-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, NJy5YjQfc3cp2wa8Gjw3fKtB6Cct47Pfs/hMKeqwCnowHMxGrQKkjYaEtlXrn9c7 Mhou9nPDma5qiij6FpQhrA== 0000950123-98-003732.txt : 19980414 0000950123-98-003732.hdr.sgml : 19980414 ACCESSION NUMBER: 0000950123-98-003732 CONFORMED SUBMISSION TYPE: 10-K405/A PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980413 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: KCS ENERGY INC CENTRAL INDEX KEY: 0000832820 STANDARD INDUSTRIAL CLASSIFICATION: WHOLESALE-PETROLEUM & PETROLEUM PRODUCTS (NO BULK STATIONS) [5172] IRS NUMBER: 222889587 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405/A SEC ACT: SEC FILE NUMBER: 001-13781 FILM NUMBER: 98592382 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 9086321770 FORMER COMPANY: FORMER CONFORMED NAME: KCS GROUP INC DATE OF NAME CHANGE: 19920310 10-K405/A 1 KCS ENERGY, INC. 1 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K/A |X| ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1997 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 incorporation or organization) Identification No.) 379 Thornall Street, Edison, New Jersey 08837 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code: (732) 632-1770 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 25,934,553 shares of the Common Stock held by non-affiliates of the Registrant at the $17.75 closing price on February 27, 1998 was $460,338,316. Number of shares of Common Stock outstanding as of the close of business on February 27, 1998: 29,455,294 Documents Incorporated By Reference Part III incorporates information by reference to Notice of and Proxy Statement for the 1998 Annual Meeting of Shareholders to the extent indicated herein. 2 EXPLANATORY NOTE: This Form 10-K/A is being filed to correct certain numbers set forth in the table under the caption "Acreage" in Item 2 hereof. The Company has elected to refile the entire text of the original Form 10-K rather than filing an amendment that includes only Item 2. 3 KCS ENERGY, INC. FORM 10-K Report for the Year Ended December 31, 1997 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, development and production of oil and gas. The Company was formed in 1988 in connection with the spin-off of the non-utility operations of NUI Corporation, a New Jersey-based natural gas distribution company that had been engaged in the oil and gas exploration and production business since the late 1960s. The Company's operations are primarily focused in the Rocky Mountain, Gulf Coast, and Mid-Continent/West Texas regions. Additionally, the Company augments its working interest ownership of properties with a volumetric production payment ("VPP") program to acquire oil and gas reserves from properties which to date have been located primarily in the Gulf of Mexico and Michigan. Several important developments have had and will continue to have a significant impact on the Company's financial condition and results of operations. On December 23, 1996, the Company and Tennessee Gas Pipeline Company ("Tennessee Gas") entered into a settlement covering all claims and litigation between them related to the above-market, take-or-pay contract (the "Tennessee Gas Contract"). As part of the settlement, the Tennessee Gas Contract was terminated effective January 1, 1997, approximately two years prior to its expiration date. See Note 10 to Consolidated Financial Statements. Prior to its termination, the Tennessee Gas Contract had a material and positive effect on the Company's gas revenue, income and cash flow. As of December 31, 1996, the Company completed the arrangements for the Medallion Acquisition (see Note 3 to Consolidated Financial Statements), effectively doubling its oil and gas reserves and giving it a substantial presence in the Mid-Continent/West Texas region. In January 1997, the Company completed a public offering of six million shares of common stock. The net proceeds to the Company of approximately $110.6 million were used to reduce outstanding indebtedness under the Company's bank credit facilities. During 1997, the Company sold its principal natural gas transportation asset, the Texas intrastate pipeline, and its third-party gas marketing operations realizing proceeds of $28.5 million and an after-tax gain of $5.4 million. Accordingly, the financial statements included in this annual report have been restated to reflect the natural gas transportation and marketing operations as discontinued operations. These developments have transformed the Company from an enterprise heavily dependent on the Bob West Field and the Tennessee Gas Contract, with marketing and transportation operations, to a Company focused on exploration and production, with a portfolio of properties in three core operating areas - the Gulf Coast region, the Rocky Mountain region and the Mid-Continent/West Texas region-, and its VPP program. Production 1 4 from the Bob West Field, which in 1995 accounted for 34% of total production and 72% of the Company's oil and gas revenues, accounted for less than 5% of total production and oil and gas revenue in 1997. 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 have been 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 increases in regulatory requirements, some of which 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. Narrative description of business Oil and Gas Exploration and Production 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 acquisitions and the exploration, development, production and marketing of oil and gas, as well as contracting for equipment and securing personnel. Oil and gas prices have historically been volatile and are expected to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include political conditions in the Middle East and elsewhere, 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. One customer, Tennessee Gas, accounted for approximately 4% and 40% of the Company's consolidated revenue for the years ended December 31, 1997 and 1996, respectively. No other single customer accounted for more than 10% of the Company's consolidated revenues in 1997 or 1996. Development and Production Activities During the three-year period ended December 31, 1997, the Company participated in the drilling of 186 development wells with a 86% success rate. During 1997, the Company substantially increased its level of development drilling in the Manderson Field, drilling 38 wells, 20 of which have been completed to date with the balance awaiting completion and tie-in. The Company's activities are currently focused on the Manderson Field in the Big Horn Basin as well as the Wind River and Green River Basins of Wyoming, the Langham Creek Area and Glasscock Ranch Field in Texas and the Laurel Ridge and Elm Grove fields in Louisiana. The Company has currently identified over 600 development drilling and recompletion locations, representing approximately a four-year inventory, and has initially budgeted $75 million for development activities in 1998. The Company plans to drill, recomplete or workover as many as 140 wells in 1998 and focus its development drilling program primarily in the Rocky Mountain and onshore Gulf Coast regions discussed above and in the Sawyer Canyon Field, the Elm Grove Field and several other prospects in the Mid-Continent/West Texas region. Exploration Activities During the three-year period ended December 31, 1997, the Company participated in the drilling of 75 exploratory wells with a 43% success rate. Discoveries included wells in the Langham Creek Area, the Franklin Deep Field in Louisiana and Laurel Ridge Field. During 1997, the Company participated in the drilling of 33 exploratory wells and completed 13 wells. The Company's policy is to commit no more than 25% of its cash flow to exploration activities and generally no more than $750,000 for any single well. The company has established an initial budget of $20 million for exploration in 1998 and intends to participate in drilling a wide variety of prospects, including both low-risk and high-risk, high-potential prospects in order to maintain a balanced program with the potential for significant reserve additions. During 1998, the Company plans to participate in the drilling of up to 40 exploratory prospects and to continue 3-D and 2-D seismic data acquisition and analysis. 2 5 Volumetric Production Payment Program The Company augments its working interest ownership of properties with a VPP program, a method of acquiring oil and gas reserves scheduled to be delivered in the future at a discount to the current market price in exchange for an up-front cash payment. A VPP is comparable to a term royalty interest in oil and gas properties and entitles the Company to a priority right to a specified volume of oil and gas reserves scheduled to be produced and delivered over a stated time period. Although specific terms of the Company's VPPs vary, the Company is generally entitled to receive delivery of its scheduled oil and gas volumes at agreed delivery points, free of drilling and lease operating costs and, in certain cases, free of state severance taxes. The Company believes that its VPP program diversifies its reserve base and achieves attractive rates of return while minimizing the Company's exposure to certain development, operating and reserve volume risks. Typically, the estimated proved reserves of the properties underlying a VPP are substantially greater than the specified reserve volumes required to be delivered pursuant to the production payment. Since the inception of the VPP program in August 1994 through December 31, 1997, the Company had invested $124.5 million under the VPP program and had acquired proved reserves of 70.1 Bcf of gas and 1.6 million barrels of oil through 27 separate transactions. The Company has recovered approximately $85.6 million in revenue from the sale of oil and gas acquired under the program, with 37.4 Bcf of gas and 1.0 million barrels of oil scheduled for future deliveries. Raw Materials The Company obtains its raw materials (principally natural gas and oil) 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. Regulation General. The Company's business is affected by numerous governmental laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the energy industry. Changes in any of these laws and regulations could have a material adverse effect on the Company's business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to the Company, the Company cannot predict the overall effect of such laws and regulations on its future operations. The Company believes that its operations comply in all material respects with all applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive effect on the Company's method of operations than on other similar companies in the energy industry. The following discussion contains summaries of certain laws and regulations and is qualified in its entirety by the foregoing. State Regulation of Energy. The Company's production investments are subject to regulation at the state level. Such regulation varies from state to state but generally includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the disposal of fluids used in connection with operations. The Company's operations are also subject to various state conservation laws and regulations. These include regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled, and the unitization or pooling of oil 3 6 and gas properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, restrict the venting or flaring of gas and impose certain requirements regarding the ratability of production. These regulatory burdens may affect profitability, and the Company is unable to predict the future cost or impact of complying with such regulations. Federal Regulation of the Sale 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 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"). In the past, the federal government had regulated the prices at which the Company's produced oil and 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, purported to restructure the interstate natural gas industry and to require interstate pipelines to provide transportation services separate, or "unbundled," from the pipelines' sales of natural gas. Order No. 636 and certain related proceedings have been the subject of a number of judicial appeals and orders on remand by the FERC. Although Order No. 636 has largely been upheld on appeal, several appeals remain pending in related restructuring proceedings. The Company cannot predict when these remaining appeals will be completed or their impact on the Company. FERC continues to address Order 636-related issues (including capacity brokering, alternative and negotiated ratemaking and transportation policy matters) in a number of pending proceedings. In May 1997, FERC held a public conference and inquiry to receive comments on the FERC's future regulatory policies and priorities in the post-Order 636 environment. 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. However, the court's decision is still subject to further action. Although Order No. 636 does not directly regulate the Company's production activities, Order No. 636 was issued to foster increased competition within all phases of the natural gas industry. It is unclear what future impact, if any, increased competition within the natural gas industry under Order No. 636 and related orders will have on the Company's activities. Although Order No. 636 could provide the Company with better access to markets and the ability to utilize new types of transportation services, it could also subject the Company to more restrictive pipeline imbalance tolerances and greater penalties for violation of those tolerances. The Company believes that Order No. 636 has not had any significant impact on the Company. The FERC has announced several important transportation-related policy statements and proposed rule changes, including a statement of policy and a request for comments concerning alternatives to its traditional cost-of-service ratemaking methodology to establish the rates that pipelines may charge for their services. A number of pipelines have obtained FERC authorization to charge negotiated rates as one such alternative. In February 1997, the FERC announced a broad inquiry into issues facing the natural gas industry to assist the FERC in establishing regulatory goals and priorities in the post-Order No. 636 environment. While these changes would affect the Company only indirectly, they are intended to further enhance competition in the natural gas markets. The FERC has also recently issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the FERC does not have jurisdiction over services provided thereon, then such facilities and services may be subject to regulation by state authorities in accordance with state law. A number of states have either enacted new laws or are considering inadequacy of existing laws affecting gathering rates and/or services. For example, the Texas Railroad Commission has recently changed its regulations governing transportation and gathering services provided by intrastate pipelines and gatherers to prohibit undue discrimination in favor of affiliates. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny by state agencies in the future. The Company's gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although the Company does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. In addition, FERC's approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to FERC regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future. The Company believes that its natural gas 4 7 gathering facilities meet the traditional tests that the FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. However, whether on state or federal land or in offshore waters subject to the Outer Continental Shelf Land Act ("OCSLA") natural gas gathering may receive greater federal regulatory scrutiny in the post-Order No. 636 environment. The effects, if any, of these policies on the Company's operations are uncertain. The Company's natural gas transportation and gathering operations are generally subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of facilities and to state regulation of the rates of such service. To a more limited degree, a portion of the Company's transportation services may be subject to FERC oversight in accordance with the provisions of the NGPA. Pipeline safety issues have recently become the subject of increasing focus in various political and administrative arenas at both the state and federal levels. At the federal level, in October 1996, the President signed the Accountable Pipeline Safety and Partnership Act of 1996, which, among other things, gives the public an opportunity to comment on pipeline risk management programs, promotes communication regarding safety issues to residents along pipeline right-of-ways, and encourages the examination of remote control valves along pipelines. The Company believes its operations, to the extent they may be subject to current natural gas pipeline safety requirements, comply in all material respects with such requirements. The Company cannot predict what effect, if any, the adoption of additional pipeline safety legislation might have on its operations, but the natural gas industry could be required to incur additional capital expenditures and increased costs depending upon future legislative and regulatory changes. Sales of crude oil, condensate and natural gas liquids by the Company are not 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 as of January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil pipelines, which would 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 it, but other factors being equal, the regulations may tend to increase transportation costs or reduce wellhead prices under certain conditions. The Company also operates federal and Indian oil and gas leases, which are subject to the regulation of the United States Minerals Management Service ("MMS"). The MMS has proposed to amend its regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases. This proposed rule would modify the valuation procedures for federal royalty oil in both arm's length and non-arm's length crude oil transactions to decrease reliance on oil posted prices and assign a value to crude oil that MMS believes better reflects its market value. MMS has also issued a notice of proposed rulemaking in which it proposes similar changes to regulations establishing the value for royalty purposes of oil produced from Indian leases. The Company cannot predict what action the MMS will take on these matters, nor can it predict how the Company will be affected by any change to these regulations. In April 1997, after two years of study, the MMS withdrew proposed changes to the way it values natural gas for royalty payments. These proposed changes would have established an alternative market-based method to calculate royalties on certain natural gas sold to affiliates or pursuant to non-arm's length sales contracts. Informal discussions among the MMS and industry officials are continuing, although it is uncertain whether, and what changes may be proposed regarding gas royalty valuation. In addition, MMS has recently announced its intention to issue a proposed rule that would require all but the smallest producers to be capable of reporting production information electronically by the end of 1998. MMS leases contain relatively standardized terms requiring compliance with detailed MMS regulations and, in the case of offshore leases, orders pursuant to OCSLA (which are subject to change by the MMS). For such offshore operations, lessees must obtain MMS approval for exploration, development, and production plans prior to the commencement of such operations. The MMS has promulgated regulations requiring offshore production facilities located on the OCS to meet stringent engineering and construction specification. The MMS also has proposed additional safety-related regulations concerning the design and operating procedures for OCS production platforms and pipelines, but these proposed regulations were withdrawn pending further discussions among interested federal agencies. With respect to conservation, the MMS has regulations restricting the flaring or venting of natural gas and has amended such regulations to prohibit the flaring of liquid hydrocarbons and oil without prior authorization. The MMS has also promulgated other regulations governing the plugging and abandonment of wells located offshore and the removal of all production facilities. To cover the various obligations of lessees on the OCS, the MMS generally requires that lessees post substantial bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that any 5 8 particular lease operator can obtain bonds or other surety in all cases. Under certain circumstances, the MMS may require operations on federal leases to be suspended or terminated. Any such suspension or termination could adversely affect the Company's interests. Additional proposals and proceedings that might affect the oil and gas industry are pending before Congress, the FERC, the MMS, state commissions and the courts. The Company cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry historically has been very heavily regulated. There is no assurance that the current regulatory approach pursued by various agencies will continue indefinitely into the future. 