ---------- --------- Total capitalized costs incurred............ $ 85,033 $ 62,598 $ 60,000 ========== ========== ========= Capitalized costs at year end: Proved properties.............................. $1,097,143 $1,020,099 $ 955,340 Unproved properties............................ 8,470 5,582 8,437 ---------- ---------- --------- 1,105,613 1,025,681 963,777 Less accumulated depreciation, depletion and amortization................................... (837,096) (780,512) (731,496) ---------- ---------- --------- Net investment in oil and gas properties......... $ 268,517 $ 245,169 $ 232,281 ========== ========== =========
--------------- (a) Includes amortization of deferred revenue of $63,089 in 2001, related to volumes delivered under the Production Payment sold in February. See Note 2. DISCOUNTED FUTURE NET CASH FLOWS (UNAUDITED) 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. 44 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
DECEMBER 31, ---------------------------------- 2001 2000 1999 --------- ---------- --------- (DOLLARS IN THOUSANDS) Future cash inflows............................... $ 631,061 $2,234,831 $ 713,067 Future costs: Production...................................... (228,701) (451,763) (235,328) Development..................................... (64,251) (54,568) (41,751) Future income taxes............................. -- (428,644) -- --------- ---------- --------- Future net revenues............................. 338,109 1,299,856 435,988 Discount -- 10%................................. (135,921) (447,248) (143,198) --------- ---------- --------- Standardized measure of discounted future net cash flows(a)........................................ $ 202,188 $ 852,608 $ 292,790 ========= ========== =========
CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
FOR THE YEAR ENDED DECEMBER 31, --------------------------------- 2001 2000 1999 --------- --------- --------- (DOLLARS IN THOUSANDS) Balance, beginning of year........................ $ 852,608 $ 292,790 $ 293,759 Increases (decreases) Sales, net of production costs.................. (72,694) (156,105) (101,849) Net change in prices, net of production costs... (660,420) 729,127 41,610 Discoveries and extensions, net of future production and development costs............. 37,865 153,415 25,402 Changes in estimated future development costs... 7,046 (9,953) 344 Change due to acquisition of reserves in place........................................ 27,591 34,087 41,142 Development costs incurred during the period.... 10,689 19,302 8,400 Revisions of quantity estimates................. (14,433) (12,720) (10,666) Accretion of discount........................... 85,261 29,279 28,068 Net change in income taxes...................... 251,871 (251,871) -- Sales of reserves in place...................... (341,223) (344) (24,345) Changes in production rates (timing) and other........................................ 18,027 25,601 (9,075) --------- --------- --------- Net increase (decrease)......................... (650,420) 559,818 (969) --------- --------- --------- Balance, end of year(a)........................... $ 202,188 $ 852,608 $ 292,790 ========= ========= =========
--------------- (a) Excludes $111,880 of deferred revenue related to the Production Payment sold in 2001 as discussed in Note 2. RESERVE INFORMATION (UNAUDITED) The following information with respect to the Company's 2001 net proved oil and gas reserves are estimates based on reports prepared by the Company and audited 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 45 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) from new wells or from existing wells after material recompletion expenditures. All of the Company's reserves are located within the United States.
2001 2000 1999 ---------------- ---------------- ---------------- GAS OIL GAS OIL GAS OIL MMCF MBBL MMCF MBBL MMCF MBBL ------- ------ ------- ------ ------- ------ Proved developed and undeveloped reserves Balance, beginning of year... 211,628 8,986 227,119 8,341 257,690 8,693 Production(a)................ (23,133) (1,273) (41,089) (1,570) (50,471) (1,408) Discoveries, extensions, etc....................... 35,250 725 25,715 1,303 13,953 777 Acquisition of reserves in place..................... 18,382 140 5,921 293 31,857 906 Sales of reserves in place(b).................. (41,759) (1,064) (213) (40) (18,118) (604) Revisions of estimates....... (10,227) (870) (5,825) 659 (7,792) (23) ------- ------ ------- ------ ------- ------ Balance, end of year........... 190,141 6,644 211,628 8,986 227,119 8,341 ======= ====== ======= ====== ======= ====== Proved developed reserves Balance, beginning of year... 173,995 7,885 175,896 7,568 204,327 6,963 ------- ------ ------- ------ ------- ------ Balance, end of year......... 139,137 5,915 173,995 7,885 175,896 7,568 ======= ====== ======= ====== ======= ======
--------------- (a) 2001 production excludes volumes produced and delivered in respect to the Production Payment (b) The Company sold a Production Payment in connection with the Plan as discussed in Note 2. The Production Payment for 38.3 Bcf of gas and 797,000 barrels of oil is reflected as sales of reserves in place in the table above. 46 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS OR ACCOUNTING AND FINANCIAL DISCLOSURE None. 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 2002 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 and the related Report of Independent Public Accountants are presented in Item 8 of this Form 10-K.
