-----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, UCFEp4RewtbnkNMg+QIIcaPAghSqMzlSRPdTJKqOjZ9WwJW/W8+GYFBPGeIAbjge ofEuJd6/RUi/98K8H1bwUg== 0000950129-98-000163.txt : 19980116 0000950129-98-000163.hdr.sgml : 19980116 ACCESSION NUMBER: 0000950129-98-000163 CONFORMED SUBMISSION TYPE: 424B4 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19980115 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: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479 FILM NUMBER: 98507887 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 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KCS RESOURCE INC CENTRAL INDEX KEY: 0001050188 STANDARD INDUSTRIAL CLASSIFICATION: [] STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-01 FILM NUMBER: 98507888 BUSINESS ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KCS MICHIGAN RESOURCES CENTRAL INDEX KEY: 0001050189 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 760482274 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-02 FILM NUMBER: 98507889 BUSINESS ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KCS ENERGY MARKETING INC CENTRAL INDEX KEY: 0001050190 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 222267499 STATE OF INCORPORATION: NJ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-04 FILM NUMBER: 98507890 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENERCORP GAS MARKETING INC CENTRAL INDEX KEY: 0001050192 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 760420837 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-05 FILM NUMBER: 98507891 BUSINESS ADDRESS: STREET 1: 0 STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KCS PIPELINE SYSTEMS INC CENTRAL INDEX KEY: 0001050193 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 760516389 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-06 FILM NUMBER: 98507892 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KCS ENERGY SERVICES INC CENTRAL INDEX KEY: 0001050196 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 760516389 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-07 FILM NUMBER: 98507893 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NATIONAL ENERDRILL CORP CENTRAL INDEX KEY: 0001050197 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 229196560 STATE OF INCORPORATION: NJ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-08 FILM NUMBER: 98507894 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PROLIQ INC CENTRAL INDEX KEY: 0001050198 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 221516527 STATE OF INCORPORATION: NJ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-09 FILM NUMBER: 98507895 BUSINESS ADDRESS: STREET 1: 0 STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MEDALLION CALIFORNIA PROPERTIES CO CENTRAL INDEX KEY: 0001050200 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 760267470 STATE OF INCORPORATION: NJ FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-10 FILM NUMBER: 98507896 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MEDALLION GAS SERVICES INC CENTRAL INDEX KEY: 0001050201 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 731385098 STATE OF INCORPORATION: OK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-11 FILM NUMBER: 98507897 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 FILER: COMPANY DATA: COMPANY CONFORMED NAME: KCS MEDALLION RESOURCES INC CENTRAL INDEX KEY: 0001050202 STANDARD INDUSTRIAL CLASSIFICATION: [] IRS NUMBER: 760482274 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: SEC FILE NUMBER: 333-40479-03 FILM NUMBER: 98507898 BUSINESS ADDRESS: STREET 1: 379 THORNALL ST STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 BUSINESS PHONE: 7326321770 MAIL ADDRESS: STREET 1: 379 THORNALL STREET STREET 2: 379 THORNALL STREET CITY: EDISON STATE: NJ ZIP: 08837 424B4 1 KCS ENERGY, INC. - FILE #333-40479 1 Filed pursuant to Rule 424(b)(4) Registration No. 333-40479 PROSPECTUS $125,000,000 KCS ENERGY, INC. [KCS ENERGY, INC. LOGO] 8 7/8% SENIOR SUBORDINATED NOTES DUE 2008 ------------------ The 8 7/8% Senior Subordinated Notes due 2008 (the "Notes") are being offered (the "Offering") by KCS Energy, Inc. (the "Company"). The Notes will mature on January 15, 2008 and will bear interest at a rate of 8 7/8% per annum, payable semi-annually on January 15 and July 15 of each year, commencing July 15, 1998. The Notes will not be redeemable by the Company prior to January 15, 2003. Thereafter, the Notes will be redeemable at the option of the Company, in whole or in part, at the redemption prices set forth in this Prospectus, together with accrued interest. In the event the Company consummates a Public Equity Offering (as defined) on or prior to January 15, 2001, the Company may at its option use all or a portion of the proceeds from such offering to redeem up to 33 1/3% of the aggregate principal amount of the Notes originally issued at a redemption price equal to 108.875% of the aggregate principal amount thereof, together with accrued interest, provided that at least 66 2/3% of the aggregate principal amount of Notes originally issued remains outstanding immediately after such redemption. In addition, upon a Change of Control (as defined herein), each holder of Notes shall have the right, at the holder's option, to require the Company to repurchase such holder's Notes at a purchase price equal to 101% of the principal amount thereof, together with accrued interest. See "Description of the Notes -- Redemption." The Notes will be unsecured obligations of the Company and will be subordinate to all present and future Senior Indebtedness (as defined herein) of the Company and senior to all future Subordinated Indebtedness (as defined herein) of the Company. See "Description of the Notes -- Subordination." Each of the Company's current and certain of its future subsidiaries will unconditionally guarantee, jointly and severally, the Company's obligations under the Notes on a senior subordinated basis. See "Description of the Notes -- Subsidiary Guarantees of Notes." The Notes have been approved for listing on the New York Stock Exchange, subject to official notice of issuance, under the symbol "KCS08." ------------------ SEE "RISK FACTORS" BEGINNING ON PAGE 10 HEREIN FOR CERTAIN INFORMATION THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS. ------------------ THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
=================================================================================================================== PRICE TO DISCOUNTS AND PROCEEDS TO PUBLIC(1) COMMISSIONS(2) COMPANY(3) - ------------------------------------------------------------------------------------------------------------------- Per Note...................................... 100% 2.625% 97.375% - ------------------------------------------------------------------------------------------------------------------- Total......................................... $125,000,000 $3,281,250 $121,718,750 ===================================================================================================================
(1) Plus accrued interest, if any, from the date of initial issuance. (2) The Company has agreed to indemnify the several Underwriters against certain liabilities, including liabilities under the Securities Act of 1933. See "Underwriting." (3) Before deducting expenses payable by the Company estimated at $725,000. ------------------ The Notes are being offered by the several Underwriters named herein, subject to prior sale, when, as and if accepted by them and subject to certain conditions. It is expected that delivery of the Notes in book-entry form will be made through the facilities of The Depository Trust Company on or about January 21, 1998. --------------------- SALOMON SMITH BARNEY PRUDENTIAL SECURITIES INCORPORATED CIBC OPPENHEIMER JEFFERIES AND COMPANY, INC. MORGAN KEEGAN & COMPANY, INC. January 15, 1998 2 CERTAIN PERSONS PARTICIPATING IN THE OFFERING MAY ENGAGE IN TRANSACTIONS THAT STABILIZE, MAINTAIN, OR OTHERWISE AFFECT THE MARKET PRICE OF THE NOTES. SPECIFICALLY, THE UNDERWRITERS MAY BID FOR, AND PURCHASE, THE NOTES IN THE OPEN MARKET AND MAY IMPOSE PENALTY BIDS. FOR A DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING." 3 PROSPECTUS SUMMARY The following summary is qualified in its entirety by the more detailed information and financial statements (including the notes thereto) included elsewhere in this Prospectus and in the documents incorporated herein by reference. Investors should carefully consider the statements set forth under "Risk Factors." Unless the context otherwise requires, "Company" and "KCS" refer to KCS Energy, Inc. and its consolidated subsidiaries. Except as otherwise specified, all data set forth in this Prospectus has been adjusted to reflect a two-for-one stock split that the Company completed on June 30, 1997. See "Glossary" for definitions of certain terms used herein. This Prospectus contains forward-looking statements that involve risks and uncertainties. The Company's actual results may differ significantly from the results discussed in the forward-looking statements. See "Special Note on Forward-Looking Statements." Factors that might cause such differences include, but are not limited to, those discussed in "Risk Factors." THE COMPANY GENERAL KCS is an independent oil and gas company engaged in the acquisition, exploration, development and production of oil and gas. Through its experienced management and technical staff, the Company has grown significantly and created a geographically diversified reserve base by implementing a balanced program of development drilling, reserve acquisitions and exploration