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. Taxation. The operations of the Company, as is the case in the energy industry generally, are significantly affected by federal tax laws, including the Tax Reform Act of 1986. In addition, federal as well as state tax laws have many provisions applicable to corporations in general which could affect the potential tax liability of the Company. Operating Hazards and Environmental Matters. The oil and gas business involves a variety of operating risks, including the risk of fire, explosions, blow-outs, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as oil spills, natural gas leaks, ruptures and discharge of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Such hazards may hinder or delay drilling, development and on-line production operations. Extensive federal, state and local laws and regulations govern oil and gas operations regulating the discharge of materials into the environment or otherwise relating to the protection of the environment. These laws and regulations may require the acquisition of a permit before drilling commences, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment or wastes that can be disposed of in connection with drilling and production activities, prohibit drilling activities on certain lands lying within wetlands or other protected areas and impose substantial liabilities for pollution or releases of hazardous substances resulting from drilling and production operations. Failure to comply with these laws and regulations may also result in civil and criminal fines and penalties. Moreover, state and federal environmental laws and regulations may become more stringent. The Company owns, leases, or operates properties that have been used for the exploration and production of oil and gas, and owns natural gas gathering systems. Hydrocarbons, mercury, polychlorinated biphenyls ("PCBs") or other wastes may have been disposed of or released on or under the properties owned, leased, or operated by the Company or on or under other locations where such wastes have been or are taken for disposal, although the Company has no knowledge of any such occurrences. The Company's properties and any wastes that may have been disposed thereon may be subject to federal or state environmental laws that could require the Company to remove the wastes or remediate any contamination identified on the Company's properties. For example, soil contamination and possible groundwater contamination exist on properties in the Newhall-Potrero Field in California acquired by the Company in the Medallion Acquisition. The surface landowner has notified the Company and some prior operators of the Newhall-Potrero Field properties that the landowner expects them to remediate the contamination. Oryx Energy Company ("Oryx"), the successor to one of the prior operators in the field, has in the past performed some remediation of contamination in the field to the satisfaction of the surface landowner. However, the additional remediation demanded by the surface landowner is estimated to cost between $4 million and $47 million, with the most probable costs ranging between $5 million and $14 million. The Company acquired the Newhall-Potrero Field properties when it acquired InterCoast Oil and Gas Company, InterCoast Gas Services Company, and GED Energy Services, Inc. (collectively "InterCoast"). InterCoast had been indemnified for 100% of the cost of remediation and restoration activities at the properties by the company from which it acquired the properties, and the Company believes that it is a valid successor to InterCoast's indemnity. In addition, the Company received an indemnity from the owners of InterCoast (InterCoast Energy and affiliated entities) for 90% of any costs the Company is required to incur in relation to remediation and restoration activities at the Newhall-Potrero Field. This indemnity was guaranteed by MidAmerican Capital Company and it covers environmental claims that are filed against the Company before January 2, 1999. The Company and Oryx have 6 9 been negotiating with the surface landowner and have reached a tentative agreement regarding the scope of the additional remediation to be performed in the field. The tentative agreement requires Oryx to pay for substantially all of the additional remediation and requires only minimal expenditures by the Company. Given the indemnities available to the Company with respect to this matter and the tentative agreement obligating Oryx to perform substantially all of the additional remediation and restoration activities on the properties, management does not expect the Company to incur any material environmental costs in connection with historical contamination in the Newhall-Potrero Field. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances. The Company's operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. Amendments to the CAA were adopted in 1990 and contain provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from the operations of the Company. The EPA and states have been developing regulations to implement these requirements. The Company may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues. The Company does not believe, however, that its operations will be materially adversely affected by any such requirements. In addition, the U.S. Oil Pollution Act ("OPA") requires owners and operators of facilities that could be the source of an oil spill into "waters of the United States" (a term defined to include rivers, creeks, wetlands, and coastal waters) to adopt and implement plans and procedures to prevent any spill of oil into any waters of the United States. OPA also requires affected facility owners and operators to demonstrate that they have at least $35 million in financial resources to pay for the costs of cleaning up an oil spill and compensating any parties damaged by an oil spill. Such financial assurances may be increased by as much as $150 million if a formal assessment indicates such an increase is warranted. Operations of the Company are also subject to the federal Clean Water Act ("CWA") and analogous state laws. In accordance with the CWA, the state of Louisiana has issued regulations prohibiting discharges of produced water in state coastal waters effective July 1, 1997. The Company may be required to incur certain capital expenditures in the next several years in order to comply with the prohibition against the discharge of produced waters into Louisiana coastal waters or increase operating expenses in connection with offshore operations in Louisiana coastal waters. Pursuant to other requirements of the CWA, the EPA has adopted regulations concerning discharges of storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit. While certain of its properties may require permits for discharges of storm water runoff, the Company believes that it will be able to obtain, or be included under, such permits, where necessary, and make minor modifications to existing facilities and operations that would not have a material effect on the Company. In addition, the disposal of wastes containing naturally occurring radioactive material which are commonly generated during oil and gas production are 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. Employees The Company and its subsidiaries employed a total of 229 persons on December 31, 1997. 7 10 Item 2. Properties. Oil and Gas Properties The following table sets forth data as of December 31, 1997 regarding the number of gross producing wells and the estimated quantities of proved oil and gas reserves attributable to the Company's principal properties.
Estimated Proved Reserves Gross ------------------------- Producing Oil Natural Gas Total Location Wells (Mbbls) (MMcf) (MMcfe) --------- ------- ------- --------- Rocky Mountain Region: Manderson Field, Wyoming 15 8,163 85,643 134,621 Ignacio Blanco Field, Colorado 37 -- 6,708 6,708 Fourteen Mile Field, Wyoming 3 987 2,772 8,694 Dragon Trail Field, Colorado 163 321 3,131 5,057 Others 988 3,065 17,795 36,185 ------- ------- ------- ------- Total 1,206 12,536 116,049 191,265 Gulf Coast Region: Bob West Field, Texas 48 -- 16,267 16,267 Langham Creek Area, Texas 19 270 28,634 30,254 Others 321 1,289 29,927 37,661 ------- ------- ------- ------- Total 388 1,559 74,828 84,182 Mid-Continent/West Texas Region: Sawyer Canyon Field, Texas 346 28 43,675 43,843 Elm Grove Field, Louisiana 24 12 13,649 13,721 Mills Ranch Field, Texas 22 91 4,709 5,255 Others 579 2,354 31,552 45,676 ------- ------- ------- ------- Total 971 2,485 93,585 108,495 Other Regions: Newhall-Potrero Field, California 39 1,307 1,453 9,295 Mayfield/Hayes Properties, Michigan 8 148 2,552 3,440 Others 19 44 337 601 ------- ------- ------- ------- Total 66 1,499 4,342 13,336 Total Working Interest Properties 2,631 18,079 288,804 397,278 Volumetric Production Payments (VPP): Niagaran Reef Trend, Michigan 95 598 8,584 12,172 Gulf of Mexico 19 318 28,752 30,660 Others 91 68 28 436 ------- ------- ------- ------- Total VPP Properties 205 984 37,364 43,268 ------- ------- ------- ------- Total Company 2,836 19,063 326,168 440,546 ======= ======= ======= =======
- -------------------------------------------------------------------------------- 8 11 Set forth below are descriptions of certain of the Company's significant oil and gas producing properties and those targeted for significant drilling activity in 1998. Rocky Mountain Region General In the Rocky Mountain Region, the Company's operations are focused primarily in the Big Horn, Green River and Wind River Basins. Rocky Mountain Acquisition The Company's principal Rocky Mountain properties were acquired in November 1995 when the Company acquired substantially all of the oil and gas assets of Natural Gas Processing Company for a purchase price of approximately $33 million. Included in the acquisition were interests in 531 gross (301 net) wells located in over 30 different fields, principally in six producing basins located in Wyoming, Colorado and Montana. Proved reserves were estimated at the time of the acquisition to be 66,700 MMcfe, consisting of 40,900 MMcf of natural gas and 4,300 Mbbls of oil and representing an average net acquisition cost of $0.49 per Mcfe. Since the acquisition, the Company has undertaken an aggressive field development and acreage acquisition program in the region that has resulted in significant increases in proved oil and gas reserves and acreage holdings as well as numerous exploration and development drilling opportunities, most notably in the Manderson Field. The Rocky Mountain Acquisition also included approximately 197,000 gross (160,000 net) acres of properties, which the Company believes contain extensive development drilling opportunities. As the result of additional property acquisitions and leasing, the Company has increased its leasehold acreage in the Rocky Mountain region to approximately 618,026 gross (407,400 net) developed and undeveloped acres as of December 31, 1997. Manderson Field The Manderson Field is located in the Big Horn Basin of north central Wyoming. The field was discovered in 1951, and 14 wells targeting the Phosphoria Dolomite were drilled using primarily 320 and 640-acre spacing from 1951 to 1954 (with average reserve recovery for the wells of approximately 150 Mbbls of oil per well). The Company has expanded its holdings in the field from approximately 7,500 acres obtained in the acquisition to 64,257 gross (60,698 net) acres at December 31, 1997, covering an area 20 miles long and 14 miles wide. The field has multiple reservoirs ranging from 4,500 to 8,600 feet that are producing or potentially productive, including the Phosphoria Dolomite, Muddy, Octh Louie, Frontier, Lakota, Dakota and Tensleep sands. All of these formations except the Phosphoria and Tensleep are known to produce sweet oil and/or gas. The Phosphoria and Tensleep produce sour oil and gas. Through December 31, 1997, the Company had drilled a total of 63 wells in the field. Based on drilling and production results, coupled with the acquisition and interpretation of additional seismic data, the Company believes that the seven formations located in its holdings in the greater Manderson Field area have significant potential. As a result, the Company has commenced an extensive development drilling program in the area. Of the 63 wells the Company had drilled, 50 wells targeted the Phosphoria. The presence of sour gas from the Phosphoria and the limitations imposed by the State of Wyoming and the federal government on the amount of sour gas that can be flared have severely limited production from the completed Phosphoria wells, most of which were shut-in for extended periods of time awaiting completion of a sour gas processing facility (amine plant) and an associated acid gas injection system which was completed and put into service in December 1997. As of December 31, 1997, nine wells were completed and producing or ready to produce, nine wells had been plugged back to the shallower Octh Louie or Muddy formations due to well bore damage caused by being shut-in, 12 wells were awaiting completion, 18 wells were awaiting stimulation or remediation, one well had been completed as a full-stream re-injection well and one well had been completed as a water disposal well. Through December 31, 1997, the 9 12 Company also drilled 13 wells targeting the Muddy, Frontier and Octh Louie formations and had completed two wells to the Muddy, one to the Frontier and five to the Octh Louie, four wells were in the process of being completed and one well had been completed as an acid gas injection well. In February 1997, the Company began construction of an amine plant to process the sour gas produced from the Phosphoria formation. Testing of the plant's systems commenced in May 1997 and the Company began to test process sour gas in late July 1997. Prior to its completion in December 1997, operation of the amine plant had been severely limited due to delays in receipt of acid gas disposal equipment. The plant has the capacity to treat up to 28,000 Mcf of sour gas (20% hydrogen sulfide content level) per day to pipeline specifications. Assuming a steady-state 2 Mcf to 1 bbl gas/oil ratio, the plant's capacity, assuming treatment to pipeline specifications, would permit oil production from the Manderson Field at up to 14,000 barrels of oil per day. There can be no assurance that the Company will be able to produce oil and gas from the Manderson Field at rates sufficient to fully utilize such capacities. The plant's sour gas handling capacity would be substantially higher if the Company elected to treat its 20% sour gas to a 3% hydrogen sulfide content level and then transport the 3% sour gas to an existing gas treatment facility owned by a third party for processing to pipeline specifications. That facility is currently undergoing modifications to safely handle such sour gas. The Company has also drilled and completed an acid gas injection well, and has obtained permits for a second such well, in order to inject the acid gas by-product (approximately 98% hydrogen sulfide content level) from its amine plant back into the ground. The Company expects each of these injection wells to have sufficient capacity to inject the plant's acid gas for a significant number of years. As of December 31, 1997, the Company operated two full-stream gas re-injection wells, had permits pending for a third and was engineering a fourth re-injection well. Each of the re-injection wells is expected to have the capacity to re-inject from 2,000 to 2,500 Mcf per day of 20% sour gas back into the Phosphoria. Once fully operational, these four gas re-injection wells could permit the production of up to 4,000 to 5,000 barrels of oil per day, assuming a steady-state 2 Mcf to 1 bbl gas/oil ratio. The Company expects to use this sour gas re-injection capacity primarily as a backup for its amine plant. The Btu content of the sweet gas produced from the shallower formations in the Manderson Field (the Muddy, Frontier, Octh Louie, Lakota and Dakota sands) ranges from 1,050 to 1,350 MMBtu per Mcf. As a result, the rich gas must be processed to remove the natural gas liquids prior to shipment. The Company has several options for the removal of these liquids, including contracting for processing services from existing nearby liquids processing facilities with available