PAGE ----- Report of Independent Public Accountants.................... 23 Statements of Consolidated Operations for the years ended December 31, 2001, 2000 and 1999.......................... 24 Consolidated Balance Sheets at December 31, 2001 and 2000... 25 Statements of Consolidated Stockholders' (Deficit) Equity for the years ended December 31, 2001, 2000 and 1999...... 26 Statements of Consolidated Cash Flows for the years ended December 31, 2001, 2000 and 1999.......................... 27 Notes to Consolidated Financial Statements.................. 28-46
(3) Exhibits See "Exhibit Index" located on page 49 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. There were no reports on Form 8-K filed during the three months ended December 31, 2001. 47 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: 3/29/02 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 3/29/02 ------------------------------------------------ Officer and Director James W. Christmas /s/ STEWART B. KEAN Chairman and Director 3/28/02 ------------------------------------------------ Stewart B. Kean /s/ G. STANTON GEARY Director 3/27/02 ------------------------------------------------ G. Stanton Geary /s/ JAMES E. MURPHY, JR. Director 3/29/02 ------------------------------------------------ James E. Murphy, Jr. /s/ ROBERT G. RAYNOLDS Director 3/26/02 ------------------------------------------------ Robert G. Raynolds /s/ JOEL D. SIEGEL Director 3/29/02 ------------------------------------------------ Joel D. Siegel /s/ CHRISTOPHER A. VIGGIANO Director 3/29/02 ------------------------------------------------ Christopher A. Viggiano /s/ FREDERICK DWYER Vice President, Controller and 3/29/02 ------------------------------------------------ Secretary Frederick Dwyer
48 EXHIBIT INDEX
EXHIBIT NUMBER 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 April 2, 2001. (3)i Restated Certificate of Incorporation of KCS Energy, Inc. -- filed with the SEC as Exhibit (3)i to Form 10-K on April 2, 2001. ii Certificate of Designation, Preferences, Rights and Limitations of Series A Convertible Preferred Stock of KCS Energy, Inc. -- filed with the SEC as Exhibit (3)ii to Form 10-K on April 2, 2001. iii Restated By-Laws of KCS Energy, Inc. -- filed with the SEC as Exhibit (3)iii to Form 10-K on April 2, 2001. (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 with the SEC as Exhibit (4)iii to Form 10-K on April 2, 2001. 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 with the SEC as Exhibit (4)v to Form 10-K on April 2, 2001. 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 with the SEC as Exhibit (4)vii to Form 10-K on April 2, 2001. (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 with the SEC as Exhibit (10)iii to Form 10-K on April 2, 2001. iv KCS Energy, Inc. Savings and Investment Plan and related Adoption Agreement -- filed herewith. v 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 with the SEC as Exhibit (10)vi to Form 10-K on April 2, 2001. vi Credit Agreement among KCS Energy, Inc., Canadian Imperial Bank of Commerce, New York Agency, as Agent, CIBC, Inc., as Collateral Agent and the lenders party thereto -- filed herewith. vii Employment agreement between KCS Energy, Inc. and James W. Christmas -- filed herewith.* viii Employment agreement between KCS Energy, Inc. and William N. Hahne -- filed herewith.* ix Employment agreement between KCS Energy, Inc. and Harry Lee Stout -- filed herewith.* x Employment agreement between KCS Energy, Inc. and J. Chris Jacobsen -- 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. (99)i Letter to the Securities and Exchange Commission regarding Arthur Andersen LLP.
--------------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit. 49