drilling. The Company concentrates its activities in areas where it has accumulated geological knowledge and technical expertise and where it can retain significant operating control. As a result of these efforts, KCS has compiled a multi-year inventory of over 600 potential drilling and recompletion locations, including a significant number of sites in the Manderson Field in the Big Horn Basin in Wyoming where the Company believes it has the potential to significantly increase its reserves. Additionally, the Company augments its working interest ownership of properties with a volumetric production payment ("VPP") program to acquire priority rights to a portion of the oil and gas from other parties' producing properties. The Company plans to spend $183 million on capital expenditures in 1998, of which $95 million is for development drilling, $30 million is for exploration, $45 million is for the VPP program, $10 million is for working interest acquisitions and $3 million is for other expenditures. The Company currently plans to drill approximately 175 development wells and to participate in approximately 60 exploratory prospects during 1998. The Company's operations are primarily focused in the Rocky Mountain, Gulf Coast, and Mid-Continent/West Texas regions, and through its VPP program primarily in the Gulf of Mexico and Michigan. As of December 31, 1996, the Company had estimated proved reserves of 355.8 Bcfe with an estimated pre-tax present value of future net revenues ("PV-10") of $557.6 million. These estimated reserves were 75% natural gas and 87% proved developed, and approximately 10% were attributable to the Company's VPP program. The Company operates properties comprising approximately 72% of its reserves (excluding VPP reserves) at December 31, 1996. A significant focus of the Company's future development is in the Manderson Field in the Big Horn Basin in Wyoming. Since it acquired the field in November 1995, the Company has increased its acreage position from 7,500 to over 61,000 gross acres, and has undertaken an extensive exploration and development drilling program. Through September 30, 1997, the Company had drilled 54 wells, investing $35 million, and had spent $15.3 million to install infrastructure in the field. Most of these wells are currently shut-in or awaiting completion, remediation or stimulation because of delays in construction of a sour gas treatment plant and associated gas injection system. Operations at the plant and injection system commenced on December 3, 1997. Based on drilling and production results and accumulation of additional seismic data, the Company believes that there are seven productive formations located in the greater Manderson Field and that they have significant reserve potential. The Company plans to spend $12 million in the fourth quarter of 1997 to complete a sour gas treatment plant in the Manderson Field, bring the shut-in wells on production and drill 3 4 17 additional wells. In 1998, the Company plans to spend approximately $40 to $50 million to drill and complete as many as 70 to 100 wells in this field. The Company has successfully increased its reserves through opportunistic acquisitions. In May 1997, KCS completed an acquisition of properties in the Langham Creek Field near Houston, Texas for $17 million (the "Langham Creek Acquisition"), which enabled it to assume operatorship and increase its average working interest in the area to approximately 61%. In December 1996, the Company completed a major acquisition of oil and gas properties, principally in the Mid-Continent region, for an aggregate purchase price of $199 million (the "Medallion Acquisition"). As a result of the Medallion Acquisition, the Company more than doubled its reserve base and production rate and significantly expanded its presence in the Mid-Continent region. In November 1995, the Company completed an acquisition in the Rocky Mountain region for $33 million (the "Rocky Mountain Acquisition"), which resulted in numerous exploration and development opportunities, including the Manderson Field. Through its VPP program, the Company is able to add reserves at very attractive rates of return and increase its exposure to acquisition, development and exploration opportunities. In the three years ended September 30, 1997, the Company invested $124 million in 25 separate VPP transactions, acquiring 71.8 Bcf of natural gas and 1.5 MMbbls of oil. BUSINESS STRATEGY KCS intends to continue to broaden its reserve base and increase production and cash flow through a balanced program of development drilling, reserve acquisitions and exploration drilling. The Company extensively utilizes advanced technology, most notably 3-D seismic, computer-enhanced basin analysis, and reservoir simulation and stimulation techniques, to better delineate and produce reserves. The key components of the Company's business strategy include: (i) exploiting and developing its multi-year inventory of development drilling locations, (ii) capitalizing on the development potential of the Manderson Field, (iii) acquiring properties with growth potential, (iv) controlling its major properties, (v) continuing to expand its VPP program and (vi) pursuing a balanced exploration program that includes high-potential opportunities. KEY STRENGTHS To implement its business strategy, the Company intends to take advantage of several key strengths, including the following: Proven Growth Record. The Company has achieved substantial growth in reserves, production and EBITDA since 1992. KCS's estimated proved reserves have increased at a compound annual growth rate of 57%, from 60.0 Bcfe as of December 31, 1992 to 355.8 Bcfe as of December 31, 1996. Over this period, production has increased at a compound annual growth rate of 61%, from 4.4 Bcfe in 1992 to 30.1 Bcfe in 1996. Similarly, the Company's EBITDA has increased at a compound annual growth rate of 81%, from $8.3 million for the year ended December 31, 1992 to $88.9 million for the year ended December 31, 1996. For the nine months ended September 30, 1997, the Company had oil and gas production of 41.2 Bcfe and EBITDA of $72.0 million, compared to 22.2 Bcfe and $65.8 million for the same period in 1996. Innovative and Creative Approach to Expansion. The Company has demonstrated the ability to identify and acquire oil and gas reserves in a disciplined, creative manner and believes it has become one of the leaders in the acquisition of oil and gas reserves through VPP transactions. Large Multi-year Inventory of Drilling Opportunities. The Company has identified more than 600 potential drilling and recompletion locations, representing a three to four-year inventory. In addition, the Company believes that there are significant exploratory opportunities in the acreage it has assembled, including more than 265,000 gross undeveloped acres, in the onshore Gulf Coast regions of Texas and Louisiana and in the Rocky Mountain and Mid-Continent regions. Geographically Diversified Property Base. The Company operates in three distinct regions: the Rocky Mountains, the Gulf Coast and the Mid-Continent/West Texas regions. As a result, it benefits from diversification with respect to risks associated with focusing on any one geographical region. 4 5 Successful Drilling Program. During the three-year period ended December 31, 1996, the Company participated in the drilling of 118 development wells and 70 exploratory wells with a 93% and 46% completion rate. During the first nine months of 1997, the Company participated in the drilling of 71 development wells, 86% of which were completed and 23 exploratory wells, 43% of which were completed. Over the five-year period ended December 31, 1996, the Company replaced approximately 114% of its production through drilling. High Operating Margins. The Company's drilling success and emphasis on an efficient administrative and operating structure have enabled the Company to generate high cash margins that the Company believes compare favorably with its peer companies. Control of Major Properties. The Company seeks to operate and own a majority working interest in its major properties, which gives it greater control over the timing and nature of future development as well as over operating costs and the marketing of production. The Company operates properties comprising approximately 72% of its reserves (excluding VPP reserves) at December 31, 1996. Experienced, Motivated Management Team with a Significant Equity Stake. The Company's senior management has extensive experience in the oil and gas industry and is motivated to increase stockholder value. The Company's compensation system is strongly geared to "pay for performance" with incentives directly tied to operating and financial goals and objectives. Members of the Company's management and directors currently own approximately 14% of the Company's common stock, and the Company has established minimum direct ownership requirements for all officers and directors. 5 6 THE OFFERING SECURITIES OFFERED............ $125,000,000 principal amount of 8 7/8% Senior Subordinated Notes due 2008. MATURITY...................... January 15, 2008. PAYMENT OF INTEREST........... January 15 and July 15, commencing July 15, 1998. OPTIONAL REDEMPTION........... The Notes will be redeemable in whole or in part, at the option of the Company, at the redemption prices set forth herein, together with accrued interest, except that no redemption may be made prior to January 15, 2003. In the event the Company consummates a Public Equity Offering (as defined) on or prior to January 15, 2001, the Company may at its option use all or a portion of the proceeds from such offering to redeem up to 33 1/3% of the aggregate principal amount of the Notes originally issued at a redemption price equal to 108.875% of the aggregate principal amount thereof, together with accrued interest, provided that at least 66 2/3% of the aggregate principal amount of Notes originally issued remains outstanding immediately after such redemption. GUARANTEES.................... The Notes will be unconditionally guaranteed on a senior subordinated basis by each of the Company's current and certain of the Company's future subsidiaries, and such Subsidiary Guarantees (as defined) will be subordinate in right of payment to all existing and future Senior Indebtedness of the Subsidiary Guarantors (as defined) and senior to all future Subordinated Indebtedness of the Subsidiary Guarantors. RANKING....................... The Notes will be unsecured senior subordinated obligations of the Company and will be subordinate in right of payment to all existing and future Senior Indebtedness of the Company and senior to all future Subordinated Indebtedness of the Company. CHANGE OF CONTROL............. In the event that there shall occur a Change of Control (as defined), each holder of the Notes shall have the right, at the holder's option, to require the Company to repurchase such holder's Notes at 101% of their principal amount, plus accrued interest. The term Change in Control does not include other events that might adversely affect the financial condition of the Company or result in a downgrade in the credit rating (if any) of the Notes. The Company's ability to repurchase the Notes following a Change of Control is dependent upon the Company having sufficient funds and may be limited by the terms of the Company's Senior Indebtedness or the subordination provisions of the Indenture. There is no assurance that the Company will be able to repurchase the Notes upon the occurrence of a Change of Control. CERTAIN COVENANTS............. The Indenture relating to the Notes will contain certain covenants, including covenants which limit: (i) indebtedness; (ii) restricted payments; (iii) issuances and sales of capital stock of restricted subsidiaries; (iv) transactions with affiliates; (v) other senior subordinated indebtedness; (vi) liens; (vii) asset sales; (viii) dividends and other payment restrictions affecting restricted subsidiaries; (ix) conduct of business; and (x) mergers, consolida- 6 7 tions and sales of assets. See "Description of the Notes -- Certain Covenants" and "-- Merger, Consolidation and Sale of Assets." USE OF PROCEEDS............... The net proceeds to the Company from the sale of the Notes will be used to fund the Company's capital expenditure program and for working capital and other general corporate purposes. The proceeds will initially be used to repay existing indebtedness under the Company's Bank Credit Facilities (as defined). LISTING....................... The Notes have been approved for listing on the New York Stock Exchange ("NYSE"), subject to official notice of issuance. 7 8 SUMMARY HISTORICAL FINANCIAL DATA (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA) The following table sets forth selected historical financial information of the Company and should be read in conjunction with the Consolidated Financial Statements (including the notes thereto) of KCS Energy, Inc. and the information under the caption "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this Prospectus. The historical data for the years ended December 31, 1994, 1995 and 1996 and for the nine months ended September 30, 1996 (i) includes revenues attributable to an above-market, take-or-pay contract with Tennessee Gas Pipeline Company (the "Tennessee Gas Contract") which was terminated effective January 1, 1997 and (ii) has been restated to reflect the discontinuation of the Company's natural gas transportation and marketing operations in 1997.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, --------------------------------- --------------------- 1994 1995 1996 1996 1997 ------- -------- -------- -------- -------- (UNAUDITED) INCOME STATEMENT DATA: Revenue: Oil and gas revenue(1)..................................... $66,215 $ 86,629 $108,015 $ 79,051 $100,396 Other revenue, net......................................... 1,185 486 359 377 3,702 ------- -------- -------- -------- -------- Total................................................ 67,400 87,115 108,374 79,428 104,098 Operating costs and expenses: Lease operating expenses................................... 6,218 6,156 9,167 6,582 20,470 Production taxes........................................... 845 467 2,526 1,671 4,354 General and administrative expenses........................ 4,853 4,704 7,825 5,411 7,302 Depreciation, depletion and amortization................... 18,783 38,231 45,460 33,128 42,486 ------- -------- -------- -------- -------- Total................................................ 30,699 49,558 64,978 46,792 74,612 ------- -------- -------- -------- -------- Operating income............................................ 36,701 37,557 43,396 32,636 29,486 Interest and other income, net.............................. 1,175 4,472 5,086 4,820 388 Interest expense............................................ (2,004) (6,807) (14,085) (11,193) (15,146) ------- -------- -------- -------- -------- Income from continuing operations before income taxes....... 35,872 35,222 34,397 26,263 14,728 Federal and state income taxes.............................. 12,269 11,817 12,680 9,483 5,452 ------- -------- -------- -------- -------- Income from continuing operations........................... 23,603 23,405 21,717 16,780 9,276 Discontinued operations: Net income (loss) from operations........................ 554 (2,099) (1,845) (1,974) (72) Net gain on disposition.................................. -- -- -- -- 5,461 ------- -------- -------- -------- -------- Net income.................................................. $24,157 $ 21,306 $ 19,872 $ 14,806 $ 14,665 ======= ======== ======== ======== ======== Earnings per share: Continuing operations.................................... $ 1.00 $ 1.00 $ 0.91 $ 0.70 $ 0.32 Discontinued operations.................................. 0.02 (0.09) (0.08) (0.08) 0.18 ------- -------- -------- -------- -------- Total................................................ $ 1.02 $ 0.91 $ 0.83 $ 0.62 $ 0.50 ======= ======== ======== ======== ======== Average common shares outstanding........................... 23,610 23,521 23,811 23,773 29,449 Dividends per common share.................................. $ 0.045 $ 0.060 $ 0.060 $ 0.045 $ 0.050 OTHER DATA (UNAUDITED): Tennessee Gas Contract premium(2)........................... $42,828 $ 52,007 $ 32,829 $ 25,689 $ -- EBITDA(3)................................................... 55,484 75,788 88,856 65,764 71,972 Capital expenditures........................................ 74,953 128,699 277,218 52,735 171,884 Ratio of earnings to fixed charges(4)....................... 17.7x 6.1x 3.4x 3.3x 2.0x Ratio of EBITDA to interest expense......................... 27.7x 11.1x 6.3x 5.9x 4.8x
SEPTEMBER 30, 1997 -------------------------- ACTUAL AS ADJUSTED(5) -------- -------------- (UNAUDITED) BALANCE SHEET DATA: Cash and cash equivalents................................... $ 3,858 $ 3,858 Working capital............................................. 7,707 7,707 Oil and gas properties, net................................. 540,896 540,896 Total assets................................................ 614,043 618,049 Long-term debt.............................................. 275,723 279,729 Total stockholders' equity.................................. 251,990 251,990
- --------------- (1) Includes revenues attributable to the Tennessee Gas Contract, for the years ended December 31, 1994, 1995 and 1996 and for the nine months ended September 30, 1996, that was terminated effective January 1, 1997. (2) Reflects revenues associated with the natural gas production covered by the above-market prices provided for in the Tennessee Gas Contract in excess of the revenues that would otherwise have been received for such production at spot market prices. (3) EBITDA represents income before depletion, depreciation, amortization, interest expense, interest and other income and income taxes. EBITDA is a financial measure commonly used in the Company's industry and should not be considered in isolation or as a substitute for net income, cash flow provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. (4) For purposes of calculating the ratio of earnings to fixed charges, fixed charges include interest expense and that portion of non-capitalized rental expense deemed to be the equivalent of interest. Earnings represents income before income taxes from continuing operations before fixed charges. (5) As adjusted to give effect to the sale by the Company of the Notes offered hereby and the application of the estimated net proceeds as described under "Use of Proceeds." 8 9 SUMMARY HISTORICAL OIL AND GAS RESERVE AND OPERATING DATA The following table sets forth summary information with respect to estimates of the Company's proved oil and gas reserves at the end of the periods indicated. Summary reserve information as of December 31, 1996 includes reserves attributable to the Medallion Acquisition. For additional information relating to the Company's oil and gas reserves and operating data, see "Business and Properties," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the notes to the Consolidated Financial Statements included elsewhere in this Prospectus.