capacity or the procurement, installation and operation by the Company of its own liquids processing plant. Based on currently anticipated production levels, the Company does not expect that production will be constrained due to the need to remove the natural gas liquids. Other Big Horn Basin Properties In addition to its holdings in the Manderson Field, the Company also has interests in approximately 100,000 gross acres on other producing properties with many of the same formations as the Manderson Field area in the Big Horn Basin. The most significant of these fields is the Fourteen-Mile Field, located in Washakie County southwest of the Manderson Field in the Big Horn Basin where the Company currently has lease holdings on 70,000 gross acres. Gulf Coast Region The Company's Gulf Coast Region operations are and comprised primarily of onshore properties in Texas and Louisiana, including the Langham Creek Area near Houston, Texas and the Bob West Field in south Texas. The Company also owns non-operated interests in the Gulf of Mexico. Langham Creek Area This area is comprised of the Cypress, Cypress Deep and Langham Creek Fields in western Harris County, Texas, where the Company has interests in 10,187 gross (8,590 net) acres and is the operator. Multiple horizons in this area produce oil and gas from Eocene age sandstones in the Yegua formation from 6,000 to 7,500 feet and in 10 13 the Wilcox formation from 9,000 to 16,500 feet. The Company acquired additional working interests in the Langham Creek Area in May 1997, which added 14,000 MMcfe of proved reserves and the potential for significant additional reserves for approximately $17 million. With this acquisition, the Company's third in a series of acquisitions in this field, KCS assumed operatorship and now owns working interests varying from 33% to 87% in 19 wells in this area, representing an average net revenue interest of approximately 46%. The geological and geophysical evidence indicates the potential for as many as four to eight additional development drilling locations, with the upper-middle Wilcox sands as the primary target. In addition, the Company has initiated a 3-D seismic survey to better delineate potential drilling locations not only for the known productive horizons, but also for a deeper, high potential exploration prospect. Results of the 3-D seismic survey are expected to be completed during the second quarter of 1998 and could change the number of potential drilling locations. Bob West Field The Company has interests in approximately 863 gross (599 net) acres in this field located in Zapata and Starr Counties, Texas. Historically, the Bob West field had been the Company's most significant producing property, accounting for approximately 34% of gas production and 61% of oil and gas revenues during the six-year period ended December 31, 1996. In 1997, production from the Bob West Field accounted for less than 5% of total production and oil and gas revenue. The field produces natural gas from a series of 20 different Upper Wilcox sands with formation depths ranging from 9,500 to 13,500 feet that require stimulation by hydraulic fracturing to effectively recover the reserves. Because the majority of this field is situated under Lake Falcon on the Rio Grande River, most wells were drilled directionally under the lake from common lakeshore drill sites. The Company owns interests in two principal areas in the Bob West Field. The Company has an effective 12.5% working interest in all production from the Guerra "A" and Guerra "B" units containing 32 producing wells. The Company also owns a 100% working interest in and operates 511 acres referred to as the Falcon/Bob West Field which contains 16 producing natural gas wells. Gulf of Mexico The Company has working interests ranging from 1% to 14% in 13 offshore fields (including blocks located in the Eugene Island, Ship Shoal, South Timbalier, Vermilion and East and West Cameron areas) which are operated by others. The Company has an average working interest of approximately 8% in 50 wells. These fields produce from various Pleistocene, Pliocene and Miocene sands ranging from 6,000 feet to 15,000 feet in depth. The Company continues to participate in the development of the properties where it already owns leases but is not currently participating in new leasehold acquisitions. The Company also has acquired substantial reserves in the Gulf of Mexico under its VPP program. See "-- Volumetric Production Payment Program." Mid-Continent/West Texas Region General In the Mid-Continent/West Texas Region, the Company has active drilling programs in the Anadarko, Ardmore, Arklatex, Arkoma, and Permian Basins. Medallion Acquisition Effective December 31, 1996, the Company acquired all of the outstanding stock of InterCoast Oil and Gas Company (formerly Medallion Production Company), GED Energy Services, Inc. and InterCoast Gas Services Company, for a total price of $199.1 million. Medallion's principal oil and gas assets were estimated as of December 31, 1996 to be 187,458 MMcfe of proved oil and gas reserves, consisting of 140,320 MMcf of natural 11 14 gas and 7,856 Mbbls of oil and condensate, representing an average net acquisition cost of $0.98 per Mcfe. These reserves were located primarily in west Texas, the Texas panhandle, northwest Oklahoma and north Louisiana. Sawyer Canyon Field The Company's holdings in the Sawyer Canyon Field, located in Sutton County, Texas, represented 10% of the Company's proved reserves as of December 31, 1997. The Company owns interests in 346 gross (314 net) wells, of which it operates 323. The Company's average working interest in this field was 91%, and its leasehold position at December 31, 1997 consisted of approximately 36,807 gross (35,759 net) acres. The main producing formation in the Sawyer Canyon Field is the Canyon sandstone at a depth of approximately 5,500 feet. These Canyon reservoirs tend to be discontinuous and generally exhibit lower porosity and permeability, characteristics which reduce the area that can be effectively drained by a single well to units as small as 40 acres. The Company has continued to optimize the field's production and cash flow performance by maintaining close well, compressor and operating expense surveillance. The Company believes that additional proved reserves may ultimately be attributed to many of the 30 or more 40-acre drilling locations remaining on the property. In addition to exploiting these Canyon sand development opportunities, the Company intends to evaluate portions of the Sawyer Canyon Field for potential in the shallower Wolfcamp and deeper Strawn formations which have been found to be productive in the area. Elm Grove Field The Company has interests in approximately 5,760 gross (5,545 net) acres in the Elm Grove Field, Bossier Parish, Louisiana. Production from the Elm Grove Field is primarily natural gas from the Hosston and Cotton Valley formations at depths of 7,000 to 9,600 feet. As of December 31, 1997, the Company owned an interest in 24 gross (23.7 net) wells, all of which were operated by the Company. Other Regions Newhall-Potrero Field The Company's Newhall-Potrero Field is located in Los Angeles County, California, outside the city of Valencia. The Company is the operator and owns a 100% working interest in 39 active wells. The Company has been able to maintain the oil production at or above the same daily rate as the field was producing when it was acquired by Medallion in 1993 by converting certain wells from gas lift to pumping unit operations and reworking other wells, and was able to reduce the per barrel lifting cost. The Company believes that there are other production enhancement opportunities in the Newhall-Potrero Field through the recompletion of wells or the drilling of high angle laterals to undrained portions of the oil reservoirs. Niagaran Reef Trend (Michigan) The Company owns working interests averaging 20% in 24 active producing wells located in the northern Niagaran Reef trend of Michigan. The Niagaran Reef reservoirs are tall carbonate mounds (limestones & dolomites) varying from several hundred to more than 600 feet in height and are typically found at depths of 4,000 to 6,500 feet. The Company acquired its ownership in the Michigan properties in December 1995 in conjunction with a VPP transaction with a subsidiary of Hawkins Oil and Gas, Inc. ("Hawkins"). During 1997, the Company began expanding its involvement in the area by participating in a 28 square mile 3-D seismic exploration project designed to identify and drill for Niagaran reefs in a previously underexplored area of the northern reef trend. This project area offsets a portion of the existing productive reef trend that statistically contains more than 1.5 reefs per square mile and where per well cumulative productions have exceeded 450 Mbbls of oil. This project is currently in the final stages of leasing. Drilling of the first 10 prospects is expected to commence by mid-year 1998. 12 15 Volumetric Production Payment and Underlying Principal Properties The following table shows, as of December 31, 1997 the oil and gas deliveries to the Company that are scheduled to be made pursuant to its VPP program over the period from 1998 through 2006.
Cumulative Natural Gas Oil Total Total Period (MMcf) (Mbbls) (MMcfe) (MMcfe) ---------- --------- --------- --------- --------- 1998 19,110 412 21,584 21,584 1999 11,501 183 12,598 34,182 2000 2,616 117 3,316 37,498 2001 1,690 110 2,348 39,846 2002 888 57 1,227 41,073 2003-2006 1,559 106 2,194 43,268
The properties underlying the VPP program are principally located in two major regions, the Gulf of Mexico and the Niagaran Reef trend in Michigan. Gulf of Mexico VPP Properties Hall-Houston Oil Company Properties. The Company has acquired interests in 11 blocks off the coast of Texas and Louisiana through volumetric production payment contracts with Hall-Houston Oil Company ("HHOC"), which is the operator of all of the blocks. The blocks contain 20 wells drilled during the 1994 through 1997 period in the shallow waters of the Gulf of Mexico, producing at depths ranging from 4,500 to 10,000 feet. Pursuant to the HHOC volumetric production payments, the Company received deliveries totaling 2,169 MMcf during 1997 and is scheduled to receive deliveries totaling 7,164 MMcf in 1998, and 4,922 MMcf in 1999. On January 27, 1998 the Company entered into its eleventh VPP transaction with HHOC. Under terms of the agreement, KCS acquired 10.8 billion cubic feet (Bcf) of proved natural gas reserves scheduled to be produced and delivered during the 1998-2000 period. ATP Oil & Gas Properties. The Company has acquired interests in eight blocks off the coast of Louisiana, one block off the coast of Texas and one onshore property in Texas through VPP contracts with ATP Oil & Gas Co. of Houston, Texas ("ATP"), which is the operator of all of the blocks. The blocks contain 11 wells drilled during 1996 and 1997 that are at depths ranging from 3,000 to 13,500 feet in the shallow waters of the Gulf of Mexico. Pursuant to the ATP volumetric production payments, the Company received deliveries totaling 555 MMcfe during 1997 and is scheduled to receive deliveries totaling 11,030 MMcfe in 1998, and 5,263 MMcfe in 1999. The terms of the VPP with ATP specify that the Company receives a fixed percentage of the production attributable to ATP's working interest until payout of the Company's investment, then a reduced percentage until the Company's return on its initial investment reaches a defined level, at which time the Company would be entitled to a continuing overriding royalty interest for the remaining life of the reserves. As a result, the exact volumes to be delivered to the Company will vary depending on a number of factors including the timing of production and the actual realized oil and gas prices. Niagaran Reef Trend (Michigan) VPP Properties The Company's northern and southern Niagaran Reef trend properties, located in Michigan, were acquired in December 1995. The VPP program reserves are being produced largely from a group of 25 wells located in 12 fields. The Niagaran Reef reservoirs are typically found at depths between 4,000 and 6,500 feet. Of the remaining 8,684 MMcf and 597.9 Mbbls to be delivered under the VPP program, the Company is scheduled to receive 2,195 MMcf and 161.6 Mbbls in 1998, with the balance to be delivered between 1999 and 2006. 13 16 Other VPP Properties The Company is also scheduled to receive deliveries totaling 444 MMcfe from 1998 to 2000 from several smaller VPPs. Oil and Gas Reserves All information in this Form 10-K relating to estimates of the Company's proved reserves is based on reports prepared by KCS and other independent petroleum engineers. The reports for the KCS Medallion Resources, Inc.; KCS Mountain Resources, Inc.; KCS Resources, Inc.; and KCS Michigan Resources, Inc. properties, which collectively represent 90% of total KCS proved reserves at December 31, 1997, were audited by Netherland, Sewell & Associates, Inc. pursuant to the principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. The independent reserve engineers' estimates were based upon a review of production histories and other geologic, economic, ownership and engineering data provided by the Company or third party operators. The following table sets forth, as of December 31, 1997, summary information with respect to (i) the estimates of the Company's proved oil and gas reserves attributable to working interests and (ii) the reserve amounts contracted for pursuant to the agreements relating to VPPs. The present value of future net revenues in the table should not be construed to be the current market value of the estimated oil and gas reserves owned by the Company.
December 31, 1997 ---------------- Proved reserves: Oil (Mbbls) 19,063 Natural gas (MMcf) 326,168 Total (MMcfe) 440,546 Future net revenues ($000s) $653,935 Present value of future net revenues ($000s) $410,506 Proved developed reserves: Oil (Mbbls) 13,008 Natural gas (MMcf) 234,091 Total (MMcfe) 312,139 Future net revenues ($000s) $486,026 Present value of future net revenues ($000s) $339,144
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, and 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 may all 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 value 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. Other than gas sold under contractual arrangements including swaps, futures contracts and options, gas prices were $2.50 per Mcf and oil prices were $15.15 per barrel at December 31, 1997. The prices for natural gas and, to a lesser extent, oil, are subject to substantial seasonal fluctuations, and prices for each are subject to 14 17 substantial fluctuations as a result of numerous other factors. See "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, 1997. The leases in which the Company has an interest are for varying primary terms, and many require the payment of delay rentals to continue the primary term. The leases may be surrendered by the operator at any time by notice to the lessors, by the cessation of production, fulfillment of commitments, or by failure to make timely payments of delay rentals. Excluded from the table are the Company's interests in the properties subject to volumetric production payments.
Developed Acres Undeveloped Acres ------------------------- ------------------------ State Gross Net Gross Net - --------------- ----------- ---------- ---------- ---------- Wyoming 65,869 55,274 325,880 248,305 Texas 123,224 71,578 44,380 23,184 Montana 88,880 47,163 38,500 28,675 Louisiana 114,827 28,093 18,716 11,694 Oklahoma 50,284 23,440 10,962 6,321 Colorado 30,201 13,461 10,000 5,250 Other 64,285 11,570 83,474 26,054 ----------- ---------- ---------- ---------- Total 537,570 250,579 531,912 349,483 =========== ========== ========== ==========
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, 1997, 1996 and 1995, is set forth below.
Year Ended December 31, -------------------------------------------- 1997 1996 1995 ------------ ------------ ------------ Type of Well Gross Net Gross Net Gross Net ----- --- ----- --- ----- --- Development: Oil 33 33.0 43 40.9 1 0.4 Natural gas 42 29.2 22 10.9 19 7.4 Non-productive 18 16.4 8 5.8 -- -- -- ---- -- ---- -- ---- Total 93 78.6 73 57.6 20 7.8 == ==== == ==== == ==== Exploratory: Oil 1 1.0 1 1.0 1 0.4 Natural gas 12 7.2 5 3.0 12 4.3 Non-productive 20 13.9 15 10.5 8 5.3 -- ---- -- ---- -- ---- Total 33 22.1 21 14.5 21 10.0 == ==== == ==== == ====
At December 31, 1997, the Company was participating in the drilling or completion of 30 gross (21.35 net) wells. 15 18 Production and Sales The following table presents certain information with respect to oil and gas production attributable to the Company's properties and average sales prices during the three years ended December 31, 1997, 1996 and 1995.
Year Ended December 31, ------------------------------------ 1997 1996 1995 ---------- ---------- ---------- Production: Oil (Mbbl) 1,696 758 196 Liquids (Mbbl) 128 -- -- Gas (MMcf) 43,700 25,581 19,129 Total (MMcfe) 54,644 30,129 20,305 Average price: Oil (per bbl) $ 18.57 $ 20.69 $ 17.28 Liquids (per bbl) 11.02 -- -- Gas (per Mcf) 2.40 3.61 4.29 Total (per Mcfe) 2.52 3.59 4.27
Other Facilities Principal offices of the Company and its operating subsidiaries are leased in modern office buildings in Edison, New Jersey (10,000 square feet), Houston, Texas (25,000 square feet) and Tulsa, Oklahoma (17,000 square feet). In Worland, Wyoming, the Rocky Mountain operations are based in a 10,000 square foot Company-owned facility. 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. 16 19 Item 3. Legal Proceedings. Information with respect to this Item is contained in Note 10 to the Consolidated Financial Statements on pages 38 and 39 of this Form 10-K. 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, 1997. 17 20 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters. The Company's Common Stock is traded on the New York Stock Exchange. Listed below are the high and low closing sales prices for the periods indicated:
1997 -------------------------------------------------------------- Jan. - Mar. Apr. - June July - Sept. Oct. - Dec. ------------- ------------- -------------- ------------- Market Price High $ 21.81 $ 21.19 $ 30.00 $ 29.94 Low 15.75 13.31 19.63 19.75 1996 -------------------------------------------------------------- Jan. - Mar. Apr. - June July - Sept. Oct. - Dec. ------------- ------------- -------------- ------------- Market Price High $ 7.88 $ 14.38 $ 17.81 $ 22.06 Low 6.69 7.81 13.38 14.44
There were 1,114 stockholders of record of the Company's Common Stock on February 27, 1998. The Company pays dividends on a quarterly basis. The aggregate amount of dividends declared were $2,204,000 and $1,388,000 in 1997 and 1996, respectively. 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, 1997.