DECEMBER 31, ---------------------------------- 1994 1995 1996 -------- ------------ -------- RESERVE DATA: Proved developed reserves: Oil (Mbbls)............................................... 1,336 3,808 12,133 Natural gas (MMcf)........................................ 74,215 121,987 236,454 Total (MMcfe)........................................... 82,231 144,835 309,252 Proved undeveloped reserves: Oil (Mbbls)............................................... 983 3,709 2,498 Natural gas (MMcf)........................................ 14,969 18,976 31,571 Total (MMcfe)........................................... 20,867 41,230 46,561 Total proved reserves: Oil (Mbbls)............................................... 2,319 7,517 14,631 Natural gas (MMcf)........................................ 89,184 140,963 268,025 Total (MMcfe)........................................... 103,098 186,065 355,813 Estimated future net revenue before income taxes ($000)(1)(2).............................................. $307,533 $405,049 $849,265 Present value of estimated future net revenues before income taxes ($000)(2)(3)(4)..................................... $241,705 $291,085 $557,612 Standardized measure of discounted future net cash flows ($000)(2)(3)(5)........................................... $179,660 $231,763 $437,599 Reserve replacement percentage.............................. 242.3% 527.2% 703.8% Reserve life (in years)..................................... 8.2 9.2 11.8
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, --------------------------- ----------------- 1994 1995 1996 1996 1997 ------- ------- ------- ------- ------- NET PRODUCTION DATA: Oil (Mbbls)................................................. 211 196 758 547 1,295 Liquids..................................................... -- -- -- -- 101 Natural gas (MMcf): Tennessee Gas Contract.................................... 6,851 6,924 4,645 3,576 -- Other..................................................... 4,453 12,205 20,936 15,346 32,806 ------- ------- ------- ------- ------- Total................................................... 11,304 19,129 25,581 18,922 32,806 Total (MMcfe)............................................... 12,570 20,305 30,129 22,204 41,180 OTHER DATA: Average prices: Oil (per bbl)............................................. $ 15.16 $ 17.28 $ 20.69 $ 19.72 $ 18.92 Liquids (per bbl)......................................... -- -- -- -- 11.05 Natural gas (per Mcf): Tennessee Gas Contract.................................. 7.49 7.90 8.40 8.38 -- Other................................................... 1.81 1.62 2.35 2.29 2.28 Average................................................. 5.54 4.29 3.61 3.61 2.28 Average equivalent price (per Mcfe)......................... $ 5.27 $ 4.27 $ 3.59 $ 3.56 $ 2.44 Lifting cost (per Mcfe)(6).................................. 0.56 0.33 0.39 0.37 0.60 General and administrative expense (per Mcfe)............... 0.39 0.23 0.26 0.25 0.18 ------- ------- ------- ------- ------- Cash margin (per Mcfe)...................................... $ 4.32 $ 3.71 $ 2.94 $ 2.94 $ 1.66 ======= ======= ======= ======= =======
- --------------- (1) Reflects estimated future cash inflows less future production and development costs. (2) Estimates at December 31, 1994 and 1995 reflect the contract price for natural gas to be delivered from the Bob West Field under the Tennessee Gas Contract until January 1999. In December 1996, the contract was terminated by agreement of the parties effective January 1, 1997. (3) Other than gas and oil sold under contractual arrangements including swaps, futures contracts and options, reflects average realized gas prices of $1.50, $2.03 and $3.54 per Mcf and average realized oil prices of $16.99, $18.23 and $22.45 per bbl in effect at December 31, 1994, 1995 and 1996, respectively. (4) Reflects estimated future net revenue before income taxes discounted at 10% per annum. (5) Reflects estimated future net revenue less future income taxes discounted at 10% per annum. (6) Includes lease operating expenses and production taxes. 9 10 RISK FACTORS In addition to the other information set forth in this Prospectus, prospective purchasers of the Notes should carefully consider the following risk factors in evaluating an investment in the Notes. This Prospectus contains forward-looking statements which involve certain assumptions, risks and uncertainties. The Company's actual results could differ materially from those anticipated in these forward-looking statements as a result of certain factors, including those set forth in the following risk factors and elsewhere in this Prospectus. See "Special Note on Forward-Looking Statements." VOLATILE NATURE OF OIL AND GAS MARKETS; FLUCTUATIONS IN PRICES The Company's future financial condition and results of operations are highly dependent on the demand and prices received for the Company's oil and gas production and on the costs of acquiring, developing and producing reserves. Oil and gas prices have historically been volatile and are expected by the Company to continue to be volatile in the future. Prices for oil and gas are subject to wide fluctuation in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond the Company's control. These factors include political conditions in the Middle East and elsewhere, domestic and foreign supply of oil and gas, the level of consumer demand, weather conditions, domestic and foreign government regulations and taxes, the price and availability of alternative fuels and overall economic conditions. From time to time, oil and gas prices have been depressed by excess domestic and imported supplies. There can be no assurance that current price levels will be sustained, and it is impossible to predict future oil and gas price movements with any certainty. A decline in oil or gas prices may adversely affect the Company's cash flow, liquidity and profitability. Lower oil or gas prices also may reduce the amount of the Company's oil and gas that can be produced economically. Additionally, substantially all of the Company's sales of oil and gas are made in the spot market and not pursuant to long-term fixed price contracts. With the objective of reducing price risk, the Company may from time to time enter into hedging transactions with respect to a portion of its expected future production. See "-- Risks of Hedging Transactions." There can be no assurance that such hedging transactions will reduce risk or mitigate the effect of any substantial or extended decline in oil or gas prices. Any substantial or extended decline in the prices of oil or gas would have a material adverse effect on the Company's financial condition and results of operations. DEPENDENCE ON ACQUIRING AND FINDING ADDITIONAL RESERVES The Company's prospects for future growth and profitability will depend predominately on its ability to replace present reserves through acquisitions and development and exploratory drilling. The decision to acquire a business or to purchase, explore or develop an interest in a property will depend in part on the evaluation of data obtained through geophysical and geological analyses and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Acquisitions may not be available at attractive prices, and there can be no assurance that the Company's acquisition and exploration activities or planned development projects will result in significant additional reserves or that the Company will have continuing success at drilling economically productive wells. Without successfully acquiring or developing additional reserves, the Company's proved reserves and revenues will decline. SUBSTANTIAL CAPITAL REQUIREMENTS The Company has made, and likely will continue to make, substantial capital expenditures in connection with the acquisition, development and exploration of oil and gas properties. Historically, the Company has funded its capital expenditures with cash flow from operations and funds from long-term debt financing, including bank financing secured by its oil and gas assets (including the Credit Facility and the Revolving Credit Agreement, as defined herein, the "Bank Credit Facilities"). The Company anticipates that the net proceeds from the sale of the Notes, together with its cash flow from operations, net proceeds from the sale of non-strategic assets and the availability of credit under the Bank Credit Facilities, will be sufficient to fund the approximately $183 million of capital expenditures currently budgeted for drilling and acquisition activities in 1998. Future cash flows and the availability of financing are subject to a number of variables, such as the level of production from existing wells, prices of oil and gas and the Company's success in locating and producing 10 11 new reserves. If revenues were to decrease as a result of lower oil and gas prices, decreased production or otherwise, and the Company had no availability under the Bank Credit Facilities, the Company could be limited in its ability to replace its reserves or to maintain production at current levels, resulting in a decrease in production and revenue over time. If the Company's cash flow from operations and availability under the Bank Credit Facilities are not sufficient to satisfy its capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these requirements. UNCERTAINTY OF ESTIMATES OF OIL AND GAS RESERVES AND FUTURE NET CASH FLOWS There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves, including many factors beyond the Company's control. This Prospectus includes independent engineering estimates of the Company's oil and gas reserves and future net cash flows. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and of future net cash flow necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effects of regulation by governmental agencies and assumptions concerning future oil and gas prices, operating costs, severance and excise taxes, development costs and workover and remedial costs, all of which may in fact vary considerably from actual results. For these reasons, estimates of the economically recoverable quantities of oil and gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different times may vary significantly. Actual production, revenues and expenditures with respect to the Company's reserves likely will vary from estimates, and such variances may be material. The Company's properties may also be susceptible to hydrocarbon drainage from production by other operators of adjacent properties. In addition, the Company's reserves and future cash flows may be subject to revisions, based upon production history, results of future development, oil and gas prices, performance of counterparties under agreements to which the Company is a party, operating and development costs and other factors. See "Business and Properties -- Oil and Gas Reserves." Approximately 13% of the Company's total proved reserves as of December 31, 1996 were undeveloped, which are by their nature less certain. Recovery of such reserves will require substantial capital expenditures by the Company and the successful completion of drilling operations. The Company's reserve data assume that substantial capital expenditures by the Company will be required to develop such reserves. Although cost and reserve estimates attributable to the Company's reserves have been prepared in accordance with industry standards, no assurance can be given that the estimated costs are accurate, that development will occur as scheduled or that the results will be as estimated. See "Business and Properties -- Oil and Gas Reserves." PV-10 values referred to in this Prospectus should not be construed as the current market value of the estimated oil and gas reserves attributable to the Company's properties. In accordance with applicable requirements of the Securities and Exchange Commission (the "SEC"), PV-10 is generally based on prices and costs as of the date of the estimate, whereas actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for oil and gas, curtailments or increases in consumption by natural gas purchasers and changes in governmental regulations or taxation. The timing of actual future net cash flows from proved reserves, and thus their actual present value, will be affected by the timing of both the production and the incurrence of expenses in connection with development and production of oil and gas properties. In addition, the 10% discount factor, which is required by the SEC to be used to calculate PV-10 for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company and its properties or the oil and gas industry in general. The Company provides for depreciation, depletion and amortization ("DD&A") using the future gross revenue method based on recoverable reserves valued at current prices. See Note 1 to Consolidated Financial Statements -- "Property, Plant and Equipment" for a description of how the Company provides for DD&A and the related limitation on capitalized oil and gas property costs. Significant declines in oil and gas prices, 11 12 like those experienced in early 1997, if not offset by increases in proved oil and gas reserves, could result in a substantial increase in non-cash DD&A accruals and could negatively impact earnings. SUBSTANTIAL INDEBTEDNESS AND RESTRICTIONS At September 30, 1997, the Company had outstanding $150 million in 11% Senior Notes due 2003 (the "Senior Notes") issued pursuant to an indenture governing the Senior Notes (the "Senior Notes Indenture") and approximately $126.2 million of outstanding indebtedness under the Bank Credit Facilities (which amount has increased since such date). See "Use of Proceeds" and "Capitalization." Giving effect to the Offering and the application of the net proceeds to repay amounts owed under the Bank Credit Facilities, the Company expects to have approximately $145 million available for borrowing under the Bank Credit Facilities immediately after the sale of the Notes offered hereby. The Company's level of indebtedness will have several important effects on its future operations. A significant portion of the Company's cash flow from operations must be dedicated to the payment of interest on its indebtedness and will not be available for other purposes. The covenants contained in the Bank Credit Facilities and the Senior Notes Indenture require the Company to meet certain financial tests. Other restrictions will also limit the Company's ability to borrow additional funds and may affect its flexibility in planning for and reacting to changes in its business, including possible acquisition activities. The Company's ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes or other purposes may also be restricted. There can be no assurance that the Company will be able to remain in compliance with the financial ratios prescribed under the Bank Credit Facilities or the Senior Notes Indenture. Failure to do so would result in a default and could lead to the acceleration of the Company's indebtedness under the Bank Credit Facilities, the Senior Notes Indenture and the Indenture. Moreover, if the Company's revenues were to decrease as a result of lower oil and gas prices, decreased production or otherwise, the borrowing base under the Bank Credit Facilities could be reduced and could restrict the Company's future growth. SUBORDINATION OF NOTES The Notes will be subordinate in right of payment to all current and future Senior Indebtedness of the Company, including the Bank Credit Facilities and the Senior Notes. Senior Indebtedness will include all indebtedness of the Company, whether existing on or created or incurred after the issuance of the Notes, that is not made subordinate to or pari passu with the Notes by the instrument creating the indebtedness. At September 30, 1997, the aggregate amount of the Company's Senior Indebtedness was approximately $276.2 million. By reason of the subordination of the Notes, in the event of insolvency, bankruptcy, liquidation, reorganization, or similar proceeding in relation to the Company or upon default in payment with respect to certain Senior Indebtedness of the Company or an event of default with respect to such indebtedness permitting the acceleration thereof, the assets of the Company will be available to pay the amounts due on the Notes only after all or certain of the Senior Indebtedness of the Company has been paid in full. There can be no assurance that the assets of the Company will be sufficient for that purpose at the time such payment is due. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources" and "Description of the Notes -- Subordination." RISKS RELATING TO ENFORCEABILITY OF SUBSIDIARY GUARANTEES The Company's payment obligations under the Notes will be jointly and severally guaranteed by all of its current and certain future subsidiaries. To the extent that a court were to find that (i) a guarantee was incurred by a subsidiary guarantor with the intent to hinder, delay or defraud any present or future creditor, (ii) the subsidiary guarantor contemplated insolvency with a design to prefer one or more creditors to the exclusion in whole or in part of others or (iii) such subsidiary guarantor did not receive fair consideration or reasonably equivalent value for issuing its guarantee and such subsidiary guarantor (w) was insolvent, (x) was rendered insolvent by reason of the issuance of such guarantee, (y) was engaged or about to engage in a business or transaction for which the remaining assets of such subsidiary guarantor constituted unreasonably small capital to carry on its business or (z) intended to incur, or believed that it would incur, debts beyond its 12 13 ability to pay such debts as they matured, the court, subject to applicable statutes of limitations, could avoid or subordinate such guarantee in favor of a subsidiary guarantor's creditors or take other action detrimental to the holders of the Notes. Among other things, a legal challenge of a guarantee on fraudulent conveyance grounds may focus on the benefits, if any, realized by a subsidiary guarantor as a result of the issuance by the Company of the Notes. To the extent any guarantees were avoided as a fraudulent conveyance or held unenforceable for any other reason, holders of the Notes would cease to have any claim in respect of such subsidiary guarantor and would be creditors solely of the Company and any subsidiary guarantor whose guarantee was not avoided or held unenforceable. In such event, the claims of holders of the Notes against the issuer of an invalid guarantee would be subject to the prior payment of all liabilities of such subsidiary guarantor. There can be no assurance that, after providing for all prior claims, there would be sufficient