Dollars in thousands (except per share data) 1997 1996 1995 1994 1993 --------- --------- --------- --------- --------- Revenue $ 143,689 $ 108,374 $ 87,115 $ 67,400 $ 41,428 Income (loss) from continuing operations (97,385)(a) 21,717 23,405 23,603 17,529 Income (loss) from discontinued operations 5,302 (1,845) (2,099) 554 1,082 Net income (loss) (92,083)(a) 19,872 21,306 24,157 18,611 Total assets 502,414 511,820 306,564 176,179 117,640 Long-term debt 292,445 310,347 165,529 61,970 36,289 Stockholders' equity 145,070 125,622 101,576 80,668 59,765 Per common share (Basic): Income (loss) from continuing operations (3.37)(a) 0.94 1.02 1.03 0.79 Income (loss) from discontinued operations 0.18 (0.08) (0.09) 0.02 0.05 Net income (loss) (3.19)(a) 0.86 0.93 1.05 0.84 Per common share (Diluted) Income (loss) from continuing operations (3.37)(a) 0.92 1.00 1.01 0.76 Income (loss) from discontinued operations 0.18 (0.08) (0.09) 0.02 0.05 Net income (loss) (3.19)(a) 0.84 0.91 1.03 0.81 Per common share: Stockholders' equity 4.93 5.42 4.42 3.52 2.60 Dividends 0.075 0.06 0.06 0.045 0.03
(a) includes a $165,149 pretax, $107,347 after-tax, or $3.72 per share, non-cash ceiling writedown of oil and gas assets. 18 21 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. General Several important developments have had and will continue to have a significant impact on the Company's financial condition and results of operations. On December 23, 1996, the Company and Tennessee Gas Pipeline Company ("Tennessee Gas") entered into a settlement covering all claims and litigation related to the above-market, take-or-pay contract (the "Tennessee Gas Contract"). As part of the settlement, the Tennessee Gas Contract was terminated effective January 1, 1997, approximately two years prior to its expiration date. See Note 10 to Consolidated Financial Statements. Prior to its termination, the Tennessee Gas Contract had a material and positive effect on the Company's gas revenue, income and cash flow. As of December 31, 1996, the Company completed the arrangements for the Medallion Acquisition (see Note 3 to Consolidated Financial Statements), effectively doubling its oil and gas reserves and giving it a substantial presence in the Mid-Continent/West Texas region. In January 1997, the Company completed a public offering of six million shares of common stock. The net proceeds to the Company of approximately $110.6 million were used to reduce outstanding indebtedness under the Company's bank credit facilities. During 1997, the Company sold its principal natural gas transportation asset, the Texas intrastate pipeline, and its third-party gas marketing operations, realizing proceeds of $28.5 million and an after-tax gain of $5.4 million. Accordingly, the financial statements included in this annual report have been restated to reflect the natural gas transportation and marketing operations as discontinued operations. These developments have transformed the Company from an enterprise heavily dependent on the Bob West Field and the Tennessee Gas Contract, with gas marketing and transportation operations, to a Company focused on exploration and production, with a portfolio of properties in three core operating areas -- the Gulf Coast region, the Rocky Mountain region and the Mid-Continent/West Texas region -- and its VPP program. Production from the Bob West Field, which in 1995 accounted for 34% of total production and 72% of the Company's oil and gas revenues, accounted for less than 5% of production and revenues in 1997. All references in the following discussion related to earnings per share are based upon the Company's basic earnings per share. Results of Operations for the Years Ended December 31, 1997, 1996 and 1995 Results of Operations Net loss for the year ended December 31, 1997 was $92.1 million, or $3.19 per share, compared to net income of $19.9 million, or $0.86 per share, for the year ended December 31, 1996. Loss from continuing operations was $97.4 million, or $3.37 per share, for the year ended December 31, 1997, compared to income of $21.7 million, or $0.94 per share, for the year ended December 31, 1996. The loss in 1997 resulted from a non-cash ceiling test provision of $165.1 million ($107.3 million after tax). Excluding the effect of the ceiling test provision, income from continuing operations was $9.9 million, or $0.35 per share. Significantly higher oil and gas production during 1997 was more than offset by the impact of the termination of the Tennessee Gas Contract, which contributed premium revenue of $32.8 million in 1996, and higher net interest costs. Income from discontinued operations in 1997 was $5.3 million, or $0.18 per share (primarily the net gain on disposition), compared to a loss of $1.8 million, or $0.08 per share, in 1996. Net income for the year ended December 31, 1996 was $19.9 million, or $0.86 per share, compared to $21.3 million, or $0.93 per share, for the year ended December 31, 1995. Income from continuing operations was $21.7 million, or $0.94 per share, for 1996, compared to $23.4 million, or $1.02 per share, for 1995. Significantly higher oil and gas production, along with higher oil and gas prices in 1996 for non - Tennessee Gas Contract sales were offset by lower production from properties covered by the Tennessee Gas Contract, higher interest costs and a 19 22 higher effective income tax rate. Loss from discontinued operations in 1996 was $1.8 million, or $0.08 per share, compared to a loss of $2.1 million, or $0.09 per share, in 1995. Revenue
Year Ended December 31, ------------------------------ 1997 1996 1995 -------- -------- -------- Production: Oil (Mbbl) 1,696 758 196 Liquids (Mbbl) 128 -- -- Gas (MMcf) 43,700 25,581 19,129 Total (MMcfe) 54,644 30,129 20,305 Average Price: Oil (per bbl) $ 18.57 $ 20.69 $ 17.28 Liquids (per bbl) 11.02 -- -- Gas (per Mcf) 2.40 3.61 4.29 Total (per Mcfe) 2.52 3.59 4.27 Revenue: Oil $ 31,491 $ 15,684 $ 3,387 Liquids 1,414 -- -- Gas 104,932 92,331 83,242 -------- -------- -------- Total $137,837 $108,015 $ 86,629
Oil and Gas Production. The Company's oil and gas production during 1997 increased 81% to 54.6 Bcfe, compared to 30.1 Bcfe produced during 1996. Oil and liquids production increased 141% to 1,824 Mbbls and gas production increased 71% to 43.7 Bcf. The production increases were primarily a result of the Medallion Acquisition. Oil and gas production during 1996 increased 48% to 30.1 Bcfe, compared to 20.3 Bcfe in 1995, primarily due to higher gas and oil volumes delivered under the Company's VPP program. Gas Revenue. In 1997, gas revenue increased $12.6 million to $104.9 million. Production gains added $43.8 million of gas revenue in 1997. This increase was partially offset by the termination of the Tennessee Gas Contract which provided $32.8 million in premium over corresponding spot market prices in 1996. Average realized prices for gas not covered by the Tennessee Gas Contract were $2.40 and $2.35 per Mcf in the years ended 1997 and 1996, respectively. With the termination of the Tennessee Gas Contract, the Company's earnings have been and will continue to be more heavily impacted by changing energy prices. The Company utilizes commodity price swaps, futures and options (see Note 9 to Consolidated Financial Statements) to help mitigate the impact of fluctuations in the price of a portion of its natural gas and oil production. Gas revenue in 1996 increased $9.1 million to $92.3 million. Higher production from properties not covered by the Tennessee Gas Contract along with higher non-Tennessee Gas Contract prices more than offset the impact of lower production from the properties covered by the Tennessee Gas Contract. Sales under the Tennessee Gas Contract decreased to 4.6 Bcf in 1996, compared to 6.9 Bcf in 1995, largely due to normal production declines in existing wells. Average natural gas prices were $3.61 per Mcf in 1996, compared to $4.29 per Mcf in 1995. This decrease reflected the lower percentage of production covered by the Tennessee Gas Contract. Average non-Tennessee Gas Contract prices were $2.35 in 1996, compared to $1.62 in 1995. Natural gas sales prices under the Tennessee Gas Contract, excluding severance tax reimbursements, were $8.40 in 1996, compared to $7.90 in 1995. 20 23 Oil and Liquids Revenue. In 1997, oil and liquids revenue increased $17.2 million to $32.9 million, compared to 1996. Production gains added $18.8 million of oil and liquids revenue, partially offset by lower average realized prices. The production gains were primarily due to the Medallion Acquisition. In 1996, oil and liquids revenue increased $12.3 million to $15.7 million mainly due to higher production in the Rocky Mountain region. Other Revenue, net. Other revenue in 1997 included $2.5 million related to severance tax settlements in connection with the Tennessee Gas Contract and $1.3 million from the settlement of a gas sales contract dispute. The remainder of the increase in 1997, compared to 1996, reflected certain marketing and gathering revenues primarily as a result of the Medallion Acquisition. Lease Operating Expenses As a result of the substantial increase in oil and gas production, lease operating expenses increased $20.2 million to $29.4 million, or $0.54 per Mcfe, for the year ended December 31, 1997, compared to $9.2 million, or $0.30 per Mcfe, in 1996. Approximately $17.6 million of this increase was related to the Medallion properties, with the remainder of the increase primarily due to expanded operations in the Rocky Mountain region, especially in the Manderson Field. The increase in the per Mcfe rate reflects a lower percentage of production from the VPP program, which does not bear any lease operating expenses, in 1997 compared to 1996, as well as start up costs of expanding operations in the Manderson Field. For the year ended December 31, 1996, lease operating expenses increased $3.0 million to $9.2 million, or $0.30 per Mcfe, compared to $6.2 million, or $0.30 per Mcfe, in 1995 primarily due to production increases in the Rocky Mountain region. Production Taxes Production taxes, which are generally based on a fixed percentage of revenue, increased 133% to $5.9 million in 1997, compared to $2.5 million in 1996. In addition to the effect of higher oil and gas revenue during 1997, a larger percentage of that revenue was subject to severance taxes as a result of the termination of the Tennessee Gas Contract which provided for reimbursement to the Company of severance taxes on production covered under that contract. Production taxes increased $2.1 million to $2.5 million in 1996 over 1995 primarily due to increased revenue and, to a lesser extent, an increase in average production tax rates which are higher in the Rocky Mountain region compared to the Gulf Coast region. In addition, a larger percentage of the Company's revenue was subject to production taxes in 1996, compared to 1995, due to the decline in production covered under the Tennessee Gas Contract. General and Administrative Expenses For the year ended December 31, 1997, general and administrative expenses increased $2.9 million to $10.8 million, compared to 1996. This increase was primarily the result of the overall growth of the Company, including expansion in the Mid-Continent region as a result of the Medallion Acquisition and expanded VPP operations. In 1996, general and administrative expenses were $7.8 million, compared to $4.7 million in 1995. The increase reflected the overall growth of the Company, most notably the expansion into the Rocky Mountain region. Depreciation, Depletion and Amortization For the year ended December 31, 1997, depreciation, depletion and amortization ("DD&A") increased $15.1 million over 1996 to $60.6 million due primarily to the increase in oil and gas revenue, which accounted for $12.7 million of the increase. The balance was attributable to the DD&A rate increasing to 42.4% from 41.7% and the expansion of the Company's operations in the Mid-Continent and Rocky Mountain regions. For the year ended December 31, 1996, DD&A increased $7.2 million over 1995 to $45.5 million due to the increase in oil and gas revenue, which was partially offset by a reduction in the DD&A rate to 41.7% in 1996 from 43.9% in 1995. 21 24 Writedown of Oil and Gas Properties At December 31, 1997, the Company, in accordance with the full cost accounting method and procedures prescribed by the Securities and Exchange Commission ("SEC"), recorded a $165.1 million ($107.3 million net of tax) non-cash ceiling writedown of its oil and gas properties. A portion of this writedown reflects price declines during the first part of 1998. Under the SEC accounting procedures, capitalized oil and gas property costs are limited to the present value of future net revenues from estimated production of proved oil and gas reserves at current prices, discounted at 10%, plus the value of unproved properties ("SEC PV10 value"). To the extent that the capitalized costs exceed the estimated SEC PV10 value at the end of any fiscal quarter, such excess costs are written down with a corresponding charge to income. The decrease in the 1997 SEC PV10 value was largely attributable to significantly lower oil and gas prices, but was also impacted by delays in start up of the Manderson Field. The SEC PV10 value of the Company's proved reserves at December 31, 1997 was $410.5 million. Other than gas sold under contractual arrangements including swaps, futures contracts and options, gas prices were $2.50 and $3.54 at December 31, 1997 and 1996, respectively, and oil prices were $15.15 and $22.45 at December 31, 1997 and 1996, respectively. Further price declines, if not offset by increases in proved oil and gas reserves, could result in future ceiling writedowns. Interest and Other Income, net Interest and other income was $0.5 million for the year ended December 31, 1997, compared to $5.1 million in 1996. The decrease in 1997 was primarily due to the absence of interest income on outstanding receivables related to the Tennessee Gas litigation. The outstanding receivables plus interest were paid by Tennessee Gas on September 30, 1996. Interest and other income was $5.1 million in 1996, compared to $4.5 million in 1995. Included in these amounts were $4.4 million and $3.1 million for 1996 and 1995, respectively related to interest income accrued on the Tennessee Gas receivable. These amounts were included in the September 30, 1996 cash payment received from Tennessee Gas. Interest Expense Interest expense increased $7.8 million to $21.9 million for the year ended December 31, 1997, compared to the same period in 1996. Higher average borrowings in 1997 due to the expansion of the Company's operations (including the Medallion Acquisition, the VPP program and the development of the Manderson Field) were offset in part by lower average interest rates during the period. Interest expense was $14.1 million in 1996, compared to $6.8 million in 1995. The increase in 1996 was due to higher average borrowings, along with higher average interest rates, principally resulting from the sale of $150 million of 11% Senior Notes in January 1996. Higher average borrowings in 1996, compared to 1995, were used to expand the Company's operations. The increase in interest expense during 1996 was partially offset by the increase in interest income as discussed above. Income Taxes The income tax benefit was $52.1 million in 1997, representing an effective tax rate benefit of 34.8%, compared to effective rate provisions of 36.9% and 33.6% in 1996 and 1995, respectively. A substantial portion of the income taxes reflected in the Company's income statements during these periods is deferred to future years. The Company recognized a net deferred tax asset in the amount of $16.6 million at December 31, 1997. Deferred tax assets relate primarily to the Company's net loss and alternative minimum tax credit carryforwards. See Note 8 to Consolidated Financial Statements. Liquidity and Capital Resources Cash Flow From Operating Activities Net income adjusted for non-cash charges increased to $77.6 million for the year ended December 31, 1997, compared to $75.8 million in 1996. The increase reflects cash flow from the properties acquired as part of the Medallion Acquisition, which more than offset the 1996 premium over market prices received prior to the termination of the Tennessee Gas Contract of $32.8 million. Net cash provided by operating activities was $100.2 million during 1997, compared to $121.3 million for the year ended 1996. The 1996 period included the receipt of approximately $70 million from Tennessee Gas for past underpayments and interest. 