assets remaining to satisfy the claims of the holders of the Notes relating to any avoided portions of any of the guarantees. In addition, if a court were to avoid the guarantees under fraudulent conveyance laws or other legal principles or, by the terms of such guarantees, the obligations thereunder were reduced as necessary to prevent such avoidance, or the guarantees were released, the claims of other creditors of the subsidiary guarantors, including trade creditors, would to such extent have priority as to the assets of such subsidiary guarantors over the claims of holders of the Notes. The guarantees of the Notes by any subsidiary guarantor will be released in certain circumstances. See "Description of the Notes -- Subsidiary Guarantees of Notes." LIMITATIONS ON REPURCHASE UPON A CHANGE OF CONTROL In the event of a Change of Control (as defined in the Indenture) each holder of Notes will have the right, at the holder's option, to require the Company to repurchase all or a portion of such holder's Notes at a purchase price equal to 101% of the principal amount thereof plus accrued interest thereon to the repurchase date. The Company's ability to repurchase the Notes upon a Change of Control may be limited by the terms of the Company's Senior Indebtedness and the subordination provisions of the Indenture. Further, the ability of the Company to repurchase Notes upon a Change of Control will be dependent on the availability of sufficient funds and compliance with applicable securities laws. Accordingly, there can be no assurance that the Company will be able to repurchase the Notes upon a Change of Control. The term "Change of Control" is limited to certain specified transactions and may not include other events that might adversely affect the financial condition of the Company or result in a downgrade of the credit rating (if any) of the Notes nor would the requirement that the Company offer to repurchase the Notes upon a Change of Control necessarily afford holders of the Notes protection in the event of a highly leveraged reorganization, merger or similar transaction involving the Company. See "Description of the Notes." RISKS OF HEDGING TRANSACTIONS In order to manage its exposure to price risks in the marketing of its oil and gas, the Company has in the past entered into, and expects to continue to enter into, oil and gas price hedging arrangements with respect to a portion of its expected production. These arrangements may include futures contracts and options sold on the New York Mercantile Exchange ("NYMEX") and privately-negotiated forwards, swaps and options. While intended to reduce the effects of volatility of oil and gas prices, such transactions may limit potential gains by the Company if oil and gas prices were to rise substantially over the prices established by hedging. In addition, such transactions may expose the Company to the risk of financial loss in certain circumstances, including instances in which (i) production is less than expected, (ii) there is a widening of price differentials between delivery points for the Company's production and the delivery point assumed in hedging arrangements, (iii) the counterparties to the Company's future contracts fail to perform the contracts, (iv) the Company fails to make timely deliveries or (v) a sudden, unexpected event materially impacts oil or gas prices. See "Business and Properties -- Marketing of Oil and Gas Production" and Note 8 to Consolidated Financial Statements. 13 14 EXPLORATION AND DEVELOPMENT RISKS Exploratory drilling and development drilling are subject to many risks, including the risk that no commercially productive reservoirs will be encountered, and there can be no assurance that new wells drilled by the Company will be productive or that the Company will recover all or any portion of its investment. Drilling for oil and gas may involve unprofitable efforts, not only from non-productive wells, but from wells that are productive but do not produce sufficient net revenues to return a profit. The cost of drilling, completing and operating wells is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond the Company's control, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery of equipment and services. SHORTAGES OF RIGS, EQUIPMENT, SUPPLIES AND PERSONNEL There is a general shortage of drilling rigs, equipment, supplies and personnel which the Company believes may intensify. The costs and delivery times of rigs, equipment, supplies and personnel are substantially greater than in prior periods and currently are escalating. The demand for, and wage rates of, qualified drilling rig crews have begun to rise in the drilling industry in response to the increasing number of active rigs in service. Such shortages have in the past occurred in the industry in times of increasing demand for drilling services. If the number of active drilling rigs continues to increase, the oil and gas industry may experience shortages of qualified personnel to operate drilling rigs. Shortages of drilling rigs, equipment or supplies could delay and adversely affect the Company's exploration and development operations, which could have a material adverse effect on its financial condition and results of operations. MARKETING RISKS The Company's ability to market oil and gas at commercially acceptable prices is dependent upon the availability, and capacity, of gas gathering systems, pipeline and processing facilities. The unavailability or lack of capacity thereof could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Federal and state regulation of oil and gas production and transportation, general economic conditions and changes in supply and demand all could adversely affect the Company's ability to produce and market its oil and gas. If market factors were to change dramatically, the financial impact on the Company could be substantial. The availability of markets and the volatility of product prices are beyond the control of the Company and represent a significant risk. ACQUISITION RISKS Acquisitions of oil and gas businesses, working interests in properties and volumetric production payments have been an important element of the Company's success, and the Company will continue to seek acquisitions in the future. Even though the Company performs a review of the major properties it seeks to acquire that it believes is consistent with industry practices (including a limited review of title and other records), such reviews are inherently incomplete and it is generally not feasible for the Company to review in-depth every property and all records. Even an in-depth review may not reveal existing or potential problems or permit the Company to become familiar enough with the properties to assess fully their deficiencies and capabilities, and the Company may assume environmental and other liabilities in connection with acquired businesses and properties. OPERATING RISKS The Company's operations are subject to numerous risks inherent in the oil and gas industry, including the risks of fire, explosions, blow-outs, pipe failure, abnormally pressured formations and environmental accidents such as oil spills, natural gas leaks, ruptures or discharges of toxic gases, the occurrence of any of which could result in substantial losses to the Company due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. The Company's operations 14 15 may be materially curtailed, delayed or canceled as a result of numerous factors, including the presence of unanticipated pressure or irregularities in formations, a high percentage of hydrogen sulfide gas ("sour gas"), title problems, weather conditions, accidents, compliance with governmental requirements and shortages or delays in the delivery of equipment. A number of the Company's wells are currently shut-in due to the presence of quantities of sour gas. Despite the Company's commitment of both financial and operational resources in the Manderson Field, oil and gas production did not increase significantly from this area during 1997. To the extent that mechanical, equipment, weather and other delays continue to prevent the Company from increasing production from the field, revenues and other aspects of the Company's financial performance could be adversely affected. See "Business and Properties -- Rocky Mountain Region -- Manderson Field." In accordance with customary industry practice, the Company maintains insurance against some, but not all, of the risks described above. There can be no assurance that the levels of insurance maintained by the Company will be adequate to cover any losses or liabilities. The Company cannot predict the continued availability of insurance, or availability at commercially acceptable premium levels. In addition, in the future, the Company may shut in wells due to the production of excess quantities of sour gas, a risk against which it does not maintain insurance. COMPETITIVE INDUSTRY The oil and gas industry is highly competitive. The Company competes for oil and gas business and property acquisitions and for the exploration, development, production, transportation and marketing of oil and gas, as well as for equipment and personnel, with major oil and gas companies, other independent oil and gas concerns and individual producers and operators. Many of these competitors have financial and other resources which substantially