22 25 The reductions in trade accounts receivable ($51.8 million) and in accounts payable and accrued liabilities ($34.1 million) in 1997 were largely related to the discontinuance of the natural gas transportation and marketing operations, offset by increases due to the overall growth of the Company's operations. Net income adjusted for non-cash charges was $75.8 million for the year ended December 31, 1996, compared to $71.1 million in 1995. Net cash provided by operating activities was $121.3 million in 1996 compared to $30.1 million in 1995. This increase resulted primarily from the receipt of $70 million from Tennessee Gas on September 30, 1996 and, to a lesser extent, the timing of cash receipts and payments. Investing Activities Capital expenditures for the year ended December 31, 1997 were $226.6 million, of which $107.4 million was for development drilling, $49.5 million for the acquisition of proved reserves under the Company's VPP program, $54.3 million for lease acquisitions, seismic surveys and exploratory drilling and $15.4 million for other assets including $10.7 million for Manderson Field infrastructure. During 1997, the Company sold its principal natural gas transportation asset and its third-party gas marketing operations realizing proceeds of $28.5 million, which were used to reduce indebtedness under its bank credit facilities, and an after-tax gain of $5.4 million. The Company has established for 1998 a preliminary capital expenditure budget of $160 million, consisting of $75 million for development drilling, $20 million for exploration, $55 million for VPP transactions and $10 million for working interest acquisitions and other. The program is expected to be funded by cash flow from operations, the sale of non-strategic assets and borrowings under the Company's bank credit facilities. Capital expenditures in 1996 were $282.2 million, of which $183.1 million was related to the Medallion Acquisition (see Note 3 to Consolidated Financial Statements), $54.9 million to development drilling, $15.9 million to the purchase of proved reserves under the Company's VPP program and $18.2 million to lease acquisitions, seismic surveys and exploratory drilling. The Company utilized approximately $160.5 million from its bank credit facilities to fund the Medallion Acquisition, while the remainder of the 1996 capital program was funded primarily with internally generated cash, including $70.0 million received from Tennessee Gas and $16.6 million of proceeds from the sale of certain non-strategic oil and gas properties. Capital expenditures in 1995 were $128.7 million, of which $43.8 million was for the purchase of oil and gas reserves under the Company's VPP program, $33 million was for the Rocky Mountain Acquisition and $26.9 million was for development drilling. The remainder was largely for lease acquisitions, seismic evaluations and exploratory drilling. The Company funded its capital expenditures through a combination of internally generated cash and additional borrowings under its credit facilities. Debt Financing On January 15, 1998, the Company completed a public offering of $125 million senior subordinated notes at an interest rate of 8.875% due January 15, 2008. The net proceeds of approximately $121 million were used to pay down borrowings under the Company's bank credit facilities. Credit Facility The Company's revolving credit facility ("Credit Facility"), which matures September 30, 2000, is secured by the Company's oil and gas assets excluding those securing the Revolving Credit Agreement (see below). The borrowing base under the Credit Facility is a function of the lenders' determination of the value of the collateral, and is currently limited to $75 million under the terms of the Senior Notes indenture. The Credit Facility bears interest at a spread over the prime rate or LIBOR, determined each quarter based upon the Company's consolidated debt-to-EBITDA ratio. As of December 31, 1997, the weighted average interest rate under the Credit Facility was 7.0% and $74.5 million was outstanding. Revolving Credit Agreement Simultaneous with the consummation of the Medallion Acquisition, the Company entered into a revolving credit agreement (the "Revolving Credit Agreement") with a group of banks which will mature on September 30, 2000. The Company's obligations under the Revolving Credit Agreement are secured by substantially all of the oil and gas assets acquired in the Medallion Acquisition, a pledge of the Medallion entities' common stock and certain VPP assets. The borrowing base, which is a function of the lenders' determination of the value of the collateral, is currently $90 million. The Revolving Credit Agreement permits the Company to borrow at interest rates based upon the 23 26 banks' prime rate or LIBOR. The applicable spread over the prime rate or LIBOR is determined each quarter based on the Company's consolidated debt-to-EBITDA ratio. As of December 31, 1997, the weighted average interest rate under the Revolving Credit Agreement was 7.4% and $68.4 million was outstanding. Equity Financing In January 1997, the Company completed a public offering of 6,000,000 shares of Common Stock. The net proceeds to the Company of approximately $110.6 million were used to reduce outstanding indebtedness under the bank credit facilities. Year 2000 Issue The year 2000 issue is the result of computer programs written using two digits rather than four to define the applicable year. Without corrective action, programs with time-sensitive software could potentially recognize a date ending in "00" as the year 1900 rather than the year 2000, causing many computer applications to fail or create erroneous results. Assessment and remediation of the Company's business computer systems, production control systems and other embedded-chip devices for compliance with the year 2000 is underway. As a result of modifications or upgrades planned or already completed, the Company believes that the year 2000 issue will not pose significant problems for the Company's business, operations, or operating systems. The Company expects that any additional modifications or upgrades of software or hardware required for year 2000 compatibility will be accomplished using existing resources and will not have a material impact on the Company's financial position or results of operations in future periods. The Company has identified and will be contacting customers, suppliers and other critical business partners to determine whether entities with which the Company transacts business have an effective plan in place to address the year 2000 issue. Contingency plans will be developed as needed. 24 27 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, 1997 and 1996, and the related statements of consolidated operations, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1997. 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 generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of KCS Energy, Inc. and subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP New York, New York March 26, 1998 25 28 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED OPERATIONS (amounts in thousands, except per share data)
For the Year Ended December 31, ----------------------------------- 1997 1996 1995 --------- --------- --------- Oil and gas revenue $ 137,837 $ 108,015 $ 86,629 Other revenue, net 5,852 359 486 --------- --------- --------- Total revenue 143,689 108,374 87,115 Operating costs and expenses Lease operating expenses 29,393 9,167 6,156 Production taxes 5,873 2,526 467 General and administrative expenses 10,753 7,825 4,704 Depreciation, depletion and amortization 60,554 45,460 38,231 Writedown of oil and gas properties 165,149 -- -- --------- --------- --------- Total operating costs and expenses 271,722 64,978 49,558 --------- --------- --------- Operating income (loss) (128,033) 43,396 37,557 Interest and other income, net 476 5,086 4,472 Interest expense (21,883) (14,085) (6,807) --------- --------- --------- Income (loss) from continuing operations before income taxes (149,440) 34,397 35,222 Federal and state income taxes (benefit) (52,055) 12,680 11,817 --------- --------- --------- Income (loss) from continuing operations (97,385) 21,717 23,405 Discontinued operations Net loss from operations (72) (1,845) (2,099) Net gain on disposition 5,374 -- -- --------- --------- --------- Net income (loss) $ (92,083) $ 19,872 $ 21,306 ========= ========= ========= Basic earnings per share of common stock Continuing operations $ (3.37) $ 0.94 $ 1.02 Discontinued operations 0.18 (0.08) (0.09) --------- --------- --------- $ (3.19) $ 0.86 $ 0.93 ========= ========= ========= Diluted earnings per share of common stock Continuing operations $ (3.37) $ 0.92 $ 1.00 Discontinued operations 0.18 (0.08) (0.09) --------- --------- --------- $ (3.19) $ 0.84 $ 0.91 ========= ========= ========= Weighted average shares outstanding 28,856 23,114 22,960 ========= ========= =========
The accompanying notes are an integral part of these financial statements. 26 29 KCS ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (dollars in thousands)
December 31, ---------------------- 1997 1996 --------- --------- ASSETS Current assets Cash and cash equivalents $ 4,802 $ 5,100 Trade accounts receivable 40,115 30,307 Net assets of discontinued operations -- 26,658 Other current assets 6,752 8,392 --------- --------- Current assets 51,669 70,457 --------- --------- Property, plant and equipment Oil and gas properties, full cost method, less accumulated DD&A - 1997 $356,877; 1996 $133,263 403,754 421,524 Other property, plant and equipment, at cost less accumulated depreciation - 1997 $3,408; 1996 $1,145 22,579 8,829 --------- --------- Property, plant and equipment, net 426,333 430,353 --------- --------- Other assets Investments and other assets 7,815 11,010 Deferred federal and state income taxes 16,597 -- --------- --------- Other assets 24,412 11,010 --------- --------- $ 502,414 $ 511,820 ========= ========= LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable $ 39,500 $ 24,144 Accrued liabilities 24,524 15,558 --------- --------- Current liabilities 64,024 39,702 --------- --------- Deferred credits and other liabilities Deferred federal and state income taxes -- 34,097 Other 875 2,052 --------- --------- Deferred credits and other liabilities 875 36,149 --------- --------- Long-term debt 292,445 310,347 --------- --------- Commitments and contingencies --------- --------- Preferred stock, authorized 5,000,000 shares - unissued -- -- --------- --------- Stockholders' equity Common stock, par value $0.01 per share, authorized 50,000,000 shares issued 31,229,890 and 24,976,340, respectively 312 249 Additional paid-in capital 144,135 30,463 Retained earnings 4,011 98,298 Less treasury stock, 1,801,496 shares, at cost (3,388) (3,388) --------- --------- Stockholders' equity 145,070 125,622 --------- --------- $ 502,414 $ 511,820 ========= =========
The accompanying notes are an integral part of these financial statements. 27 30 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY (dollars in thousands, except per share data)
Additional Common Paid-in Retained Treasury Stockholders' Stock Capital Earnings Stock Equity ------------- -------------- ------------- ------------- --------------- Balance at December 31, 1994 $ 246 $ 23,772 $ 59,885 $ (3,235) $ 80,668 Stock issuances - option and benefit plans 2 187 -- -- 189 Tax benefit on stock option exercises -- 201 -- -- 201 Stock warrants issued -- 626 -- -- 626 Net income -- -- 21,306 -- 21,306 Dividends ($0.06 per share) -- -- (1,377) -- (1,377) Purchase of treasury stock -- -- -- (37) (37) ------------- -------------- ------------- ------------- --------------- Balance at December 31, 1995 248 24,786 79,814 (3,272) 101,576 Stock issuances - option and benefit plans 1 682 -- -- 683 Tax benefit on stock option exercises -- 665 -- -- 665 Stock warrants issued -- 4,998 -- -- 4,998 Repurchase of stock warrants -- (668) -- -- (668) Net income -- -- 19,872 -- 19,872 Dividends ($0.06 per share) -- -- (1,388) -- (1,388) Purchase of treasury stock -- -- -- (116) (116) ------------- -------------- ------------- ------------- --------------- Balance at December 31, 1996 249 30,463 98,298 (3,388) 125,622 Stock issuance - public offering 60 110,527 -- -- 110,587 Stock issuances - option and benefit plans 3 2,073 -- -- 2,076 Tax benefit on stock option exercises -- 1,072 -- -- 1,072 Net loss -- -- (92,083) -- (92,083) Dividends ($0.075 per share) -- -- (2,204) -- (2,204) ------------- -------------- ------------- ------------- --------------- Balance at December 31, 1997 $ 312 $ 144,135 $ 4,011 $ (3,388) $ 145,070 ============= ============== ============= ============= ===============
The accompanying notes are an integral part of these financial statements. 28 31 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (dollars in thousands)
For the Year Ended December 31, --------------------------------------------------- 1997 1996 1995 -------------- -------------- --------------- Cash flows from operating activities: Net income (loss) $ (92,083) $ 19,872 $ 21,306 Non-cash charges (credits): Depreciation, depletion and amortization 60,554 46,611 39,209 Writedown of oil and gas properties 165,149 - - Deferred income taxes (52,106) 7,925 9,756 Gain on sale of discontinued operations (5,374) - - Other non-cash charges and credits, net 1,466 1,440 820 -------------- -------------- --------------- 77,606 75,848 71,091 Net changes in assets and liabilities: Trade accounts receivable 51,824 (33,887) (11,672) Receivable from Tennessee Gas - 56,437 (42,868) Other current assets 2,630 (7,060) 2,217 Accounts payable and accrued liabilities (34,100) 34,732 14,163 Federal and state income taxes 1,563 (2,572) 178 Other, net 698 (2,150) (2,999) -------------- -------------- --------------- Net cash provided by operating activities 100,221 121,348 30,110 -------------- -------------- --------------- Cash flows from investing activities: Investment in oil and gas properties(1) (211,228) (267,133) (121,265) Proceeds from the sale of oil and gas properties 4,940 16,634 4,069 Proceeds from the sale of pipeline assets 27,907 - - Investment in other property, plant and equipment, net (15,341) (10,085) (7,434) -------------- -------------- --------------- Net cash used in investing activities (193,722) (260,584) (124,630) -------------- -------------- --------------- Cash flows from financing activities: Proceeds from long-term debt 156,800 325,636 141,298 Repayments of long-term debt (174,791) (180,900) (38,774) Issuance of common stock 112,663 683 189 Issuance of stock warrants - - 626 Repurchase of stock warrants - (668) - Tax benefit on stock option exercises 1,072 665 201 Purchase of treasury stock - (116) (37) Dividends paid (1,962) (1,388) (1,377) Deferred financing costs and other, net (579) (5,422) (2,748) -------------- -------------- --------------- Net cash provided by financing activities 93,203 138,490 99,378 -------------- -------------- --------------- Increase (decrease) in cash and cash equivalents (298) (746) 4,858 Cash and cash equivalents at beginning of year 5,100 5,846 988 -------------- -------------- --------------- Cash and cash equivalents at end of year $ 4,802 $ 5,100 $ 5,846 ============== ============== ===============
(1) The amount included in the year ended December 31, 1996 does not include $4,998 (non-cash) related to stock warrants issued in connection with the 1996 Medallion Acquisition. The accompanying notes are an integral part of these financial statements. 29 32 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Summary of Significant Accounting Policies KCS Energy, Inc. is an independent energy company engaged in the acquisition, exploration, development and production of natural gas and crude oil. Recapitalization (Quasi-reorganization) At September 30, 1988, prior to the start of the Company's first full year of operations as a separate legal entity with independent management, an amount equal to the cumulative retained earnings deficit of the KCS subsidiaries ($25,109,000) was eliminated against additional paid-in capital in connection with a quasi-reorganization. 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 presentations. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Cash Equivalents The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. Futures Contracts The Company utilizes oil and natural gas futures contracts for the purpose of hedging the risks associated with fluctuating crude oil and natural gas prices and accounts for such contracts in accordance with FASB Statement No. 80, "Accounting for Futures Contracts." These contracts permit settlement by delivery of commodities and, therefore, are not financial instruments, as defined by FASB Statement Nos. 107 and 119. Changes in the market value of these transactions are deferred until the gain or loss on the underlying item is recognized. See Note 9 for further discussion of the Company's price risk management activities. Imbalances The Company follows the entitlements method of accounting for production imbalances, where revenues are recognized based on its interest in oil and gas production from a well. Imbalances arise when a purchaser takes delivery of more or less production from a well than the Company's actual interest in the production from that well. The difference between cash received and revenue recorded is a receivable or payable. Such imbalances are reduced either by subsequent balancing of over and under deliveries or by cash settlement, as required by applicable contracts. Property, Plant and Equipment The Company follows the full cost method of accounting, under which all productive and nonproductive costs associated with its exploration, development and production 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. General and administrative costs related to production and general overhead are expensed as incurred. The Company provides for depreciation, depletion and amortization of evaluated costs using the future gross revenue method based on recoverable reserves valued at current prices. Under accounting procedures prescribed by the SEC, capitalized oil and gas property costs are limited to the present value of future net revenues from estimated production of proved oil and gas reserves discounted at 10%, plus the value of unproved properties. 30 33 To the extent that the capitalized costs exceed the estimated present value of future net revenues at the end of any fiscal quarter, such excess costs are written down with a corresponding charge to income. At December 31, 1997, the Company recorded a $165.1 million ($107.3 million net of tax) non-cash ceiling writedown of its oil and gas properties. A portion of this write down reflects price declines during the first part of 1998. See "Management's Discussion and Analysis of Financial Condition and Results of Operations". Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $21.1 million and $10.6 million at December 31, 1997 and 1996. Such costs relate to projects which were at such dates undergoing exploration or development activities or in which the Company intends to commence such activities in the future. The Company will begin to amortize these costs when proved reserves are established or impairment is determined. Depreciation of other property, plant and equipment is provided on a straight-line basis over the useful lives of the assets, except for certain natural gas gathering pipelines which are depreciated based on the estimated lives of the gas wells served. Repairs of all property, plant and equipment and replacements and renewals of minor items of property are charged to expense as incurred. Income Taxes The Company accounts for income taxes in accordance with FASB Statement No. 109, "Accounting for Income Taxes." Deferred income taxes reflect the future tax consequences of differences between the tax bases of assets and liabilities and their financial reporting amounts at each year end. For income tax purposes, the Company deducts the difference between market value and exercise price arising from the exercise of stock options. The tax effect of this deduction which, for financial reporting purposes, is accounted for as an increase to additional paid-in capital, amounted to $1,072,000, $665,000 and $201,000 in 1997, 1996 and 1995, respectively. Earnings Per Share Basic earnings per share were computed by dividing net income by the weighted average number of common shares outstanding during the year as required by FASB Statement No. 128, "Earnings per Share" ("SFAS 128"). Diluted earnings per share have been computed by dividing net income by the weighted average number of common shares outstanding plus the incremental shares that would have been outstanding assuming the exercise of stock options and stock warrants as applicable. A reconciliation of shares used for basic earnings per share and those used for diluted earnings per share is as follows:
Year Ended December 31, ------------------------ 1997 1996 1995 ------ ------ ------ (amounts in thousands) Average common stock outstanding 28,856 23,114 22,960 Common stock equivalents 515 453 365 ------ ------ ------ Average common stock and common stock equivalents outstanding 29,371 23,567 23,325 ====== ====== ======
Common stock equivalents are not applicable for 1997 earnings per share as they would be anti-dilutive. On May 6, 1997 the Company's Board of Directors approved a two-for-one stock split of its common stock effective June 30, 1997 to stockholders of record on June 3, 1997. All references in these financial statements and notes thereto related to the number of common shares and per share amounts reflect the stock split. 2. Discontinued Operations During the first quarter of 1997, the Board of Directors approved a plan to discontinue the Company's natural gas transportation and marketing operations in order to focus on the core oil and gas exploration and production operations. During 1997, the Company sold its Texas intrastate natural gas pipeline system and its third-party natural gas marketing operations, realizing proceeds of $28.5 million and an after-tax gain of $5.4 million. Income taxes associated with the discontinued operations were $2.8 million. 31 34 The results for the transportation and marketing operations have been classified as discontinued operations for all periods presented in the Statements of Consolidated Operations. The assets and liabilities of the discontinued operations have been classified in the Consolidated Balance Sheets as "Net assets of discontinued operations". By December 31, 1997, all assets of the discontinued operations were disposed of. Net assets of the Company's discontinued operations at December 31, 1996 were as follows:
December 31, 1996 ------------ (thousands of dollars) Assets Current Assets $64,627 Net property, plant and equipment and other 19,941 ------- Total assets 84,568 Liabilities Current liabilities 55,701 Noncurrent liabilities 2,209 ------- Total liabilities 57,910 ------- Net assets of discontinued operations $26,658 =======
Summarized results of operations of the Company's discontinued operations are as follows:
Year Ended December 31, ----------------------------------- 1997 1996 1995 --------- --------- --------- (thousands of dollars) Revenues $ 22,015 $ 274,323 $ 360,627 Costs and expenses * 22,129 277,237 363,968 --------- --------- --------- (Loss) before income taxes (114) (2,914) (3,341) (Benefit) for income taxes (42) (1,069) (1,242) --------- --------- --------- (Loss) from discontinued operations $ (72) $ (1,845) $ (2,099) ========= ========= ========= Gain on disposal before income taxes $ 8,198 $ -- $ -- Provision for income taxes 2,824 -- -- --------- --------- --------- Net gain on disposal $ 5,374 $ -- $ -- ========= ========= =========
* Includes allocated net interest expense of $0.1 million, $3.8 million and $1.1 million for the years ended December 31, 1997, 1996 and 1995, respectively. Discontinued operations have not been segregated in the Statements of Consolidated Cash Flows and, therefore, amounts for certain captions will not agree with the respective Statements of Consolidated Operations and Consolidated Balance Sheets. 3. Acquisitions Medallion Acquisition. As of December 31, 1996, the Company completed the arrangements for the acquisition of all of the outstanding stock of InterCoast Oil and Gas Company (formerly Medallion Production Company), GED Energy Services, Inc. and InterCoast Gas Services Company (collectively referred to as Medallion), indirect wholly-owned subsidiaries of MidAmerican Energy Holdings Company ("MidAmerican"), for a purchase price of approximately $199.1 million, consisting of a cash payment of $194.1 million and warrants to purchase 870,000 shares of Common Stock at an exercise price of $22.50 per share and a four-year term (the "Medallion Acquisition"). Medallion's principal assets as of December 31, 1996, were proved oil and gas reserves of 187.5 Bcfe consisting of 140.3 Bcf of natural gas and 7.9 MMbbls of oil and liquids. The Company also acquired a natural gas 32 35 gathering system as well as oil and gas equipment and supplies. The Medallion Acquisition doubled the Company's reserve and production base at December 31, 1996. Rocky Mountain Acquisition. On November 8, 1995, the Company acquired substantially all of the oil and gas assets of Natural Gas Processing Company (the "Rocky Mountain Acquisition") for $33 million, subject to adjustments for a July 1, 1995 effective date. Proved reserves attributable to the properties acquired were estimated to be 66.7 Bcfe at September 30, 1995, consisting of 40.9 Bcf of natural gas and 4.3 MMbbls of oil. The Company also acquired a significant inventory of oil and gas equipment and supplies, vehicles and buildings as well as natural gas gathering systems consisting of approximately 200 miles of pipeline. The above acquisitions were accounted for using the purchase method. The results of operations for the acquired entities are included in the Company's consolidated results of operations from the dates of acquisition. Pro forma revenue, net income and basic earnings per share giving effect to the Medallion Acquisition for the year ended December 31, 1996, as if the transaction had occurred on January 1, 1996, is $180.1 million, $35.1 million and $1.21, respectively. Such unaudited pro forma financial data does not purport to be indicative of the results of operations that would actually have occurred if the transaction had occurred as presented or that may be obtained in the future. 4. Retirement Benefit Plans The Company sponsors a Savings and Investment Plan ("Savings Plan") under Section 401(k) of the Internal Revenue Code. Eligible employees may contribute up to 16% of their base salary to the Savings Plan subject to certain IRS limitations. The Company may make matching contributions, which have been set by the Board of Directors at 50% of the employee's contribution (up to 6% of the employee's annual base salary). 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. Employee and profit-sharing contributions 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. Company matching contributions are invested in shares of KCS common stock. Eligible employees vest in both the Company matching and discretionary profit-sharing contributions over a four-year period based upon their years of service with the Company. Company contributions to the Savings Plan were $420,090 in 1997, $102,455 in 1996 and $253,666 in 1995. 5. Stock Option and Incentive Plans Under the 1988 Stock Plan and the 1992 Stock Plan (the "Employee Incentive Plans"), stock options, stock appreciation rights and restricted stock may be granted to employees of KCS. The 1992 Stock Plan also provides that bonus stock may be granted to employees. The 1994 Directors' Stock Plan provides that each non-employee director be granted stock options for 2,000 shares annually. This plan also provides that in lieu of cash, each non-employee director be issued KCS stock with a fair market value equal to 50% of their annual retainer. Each 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. Restricted shares awarded under the Employee Incentive Plans 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 has the same dividend and voting rights as other common stock and is considered to be currently issued and outstanding. The cost of the awards, determined as the fair market value of the shares at the date of grant, is expensed ratably over the period the restrictions lapse. This cost was immaterial during the three years ended December 31, 1997. Restricted stock totaling 29,200 shares was outstanding under the Employee Incentive Plans at December 31, 1997. At December 31, 1997, 1,018,074 shares were available for future grants under the Employee Incentive Plans. Under the 1988 KCS Energy, Inc. Employee Stock Purchase Program (the "Program"), all eligible employees and directors may purchase full shares from the Company at a price per share equal to 90% of the market 33 36 value determined by the closing price on the date of purchase. The minimum purchase is 50 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 14,520, 15,326 and 13,794 during 1997, 1996 and 1995, respectively. At December 31, 1997, there were 857,544 shares available for issuance under the Program. As permitted under SFAS 123, the Company has elected to continue to account for stock-based compensation under the provisions of APB Opinion No. 25. Had compensation cost for the following plans been determined consistent with SFAS 123, the impact on the Company's net income would have been $0.7 million in 1997 and $0.1 million in 1996. The impact on basic earnings per share would have been $0.02 in 1997. There would have been no effect on earnings per share in 1996 and 1995. As required under SFAS 123, a summary of the status of the stock options under the Employee Incentive Plans and the 1994 Directors' Stock Plan at December 31, 1997, 1996 and 1995 and changes during the years then ended is presented in the table and narrative below:
1997 1996 1995 ----------------------------- ----------------------------- ------------------------------ Weighted Average Weighted Average Weighted Average Shares Exercise Price Shares Exercise Price Shares Exercise Price ---------- ---------------- ---------- ---------------- ---------- ----------------- Outstanding at beginning of year 1,059,150 $ 5.46 1,265,600 $ 4.95 1,107,000 $ 4.50 Granted 349,400 16.82 12,000 11.44 210,000 6.58 Exercised (236,250) 8.04 (183,000) 1.81 (45,200) 0.81 Forfeited (108,900) 13.83 (35,450) 7.85 (6,200) 12.09 ---------- ---------------- ---------- ---------------- ---------- ----------------- Outstanding at end of year 1,063,400 7.76 1,059,150 5.46 1,265,600 4.95 ---------- ---------------- ---------- ---------------- ---------- ----------------- Exercisable at end of year 697,300 $ 4.58 779,812 $ 4.68 777,600 $ 3.30 ---------- ---------------- ---------- ---------------- ---------- ----------------- Weighted average fair value of options granted $ 8.79 $ 4.36 $ 2.41 ================ ================ =================
The following table summarizes information about stock options outstanding at December 31, 1997:
Number Weighted Average Weighted Number Weighted Range of Outstanding at Remaining Average Exercisable at Average Exercise Prices December 31, 1997 Contractual Life Exercise Price December 31, 1997 Exercise Price - ----------------- -------------------- --------------------- ---------------- --------------------- --------------- $0.92 - $3.12 360,000 3.02 $ 0.98 360,000 $ 0.98 3.13 - 4.68 60,000 4.92 3.13 60,000 3.13 4.69 - 7.01 125,000 7.91 6.50 55,000 6.50 7.02 - 10.52 125,000 6.93 7.32 87,500 7.34 10.53 - 18.81 393,400 8.23 15.21 134,800 12.24 - ----------------- -------------------- --------------------- ---------------- --------------------- --------------- $0.92 - $18.81 1,063,400 6.09 $ 7.76 697,300 $ 4.58 ================= ==================== ===================== ================ ===================== ===============
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 1997, 1996 and 1995, respectively: risk-free interest rates of 6.39%, 6.52% and 5.73%; expected dividend yield of 0.46%, 0.33% and 0.33%; expected lives of 5.6 years, 5.1 years and 5.1 years; expected stock price volatility of 50.1%, 30.0% and 30.0%. 34 37 6. Long-Term Debt Long-term debt consists of the following:
December 31, ------------------------- 1997 1996 -------- -------- (dollars in thousands) 11% Senior Notes Due 2003 $149,545 $149,456 Revolving Credit Agreement 68,400 105,000 Credit Facility 74,500 55,600 Other -- 291 -------- -------- 292,445 310,347 Less current maturities -- -- -------- -------- Long-term debt $292,445 $310,347 ======== ========