exceed those available to the Company. GOVERNMENT REGULATION The Company's business is subject to certain federal, state and local laws and regulations relating to the drilling for and production, transportation and marketing of oil and gas, as well as environmental and safety matters. Such laws and regulations have generally become more stringent in recent years, often imposing greater liability on an increasing number of parties. Because the requirements imposed by such laws and regulations are frequently changed, the Company is unable to predict the effect or cost of compliance with such requirements or their effects on oil and gas use or prices. In addition, legislative proposals are frequently introduced in Congress and state legislatures which, if enacted, might significantly affect the oil and gas industry. In view of the many uncertainties which exist with respect to any legislative proposals, the effect on the Company of any legislation which might be enacted cannot be predicted. See "Business and Properties -- Regulation." ABSENCE OF PUBLIC MARKET FOR THE NOTES Prior to this Offering, there has been no trading market for the Notes. Although the Underwriters have advised the Company that they currently intend to make a market in the Notes, they are not obligated to do so and may discontinue such market making at any time without notice. In addition, such market making activity will be subject to the limits imposed by the Securities Act and the Exchange Act. Accordingly, although the Notes have been approved for listing on the NYSE (subject to official notice of issuance), there can be no assurance that any market for the Notes will develop or, if one does develop, that it will be maintained. If an active market for the Notes fails to develop or be sustained, the trading price of the Notes could be materially adversely affected. 15 16 SPECIAL NOTE ON FORWARD-LOOKING STATEMENTS This Prospectus 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 Exchange Act. All statements other than statements of historical facts included in this Prospectus, including, without limitation, statements under "Prospectus Summary," "Risk Factors," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Business and Properties" are forward-looking statements. Such statements include, without limitation, discussions regarding planned capital expenditures, the Company's financial position, business strategy and other plans and objectives for future operations. Although the Company believes that the expectations reflected in such forward-looking statements are reasonable, it can give no assurance that such expectations will prove to have been correct. Such forward-looking statements involve known and unknown risks, uncertainties, and other factors that may cause actual results, performance or achievements to differ materially from any future results, performance or achievements expressed or implied by such forward-looking statements. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the Company. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates made by different engineers often vary from one another. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revisions of such estimate and such revisions, if significant, would change the schedule of any further production and development drilling. Accordingly, reserve estimates are generally different from the quantities of oil and gas that are ultimately recovered. Additional important factors that could cause actual results to differ materially from the Company's expectations are disclosed under "Risk Factors" and elsewhere in this Prospectus, including without limitation in conjunction with the forward-looking statements included in this Prospectus. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by such factors. 16 17 USE OF PROCEEDS The net proceeds to the Company from the Notes offered hereby are estimated to be approximately $121 million, after deducting estimated offering expenses payable by the Company. These estimated net proceeds will be used by the Company to reduce the outstanding indebtedness under the Bank Credit Facilities. The Bank Credit Facilities have been used historically to fund the Company's capital expenditure program, including the Rocky Mountain and Medallion Acquisitions, the Manderson Field development drilling program and the continued growth of the VPP program. Consistent with past practice, the Company intends to use the resulting borrowing capacity under these facilities to fund its future capital expenditure program. On December 26, 1997, the outstanding balance under the Bank Credit Facilities was $140.6 million. The Bank Credit Facilities permit the Company to borrow at interest rates based upon the 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. The weighted average interest rate on bank borrowings on September 30, 1997 was 7.2%. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Debt Financing" and "Description of Existing Indebtedness." CAPITALIZATION The following table sets forth the Company's capitalization at September 30, 1997, and as adjusted to give effect to the issuance of the Notes offered hereby and the application of the estimated net proceeds as set forth under "Use of Proceeds." The table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Company's Consolidated Financial Statements (including the notes thereto) included elsewhere in this Prospectus.
SEPTEMBER 30, 1997 ---------------------- ACTUAL AS ADJUSTED -------- ----------- (IN THOUSANDS) Long-term debt: Bank Credit Facilities.................................... $126,200 $ 5,206 11% Senior Notes due 2003................................. 149,523 149,523 8 7/8% Senior Subordinated Notes due 2008................. -- 125,000 -------- -------- Total long-term debt.............................. 275,723 279,729 -------- -------- Stockholders' equity: Preferred stock: 5,000,000 shares authorized; none issued................................................. -- -- Common stock, par value $0.01 per share: 50,000,000 shares authorized; 31,198,390 issued.......................... 312 312 Additional paid-in capital................................ 143,718 143,718 Retained earnings......................................... 111,348 111,348 Less treasury stock, 1,801,496 shares at cost............. (3,388) (3,388) -------- -------- Total stockholders' equity........................ 251,990 251,990 -------- -------- Total capitalization.............................. $527,713 $531,719 ======== ========
17 18 KCS ENERGY, INC. SELECTED HISTORICAL FINANCIAL INFORMATION (AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA) The historical financial data presented below is derived from the Company's financial statements. The information in this table should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the Consolidated Financial Statements (including the notes thereto) included elsewhere in this Prospectus. The historical data for the years ended December 31, 1992, 1993, 1994, 1995 and 1996 and for the nine months ended September 30, 1996 (i) includes revenues attributable to the Tennessee Gas Contract which was terminated effective January 1, 1997 and (ii) has been restated to reflect the discontinuation of the Company's natural gas transportation and marketing operations in 1997.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------------------------------------------------- ------------------------- 1992 1993 1994 1995 1996 1996 1997 ----------- ----------- ----------- ----------- ----------- ----------- ----------- (UNAUDITED) INCOME STATEMENT DATA: Revenue: Oil and gas revenue(1)........ $ 13,496 $ 40,455 $ 66,215 $ 86,629 $ 108,015 $ 79,051 $ 100,396 Other revenue, net............ 568 973 1,185 486 359 377 3,702 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total................... 14,064 41,428 67,400 87,115 108,374 79,428 104,098 Operating costs and expenses: Lease operating expenses...... 2,223 4,598 6,218 6,156 9,167 6,582 20,470 Production taxes.............. 391 411 845 467 2,526 1,671 4,354 General and administrative expenses.................... 3,190 4,158 4,853 4,704 7,825 5,411 7,302 Depreciation, depletion and amortization................ 2,985 7,179 18,783 38,231 45,460 33,128 42,486 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total................... 8,789 16,346 30,699 49,558 64,978 46,792 74,612 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Operating income................ 5,275 25,082 36,701 37,557 43,396 32,636 29,486 Interest and other income, net........................... 659 1,022 1,175 4,472 5,086 4,820 388 Interest expense................ (217) (1,125) (2,004) (6,807) (14,085) (11,193) (15,146) ----------- ----------- ----------- ----------- ----------- ----------- ----------- Income from continuing operations before income taxes......................... 5,717 24,979 35,872 35,222 34,397 26,263 14,728 Federal and state income taxes......................... 1,581 7,450 12,269 11,817 12,680 9,483 5,452 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Income from continuing operations.................... 