Subordinated Notes On January 15, 1998, KCS Energy, Inc. (the "Parent") completed a public offering of $125 million senior subordinated notes at an interest rate of 8.875% due January 15, 2008 (the "Subordinated Notes"). The Subordinated Notes are noncallable for five years and are unsecured subordinated obligations of the Parent. Prior to January 15, 2001, the Parent may use proceeds from a public equity offering to redeem up to 33-1/3% of the Subordinated Notes. The subsidiaries of the Parent have guaranteed the Subordinated Notes on an unsecured subordinated basis. The net proceeds of approximately $121 million were used to reduce the outstanding indebtedness under the credit agreements discussed below. The Subordinated Notes 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 restrict the aggregate cash dividends paid to 50% of the Company's cumulative net income, as defined in the indenture, during the period beginning October 1, 1997. A ceiling writedown is not a charge against net income as defined in the indenture. Senior Notes KCS Energy, Inc. has outstanding $150 million principal amount of 11% senior notes due 2003 issued pursuant to an indenture governing the senior notes dated January 25, 1996 (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, commencing January 15, 2000, at pre-determined redemption prices set forth within the Senior Notes indenture. Prior to January 15, 1999, the Parent may use proceeds from a public equity offering to redeem up to $35 million of the Senior Notes. The subsidiaries of the Parent have guaranteed the Senior Notes on a senior unsecured basis. The Senior Notes 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 and restrict the aggregate cash dividends paid to 50% of the Company's cumulative net income, as defined in the indenture, during the period beginning October 1, 1995. A ceiling writedown is not a charge against net income as defined in the indenture. Revolving Credit Agreement Simultaneous with the consummation of the Medallion Acquisition, the Company entered into a revolving credit agreement ("Revolving Credit Agreement") with a group of banks which will mature on September 30, 2000. The Revolving Credit Agreement is used for general corporate purposes, including working capital and to support the Company's capital expenditure program. As of December 31, 1997, the Revolving Credit Agreement had a borrowing base of $90 million. The borrowing base is reviewed at least semiannually and may be adjusted based on the lenders' valuation of the borrowers' oil and gas reserves and other factors. The obligations under the Revolving Credit Agreement are secured by substantially all of the oil and gas reserves acquired in the Medallion Acquisition, a pledge of the Medallion entities' common stock and certain VPP assets. The Revolving Credit Agreement permits 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 twelve months. The applicable spread over the prime rate or LIBOR is determined each quarter based on KCS' consolidated debt-to-EBITDA ratio. A commitment fee of 0.375% is paid on the unused portion of the borrowing base. The weighted average effective 35 38 interest rate during 1997 was 7.8%. As of December 31, 1997, the weighted average interest rate under the Revolving Credit Agreement was 7.4% and $68.4 million was outstanding. Proceeds from the January 1998 sale of the Subordinated Notes were used to decrease the amount then outstanding under the Revolving Credit Agreement to $1.0 million. The borrowing base of the Revolving Credit Agreement was unaffected by the sale of the Subordinated Notes. Credit Facility The Company's revolving credit facility ("Credit Facility"), which matures on September 30, 2000, is used for general corporate purposes, including working capital and to support the Company's capital expenditure program. On December 31, 1997, the borrowing base, or actual availability under the Credit Facility, was limited to $75 million under the terms of the Senior Notes. The borrowing base is reviewed at least semiannually and may be adjusted based on the lenders' valuation of the borrowers' oil and gas reserves and other factors. Substantially all of the Company's oil and gas reserves (excluding those pledged under the Revolving Credit Agreement) have been pledged to secure the Credit Facility. The Credit Facility permits the borrowers to choose interest rate options based on the bank's prime rate or LIBOR and from maturities ranging up to twelve months. The applicable spread over the prime rate or LIBOR is determined each quarter based on KCS' consolidated debt-to-EBITDA ratio. A commitment fee of 0.375% is paid on the unused portion of the borrowing base. The weighted average effective interest rate during 1997 was 7.0%. As of December 31, 1997, the weighted average interest rate under the Credit Facility was 7.0% and $74.5 million was outstanding. Following the application of the proceeds from the January 1998 sale of the Subordinated Notes the amount then outstanding under the Credit Facility was $30.5 million. The borrowing base of the Credit Facility was unaffected by the sale of the Subordinated Notes. Other Information KCS Energy, Inc. is a borrower under the Revolving Credit Agreement and has guaranteed the obligations of its subsidiaries under the Credit Facility. The agreements, as amended effective December 31, 1997, contain certain restrictive covenants which, among other things, require the Company to maintain minimum levels of cash flow and tangible net worth, as defined in the agreements. In addition, the Company is restricted from incurring secured indebtedness in an amount which is the greater of $75 million or 15% of adjusted consolidated net tangible assets (as defined in the Senior Notes indenture). This restriction does not apply to purchase money indebtedness. The Company's ability to pay cash dividends is limited by these agreements. The fair value of the Company's Senior Notes, $165 million, is estimated based upon the December 31, 1997 quoted market price of $110.00 for such issue. The carrying amount of the remaining long-term debt reasonably approximates fair value because its interest rates are based on current market rates. Prior to the January 1998 issuance of the Subordinated Notes, the scheduled maturities of long-term debt during the next five years were as follows: 1998 $-0- million, 1999 $-0- million, 2000 $142.9 million, 2001 $-0- million and 2002 $-0- million. Interest payments were $22.5 million in 1997, $10.9 million in 1996 and $6.8 million in 1995. 7. Leases Future minimum lease payments under non-cancelable operating leases are as follows: $787,000 in 1998, $602,000 in 1999, $556,000 in 2000, $491,000 in 2001 and $197,000 in 2002. Lease payments charged to operating expenses amounted to $796,000, $564,000 and $466,000 during 1997, 1996 and 1995, respectively. 36 39 8. Income Taxes Federal and state income tax expense (benefit) includes the following components:
For the Year Ended December 31, ----------------------------------- 1997 1996 1995 --------- --------- --------- (dollars in thousands) Current provision $ -- $ 3,800 $ 2,545 Deferred provision (benefit), net (52,406) 7,028 8,096 --------- --------- --------- Federal income tax expense (benefit) (52,406) 10,828 10,641 State income taxes (deferred provision $300 in 1997, $578 in 1996, and $1,460 in 1995) 351 1,852 1,176 --------- --------- --------- $ (52,055) $ 12,680 $ 11,817 ========= ========= ========= Reconciliation of federal income tax expense (benefit) at statutory rate to provision for income taxes: Income (loss) before income taxes $(149,440) $ 34,397 $ 35,222 --------- --------- --------- Tax provision (benefit) at 35% statutory rate (52,304) 12,039 12,328 State income tax, net of federal income tax benefit 228 1,204 764 Statutory depletion (23) (475) (676) Section 29 credits -- -- (425) Other, net 44 (88) (174) --------- --------- --------- $ (52,055) $ 12,680 $ 11,817 ========= ========= =========
The primary differences giving rise to the Company's deferred tax assets and liabilities are as follows:
December 31, 1997 --------------------- Assets Liabilities ------ ----------- (dollars in thousands) Income tax effects of: Accelerated DD&A and other property related items $13,646 Deferred revenue 5,354 Alternative minimum tax credit carry forwards $ 1,923 Net operating loss carry forward 33,412 Other, net 262 ------- ------- $35,597 $19,000 ======= =======
Income tax payments were $0.5 million in 1997 and $5.6 million in 1996. No income tax payments were made in 1995. Deferred tax assets relate primarily to the Company's tax net operating loss and alternative minimum tax credit carryforwards. The Company had tax net operating losses ("NOLs") of approximately $95.5 million available to offset future taxable income (assuming it elects to forego its right to carryback approximately $18.0 million which it currently could carryback to prior periods) of which approximately $14.5 million will expire in 2011 and approximately $81.0 million will expire in 2012. SFAS 109 requires that the tax benefit of such NOLs be recorded as an asset to the extent that management assesses the realization of such NOLs to be "more likely than not". Management has concluded that operating income of the Company will more likely than not be sufficient to fully utilize the $95.5 million of NOLs prior to their expiration in the year 2012. In assessing the likelihood of utilization of existing NOLs, management considered, among other things, the historical operating earnings of KCS prior to the $165.1 million writedown in 1997 of its oil and gas properties. This writedown was largely attributable to significant oil and gas price declines, but was also impacted by delays in the start up of the Manderson Field. The deferred tax assets will be monitored for potential adjustments as future events so indicate. 37 40 9. Financial Instruments The Company has entered into swaps, futures contracts and options to manage risks associated with fluctuations in the price of its natural gas and oil production. Commodity Price Swaps. Commodity price swap agreements require the Company to make payments to (or entitle it to receive payments from) the counterparties based upon the differential between a specified fixed and variable price. The Company accounts for these transactions on a settlement basis and, accordingly, gains or losses are included in gas revenue in the period in which the underlying natural gas is produced. These agreements do not impose cash margin requirements on the Company. At December 31, 1997, the Company was party to commodity price swap agreements covering approximately 4.8 million MMBtu, 3.9 million MMBtu and 13.8 million MMBtu of natural gas production for the years 1998 and 1999 and for the period 2000 through 2005, respectively. Futures and Options Contracts. Natural gas futures contracts require the Company to buy or sell natural gas at a fixed price. The Company uses futures to hedge price risk on a portion of its gas production and to manage profit margins on offsetting fixed-price purchase or sale commitments for physical quantities of natural gas. Futures contracts mandate initial margin requirements. The Company maintains such margin accounts and funds in cash any daily settlement requirements relating to futures contracts. Natural gas options used to hedge price risk only provide the right, not the requirement, to buy or sell natural gas at a fixed price. The Company uses options to limit overall price risk exposure. At December 31, 1997, the Company's hedging activities consisted of 219 short contracts at an average price of $2.46 per MMBtu maturing through 1998, covering 2,190 MMBtu of natural gas. At December 31, 1996, the Company's hedging activities consisted of 157 short contracts at an average price of $2.31 per MMBtu maturing through 1997 covering 1,570 MMBtu of natural gas. Since these contracts qualify as hedges and correlate to market price movements of natural gas, any gains or losses resulting from market changes will be offset by losses or gains on corresponding physical transactions. Deferred gains, net of deferred losses, were $0.5 million at December 31, 1997. Deferred losses, net of deferred gains, were $0.1 million at December 31, 1996. 10. Litigation Tennessee Gas Litigation Prior to January 1, 1997, most of the Company's natural gas sold from the Bob West Field in south Texas was covered by the Tennessee Gas Contract, which had been the subject of several lawsuits. On December 23, 1996, the Company and Tennessee Gas entered into a comprehensive settlement covering all claims and litigation between them related to the Tennessee Gas Contract. As part of the settlement, the Tennessee Gas Contract was terminated effective January 1, 1997, approximately two years prior to its expiration date. The parties also agreed to the dismissal of the two pending lawsuits that had been filed in Zapata County, Texas, thereby concluding all matters of litigation between them. The December 1996 settlement did not affect the Company's successful conclusion earlier in the year of the litigation that was decided by the Texas Supreme Court relating to the validity and pricing provisions of the Tennessee Gas Contract or the Company's recovery of $70 million of past underpayments (including interest and net of severance taxes and other payables related to the contract) that had accrued under the Tennessee Gas Contract. Royalty Suits The Company is a party to six lawsuits in the Texas State Courts involving various claims asserted by various holders of royalty interests under leases on the acreage that was dedicated to the Tennessee Gas Contract or pooled therewith. One suit involves claims by the holder of an overriding royalty interest in the dedicated acreage of certain rights in the Tennessee Gas Contract. Of the other five (the "Royalty Basis Suits"), one seeks a declaratory judgment on the royalty payment basis for non-dedicated acreage in which the Company owns no interest. The other four suits seek declaratory judgments to determine whether royalties payable to the holders of landowner royalty interests in the dedicated acreage should be based on the net proceeds received by the Company for gas sales under the Tennessee Gas Contract or on the spot market price. The Company paid royalties based upon the spot market price to the holders of royalty interests (other than the overriding royalty interest) because the Company's leases, which cover only dedicated acreage, have market value royalty provisions. Initially, there were three Royalty Basis Suits, one in Dallas County, Texas, in which the Company is a co- 38 41 plaintiff and two subsequently filed suits in Zapata County, Texas, in which the Company is a co-defendant (the "Las Blancas Suit" and the "Gonzalez Suit"). The Dallas suit was subsequently split into four separate lawsuits, based on issues concerning (1) the dedicated acreage in the Guerra "A" and Guerra "B" Units (the "Los Santos Suit"), (2) the non-dedicated acreage in those Units (the "Collins Suit"), in which the Company has no interests, (3) the Jesus Yzaguirre Unit, which consists entirely of dedicated acreage owned only by the Company (the "Jesus Yzaguirre Suit"), and (4) the overriding royalty interest in the dedicated acreage (the "Matthews Suit"). On March 4, 1997, the holder of an overriding royalty interest filed a claim against the Company and its co-lessees in the Matthews Suit, alleging breach of duties arising from the termination of the Tennessee Gas Contract and for certain tortious acts. Effective January 23, 1998, the Company and the royalty holder settled their disputes. On February 3, 1998, the Company and its co-lessees were dismissed from the Matthews Suit. In addition, in May 1997, the Gonzalez Suit was dismissed and in October 1997 the Las Blancas Suit was dismissed. The Los Santos Suit and the Jesus Yzaguirre Suit have resulted in separate summary judgments in favor of the Company's position that royalty payments based upon the spot market price are all that is required to be paid under the leases and dismissal of the royalty owners counterclaims and affirmative defenses. In early 1997, the summary judgment in the Los Santos Suit was appealed to the Fifth Court of Appeals in Dallas by the royalty holders, who have requested oral argument on eleven points of error. These points of error concern the granting of summary judgment against them on issues of lease provisions on market value royalties; counterclaims and affirmative defenses of fraud, negligent misrepresentations, conspiracy and estoppel; denial of their efforts to supplement summary judgment evidence; denial of efforts to transfer venue to Zapata County; failure to abate the Dallas lawsuit in favor of the two lawsuits filed by them in Zapata County; and the entry of final judgment in favor of the Company and its co-plaintiffs. In the Jesus Yzaguirre Suit, certain of the royalty owners counterclaimed against the Company, asserting that the largest lease contained therein had terminated in December, 1975, and that they were entitled to the Tennessee Gas Contract Price because of the execution of certain division orders in 1992 that allegedly varied the market value royalty provision of their lease. On May 30, 1997, the Company and these royalty owners reached a settlement of the lease termination claims, and on June 2, 1997, this issue was dismissed from the Jesus Yzaguirre Suit. On June 17, 1997, the Company and the royalty owners moved for summary judgment on the issue of the effect of division orders. The trial judge granted the Company's motion and denied the competing motion on August 12, 1997. On October 29, 1997, a final judgment was signed, and on November 19, 1997, the royalty owners gave notice of their appeal to the Fifth Court of Appeals in Dallas, Texas. The appellate record has been filed and the royalty owners' brief was filed with the Fifth Court of Appeals on March 18, 1998. The Company will file its brief in response to the royalty owners' various points of error and legal arguments early in the second quarter of 1998. Given the inherent uncertainties of appellate matters and notwithstanding that the Company's position on the market value and other issues is based upon established decisional law in Texas, the Company is unable to provide any assurance of a favorable outcome of the appeals from the summary judgments and evidentiary rulings in the Los Santos Suit and the Jesus Yzaguirre Suit, inasmuch as the Appellants in each appeal can obtain a reversal and remand for plenary trial upon showing that summary judgment was improper because there exists an issue of material fact. The aggregate amount at issue in the Los Santos and Jesus Yzaguirre Suits, apart from certain tort counterclaims and affirmative defenses alleged by the landowner royalty holders, is a function of the quantity of natural gas for which Tennessee Gas paid at the contract price. As of January 1, 1997 (the date of the termination of the Tennessee Gas Contract) the amount of natural gas taken by Tennessee Gas attributable to the royalty interests involved in the Royalty Basis Suits was approximately 3.8 Bcf for which royalties have been paid by the Company at the average price of approximately $1.63 per Mcf, net of severance tax, compared to the average Tennessee Gas Contract price of approximately $7.60 per Mcf, net of severance tax. Consequently, if the Company loses in its litigation with these royalty interest owners on these claims the Company faces a maximum liability in the Royalty Basis Suits of approximately $22.7 million, plus interest thereon, at December 31, 1997. Other 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. 39 42 11. Quarterly Financial Data (unaudited)
Quarters --------------------------------------------------------- First Second Third Fourth ----------- ----------- ----------- ----------- (dollars in thousands, except per share data) 1997 Revenue $ 39,879 $ 32,551 $ 31,668 $ 39,591 Operating income (loss) 13,717 8,025 7,744 (157,519)* Income (loss) from continuing operations 5,405 2,292 1,579 (106,661)* Discontinued operations 5,389 -- -- (87) Net income (loss) $ 10,794 $ 2,292 $ 1,579 $ (106,748)* Basic earnings per common share: Continuing operations $ 0.20 $ 0.08 $ 0.05 $ (3.63)* Discontinued operations 0.19 -- -- -- ----------- ----------- ----------- ----------- Basic earnings per common share $ 0.39 $ 0.08 $ 0.05 $ (3.63)* =========== =========== =========== =========== Diluted earnings per common share: Continuing operations $ 0.20 $ 0.08 $ 0.05 $ (3.63)* Discontinued operations 0.19 -- -- -- ----------- ----------- ----------- ----------- Diluted earnings per common share $ 0.39 $ 0.08 $ 0.05 $ (3.63)* =========== =========== =========== =========== 1996 Revenue $ 27,284 $ 26,098 $ 26,046 $ 28,946 Operating income 11,835 10,721 10,080 10,760 Income from continuing operations 5,973 5,524 5,283 4,937 Income (loss) from discontinued operations (118) (537) (1,319) 129 Net income $ 5,855 $ 4,987 $ 3,964 $ 5,066 Basic earnings per common share: Continuing operations $ 0.26 $ 0.24 $ 0.23 $ 0.21 Discontinued operations (0.01) (0.02) (0.06) 0.01 ----------- ----------- ----------- ----------- Basic earnings per common share $ 0.25 $ 0.22 $ 0.17 $ 0.22 =========== =========== =========== =========== Diluted earnings per common share: Continuing operations $ 0.26 $ 0.23 $ 0.22 $ 0.21 Discontinued operations (0.01) (0.02) (0.05) -- ----------- ----------- ----------- ----------- Diluted earnings per common share $ 0.25 $ 0.21 $ 0.17 $ 0.21 =========== =========== =========== ===========
* Includes a $165,149 pretax, $107,347 after-tax, or $3.65 per share non-cash ceiling write down of oil and gas assets. 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 Company's issuance of additional shares of common stock during the year. 40 43 12. Oil and Gas Producing Operations The following data is presented pursuant to FASB Statement No. 69 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, 1997 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 $2.50 and $3.54 at December 31, 1997 and 1996, respectively, and oil prices were $15.15 and $22.45 at December 31, 1997 and 1996, respectively. VPP volumes represent oil and gas reserves purchased from third parties which generally entitle the Company to a specified volume of oil and gas to be delivered over a stated time period. The related volumes stated herein reflect scheduled amounts of oil and gas to be delivered to the Company at agreed delivery points and future cash inflows are estimated at year-end prices. Although specific terms of the Company's VPPs vary, the Company is generally entitled to receive delivery of its scheduled oil and gas volumes, free of drilling and lease operating costs and, in certain cases, free of state severance taxes. 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, ----------------------------------- 1997 1996 1995 --------- --------- --------- (dollars in thousands) Revenue $ 137,837 $ 107,959 $ 85,424 Production (lifting) costs 35,266 11,693 6,623 Technical support and other 6,978 4,401 2,373 Depreciation, depletion and amortization 58,465 44,565 37,859 Writedown of oil and gas properties 165,149 -- -- --------- --------- --------- Total expenses 265,858 60,659 46,855 --------- --------- --------- Pretax income (loss) from producing activities (128,021) 47,300 38,569 Income tax provision (benefit) (48,344) 17,381 12,549 --------- --------- --------- Results of oil and gas producing activities (excluding corporate overhead and interest) $ (79,677) $ 29,919 $ 26,020 ========= ========= ========= Capitalized costs incurred: Property acquisition $ 70,364 $ 198,927 $ 77,515 Exploration 33,440 18,315 16,891 Development 107,424 54,889 26,859 --------- --------- --------- Total capitalized costs incurred $ 211,228 $ 272,131 $ 121,265 ========= ========= ========= Capitalized costs at year-end: Proved properties $ 739,551 $ 544,213 $ 284,597 Unproved properties 21,080 10,574 7,297 --------- --------- --------- 760,631 554,787 291,894 Less accumulated depreciation, depletion and amortization (356,877) (133,263) (86,936) --------- --------- --------- Net investment in oil and gas properties $ 403,754 $ 421,524 $ 204,958 ========= ========= =========
- -------------------------------------------------------------------------------- 41 44 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 FASB Statement No. 69. Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
December 31, -------------------------- 1997 1996 =========== =========== (dollars in thousands) Future cash inflows $ 1,092,271 $ 1,213,604 Future costs: Production (371,762) (320,457) Development (66,574) (43,882) Discount - 10% annually (243,429) (291,653) ----------- ----------- Present value of future net revenues 410,506 557,612 Future income taxes, discounted at 10% (35,624) (120,013) ----------- ----------- Standardized measure of discounted future net cash flows $ 374,882 $ 437,599 =========== ===========
Changes in Discounted Future Net Cash Flows From Proved Reserve Quantities
For the Year Ended December 31, ----------------------------------- 1997 1996 1995 --------- --------- --------- (dollars in thousands) Balance, beginning of year $ 437,599 $ 231,763 $ 179,660 Increases (decreases) Sales, net of production costs (102,571) (96,266) (78,801) Net change in prices, net of production costs (201,580) 50,328 9,593 Discoveries and extensions, net of future production and development costs 101,004 67,791 22,417 Changes in estimated future development costs (18,912) 2,005 (862) Change due to acquisition of reserves in place 40,509 292,557 108,798 Development costs incurred during the period 34,674 10,411 9,672 Revisions of quantity estimates (19,160) (45,003) (19,256) Accretion of discount 55,761 29,108 24,033 Net change in income taxes 84,390 (60,691) 2,021 Sales of reserves in place (2,225) (11,507) (1,931) Changes in production rates (timing) and other (34,607) (32,897) (23,581) --------- --------- --------- Net increase / (decrease) (62,717) 205,836 52,103 --------- --------- --------- Balance, end of year $ 374,882 $ 437,599 $ 231,763 ========= ========= =========
- -------------------------------------------------------------------------------- 42 45 Reserve Information (Unaudited) The following information with respect to the Company's 1997 net proved oil and gas reserves are estimates based on reports prepared by KCS and other independent petroleum engineers. The reports for the KCS Medallion Resources, Inc.; KCS Mountain Resources, Inc.; KCS Resources, Inc.; and KCS Michigan Resources, Inc. properties, which collectively represent 90% of total KCS proved reserves at December 31, 1997, were audited by Netherland, Sewell & Associates, Inc. pursuant to the principles set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers. Proved developed reserves represent only those reserves expected to be recovered through existing wells using equipment currently in place. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells or from existing wells after material recompletion expenditures. All of the Company's reserves are located within the United States.
1997 1996 1995 -------------------- -------------------- -------------------- Gas Oil Gas Oil Gas Oil MMcf Mbbl MMcf Mbbl MMcf Mbbl -------- -------- -------- -------- -------- -------- Proved developed and undeveloped reserves Balance, beginning of year 268,025 14,631 140,963 7,517 89,184 2,319 Production (43,700) (1,824) (25,581) (758) (19,129) (196) Discoveries, extensions, ect 110,010 6,172 21,998 2,196 10,399 202 Acquisition of reserves in place 23,281 155 157,051 7,245 71,560 5,449 Sales of reserves in place (698) (23) (9,224) (492) (3,751) (3) Revisions of estimates (30,750) (48) (17,182) (1,077) (7,300) (254) -------- -------- -------- -------- -------- -------- Balance, end of year 326,168 19,063 268,025 14,631 140,963 7,517 ======== ======== ======== ======== ======== ======== Proved developed reserves Balance, beginning of year 236,454 12,133 121,987 3,808 74,215 1,336 -------- -------- -------- -------- -------- -------- Balance, end of year 234,091 13,008 236,454 12,133 121,987 3,808 ======== ======== ======== ======== ======== ========
13. Subsequent Events On January 15, 1998, the Company completed a public offering of $125 million Senior Subordinated Notes at an interest rate of 8.875% due January 15, 2008. The net proceeds of approximately $121 million were used to pay down borrowings under the bank credit facilities (See Note 6). 43 46 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 1998 Annual Meeting of Stockholders. PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. (a) Financial statements, financial statement schedules, and exhibits. (1) The following consolidated financial statements of KCS and its subsidiaries are presented in Item 8 of this Form 10-K. Page ---- Report of Independent Public Accountants................................25 Statements of Consolidated Operations for the years ended December 31, 1997, 1996 and 1995........................................26 Consolidated Balance Sheets at December 31, 1997 and 1996...............27 Statements of Consolidated Stockholders' Equity for the years ended December 31, 1997, 1996 and 1995..................................28 Statements of Consolidated Cash Flows for the years ended December 31, 1997, 1996 and 1995........................................29 Notes to Consolidated Financial Statements.........................30 - 43 (3) Exhibits See "Exhibit Index" located on page 46 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, 1997. 44 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) Date: 4/13/98 By: /s/ Frederick Dwyer ------- ----------------------- Frederick Dwyer Vice President and Controller 45 48 Exhibit Index Exhibit No. Description ------ ----------- (3) i Certificate of Incorporation of KCS filed as Exhibit 4.3 to Form S-8 Registration Statement No. 33-63982 filed with SEC June 8, 1993. ii By-Laws of KCS filed as Exhibit 4.4 to Form S-8 Registration Statement No. 33-63982 filed with SEC June 8, 1993. (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. iv Form of 11% Senior Note due 2003 (included in Exhibit (4) (iii)). (10) i Performance Unit Plan filed as Exhibit 10B of Registrant's Form 10 filed with the SEC May 13, 1988.* ii 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.* iii 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.* iv 1988 Stock Plan filed as Exhibit 10A of Registrant's Form 10 filed with the SEC May 13, 1988 and as Exhibit 4.1 to Form S-8 Registration Statement No. 33-25707 filed with the SEC on November 21, 1988.* v KCS Group, Inc. Savings and Investment Plan filed as Exhibit 4.1 to Form S-8 Registration Statement No. 33-28899 filed with the SEC on May 16, 1989.* vi 1992 Stock Plan filed as Exhibit 4.1 to Form S-8 Registration Statement No. 33-45923 filed with the SEC on February 24, 1992.* vii Purchase and Sale Agreement dated as of November 30, 1995 between the Company and Hawkins Oil of Michigan, Inc. (formerly Savoy Oil & Gas, Inc.), Conveyance of Production Payment dated as of November 30, 1995, Production and Delivery Agreement dated as of November 30, 1995, Option Agreement dated as of November 30, 1995, Drilling Participation Agreement dated December 7, 1995, Assignment and Bill of Sale (Working Interests) filed with the SEC as Exhibits 2.1 through 2.6 to Form 8-K on December 22, 1995. viii Purchase and Sale Agreement dated September 8, 1995 by and between Natural Gas Processing Co., a Wyoming corporation, and KCS Resources, Inc., a Delaware corporation filed with the SEC as Exhibit 2.1 to Form 8-K on November 22, 1995. 46 49 ix Credit Agreement among KCS Resources, Inc., KCS Pipeline Systems, Inc., KCS Michigan Resources, Inc. and KCS Energy Marketing, Inc., Canadian Imperial Bank of Commerce, New Agency, as Agent, CIBC Inc., as Collateral Agent, Bank One, Texas, National Association, as Co-Agent, NationsBank of Texas, N.A. as Co-Agent dated September 25, 1996. x Guaranty by KCS Energy, Inc. in Favor of Canadian Imperial Bank of Commerce, New York Agency, as Agent dated September 25, 1996. xi Stock Purchase Agreement by, between and among KCS Energy, Inc., InterCoast Energy Company, and InterCoast Gas Services Company dated November 14, 1996 filed with the SEC as Exhibit 2.1 to Form 8-K/A on November 15, 1996. xii Credit Agreement among KCS Medallion Resources, Inc., KCS Energy, Inc., KCS Energy Services, Inc., Medallion Gas Services, Inc., and GED Energy Services, Inc. and Canadian Imperial Bank of Commerce, New York Agency, as Agent, CIBC Inc., as Collateral Agent, NationsBank of Texas, N.A. as Co-Agent dated January 2, 1997. (21) Subsidiaries of the Registrant - filed herewith . (23) i Consent of Arthur Andersen LLP - filed herewith. ii Consent of Netherland, Sewell and Associates, Inc. - filed herewith. - ---------- * Management contract or compensatory plan or arrangement required to be filed as an exhibit. 47 EX-21 2 SUBSIDIARIES 1 Exhibit 21 KCS ENERGY, INC. LIST OF WHOLLY-OWNED SUBSIDIARIES KCS Resources, Inc. National Enerdrill Corporation Proliq, Inc. KCS Energy Marketing, Inc. KCS Michigan Resources, Inc. KCS Energy Services, Inc. KCS Medallion Resources, Inc. Medallion California Properties, Inc. Medallion Gas Services Company 48 EX-23.I 3 CONSENT OF ARTHUR ANDERSEN LLP 1 Exhibit 23(i) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation of our report included in this Form 10-K, into KCS Energy, Inc.'s previously filed Registration Statement File Nos. 33-25707, 33-28899, 33-45923 and 33-63982. Arthur Andersen LLP New York, New York April 13, 1998 49 EX-23.II 4 CONSENT OF NETHERLAND, SEWELL AND ASSOCIATES, INC. 1 Exhibit 23(ii) CONSENT OF INDEPENDENT PETROLEUM ENGINEER We hereby consent to the references to our firm and to our audit letter dated March 13, 1998, of the estimates of the proved reserves of KCS Energy, Inc. in the KCS Medallion Resources, Inc.; KCS Mountain Resources, Inc.; KCS Resources, Inc.; and KCS Michigan Resources, Inc. properties, as of January 1, 1998 in the Annual Report Form 10-K of KCS Energy, Inc. for the year ended December 31, 1997. Netherland, Sewell and Associates, Inc. Houston, Texas March 30, 1998 50 EX-27 5 FINANCIAL DATA SCHEDULE
5 YEAR DEC-31-1997 JAN-01-1997 DEC-31-1997 4,802 0 40,115 0 2,241 51,669 786,618 360,285 502,414 64,024 0 0 0 312 144,758 502,414 143,689 0 0 0 271,722 0 21,883 (149,440) (52,055) (97,385) 5,302 0 0 (92,083) (3.19) (3.19)
-----END PRIVACY-ENHANCED MESSAGE-----