4,136 17,529 23,603 23,405 21,717 16,780 9,276 Discontinued operations: Net income (loss) from operations.................. (126) 1,082 554 (2,099) (1,845) (1,974) (72) Net gain on disposition....... -- -- -- -- -- -- 5,461 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Net income...................... $ 4,010 $ 18,611 $ 24,157 $ 21,306 $ 19,872 $ 14,806 $ 14,665 =========== =========== =========== =========== =========== =========== =========== Earnings per share: Continuing operations......... $ 0.19 $ 0.75 $ 1.00 $ 1.00 $ 0.91 $ 0.70 $ 0.32 Discontinued operations....... (0.01) 0.05 0.02 (0.09) (0.08) (0.08) 0.18 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total................... $ 0.18 $ 0.80 $ 1.02 $ 0.91 $ 0.83 $ 0.62 $ 0.50 Average common shares outstanding................... 22,276 23,317 23,610 23,521 23,811 23,773 29,449 Dividends per common share...... $ 0.015 $ 0.030 $ 0.045 $ 0.060 $ 0.060 $ 0.045 $ 0.050 OTHER DATA (UNAUDITED): Tennessee Gas Contract premium(2).................... $ 4,059 $ 22,544 $ 42,828 $ 52,007 $ 32,829 $ 25,689 $ -- EBITDA(3)....................... 8,260 32,261 55,484 75,788 88,856 65,764 71,972 Capital expenditures............ 13,867 48,455 74,953 128,699 277,218 52,735 171,884 Ratio of earnings to fixed charges(4).................... 17.0x 20.7x 17.7x 6.1x 3.4x 3.3x 2.0x Ratio of EBITDA to interest expense....................... 38.1x 28.7x 27.7x 11.1x 6.3x 5.9x 4.8x BALANCE SHEET DATA (AT END OF PERIOD): Cash and cash equivalents....... $ 4,292 $ 5,369 $ 988 $ 5,846 $ 5,100 $ 53,597 $ 3,858 Working capital................. 23,924 29,396 33,969 81,953 30,755 78,497 7,707 Oil and gas properties, net..... 30,828 70,477 125,621 204,958 415,870 206,308 540,896 Total assets.................... 60,579 117,640 176,179 306,564 511,820 321,157 614,043 Long-term debt.................. 21,637 36,289 61,970 165,529 310,347 149,830 275,723 Total stockholders' equity...... 30,233 59,765 80,668 101,576 125,622 116,312 251,990
- --------------- (1) Includes revenues attributable to the Tennessee Gas Contract, for the years ended December 31, 1992, 1993, 1994, 1995 and 1996 and for the nine months ended September 30, 1996, that was terminated effective January 1, 1997. (2) Reflects revenues associated with the natural gas production covered by the above-market prices provided for in the Tennessee Gas Contract in excess of the revenues that would otherwise have been received for such production at spot market prices. (3) EBITDA represents income before depletion, depreciation, amortization, interest expense, interest and other income and income taxes. EBITDA is a financial measure commonly used in the Company's industry and should not be considered in isolation or as a substitute for net income, cash flow provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. (4) For purposes of calculating the ratio of earnings to fixed charges, fixed charges include interest expense and that portion of non-capitalized rental expense deemed to be the equivalent of interest. Earnings represents income before income taxes from continuing operations before fixed charges. 18 19 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following is a discussion and analysis of the Company's financial condition and results of operations and should be read in conjunction with the Company's Consolidated Financial Statements (including the notes thereto) included elsewhere in this Prospectus. GENERAL In the past year, 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, and the parties also agreed to the dismissal of the contract dispute that resulted in a November 1996 jury award to Tennessee Gas unfavorable to the Company. See Note 9 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. The December 1996 settlement did not affect the Company's successful conclusion of litigation earlier in the year relating to the validity and pricing provisions of the Tennessee Gas Contract and its recovery in September 1996 of approximately $70 million in past underpayments that had accrued under the contract. As of December 31, 1996, the Company completed the arrangements for the Medallion Acquisition (see Note 2 to Consolidated Financial Statements) for a total purchase price of approximately $199.1 million, consisting of $194.1 million in cash and warrants to purchase 870,000 shares of Common Stock at an exercise price of $22.50 per share with a four-year term. During the first quarter of 1997, the Company sold its principal natural gas transportation asset, the Texas intrastate pipeline, for a net sale price of $27.9 million and realized an after-tax gain of $5.9 million. In addition, the Company sold its gas marketing operations. Accordingly, the financial statements included in this Prospectus 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 significant marketing and transportation operations, to a Company focused on exploration and production, with a portfolio of operations 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 1993 accounted for 55% of total production and 78% of the Company's oil and gas revenues, is expected to account for less than 5% of production and revenues in 1997. The Company completed a two-for-one-stock split effective June 30, 1997. All per share data and data relating to the number of outstanding shares of Common Stock in this Prospectus have been adjusted to reflect the stock split. RESULTS OF OPERATIONS FOR NINE MONTHS ENDED SEPTEMBER 30, 1997 AND SEPTEMBER 30, 1996 Results of Operations -- Consolidated Net income for the nine months ended September 30, 1997 was $14.7 million, or $0.50 per share, compared to $14.8 million, or $0.62 per share for the nine months ended September 30, 1996. Income from continuing operations for the nine months ended September 30, 1997 was $9.3 million, or $0.32 per share, compared to $16.8 million, or $0.70 per share for the nine months ended September 30, 1996. Significantly higher oil and gas production during 1997 was more than offset by the impact of the termination of the Tennessee Gas Contract and higher net interest costs. In addition, current year earnings per share reflects the 19 20 effect of six million additional shares of Common Stock outstanding following the Company's public equity offering in January 1997. Net income for the current nine-month period included net income of $5.4 million, or $0.18 per share, from discontinued operations, principally from the gain on the sale of the Texas intrastate pipeline system. Revenue
NINE MONTHS ENDED SEPTEMBER 30, ------------------- 1996 1997 ------- -------- Production: Oil (Mbbl)................................................ 547 1,295 Liquids (Mbbl)............................................ -- 101 Gas (MMcf)................................................ 18,922 32,806 Total (MMcfe)..................................... 22,204 41,180 Average Prices: Oil (per bbl)............................................. $ 19.72 $ 18.92 Liquids (per bbl)......................................... -- 11.05 Gas (per Mcf)............................................. 3.61 2.28 Total (per Mcfe).................................. 3.56 2.44 Revenue: Oil....................................................... $10,779 $ 24,501 Liquids................................................... -- 1,113 Gas....................................................... 68,272 74,782 ------- -------- Total............................................. $79,051 $100,396
Oil and Gas Production. The Company's oil and gas production during the nine months ended September 30, 1997 increased 85% to 41.2 Bcfe, compared to 22.2 Bcfe produced during the same period in 1996. For the nine months ended September 30, 1997, oil and liquids production increased 155% to 1,396 Mbbls and gas production increased 73% to 32.8 Bcf, compared to the same period in 1996. The production increases were primarily as a result of the Medallion Acquisition. Gas Revenue. For the nine months ended September 30, 1997, gas revenues increased $6.5 million to $74.8 million. Production gains added $31.9 million of gas revenue during the 1997 period. This increase was largely offset by the termination of the Tennessee Gas Contract, which provided $25.7 million in premium over corresponding spot market prices in the nine-month period ended September 30, 1996. Average realized prices for gas not covered by the Tennessee Gas Contract were $2.28 and $2.29 per Mcf in the 1997 and 1996 nine-month periods, respectively. Oil and Liquids Revenue. For the nine months ended September 30, 1997, oil and liquids revenue increased $14.8 million to $25.6 million. Production gains added $15.3 million of oil and liquids revenue, partially offset by lower average realized prices. Other Revenue, Net Other revenue includes certain marketing and gathering revenues incidental to the Company's oil and gas exploration and production operations. The increases for the nine months ended September 30, 1997 over the same period in 1996 were primarily the result of the Medallion Acquisition. The 1997 nine-month total includes $1.3 million from the settlement of a gas sales contract dispute during the second quarter of 1997. Lease Operating Expenses As a result of the substantial increase in oil and gas production, lease operating expenses increased $13.9 million to $20.5 million for the nine months ended September 30, 1997, compared to the same period in 1996. Approximately $12.3 million of the increase was related to the Medallion properties, with the remainder 20 21 of the increase primarily due to the expanded operations in the Rocky Mountain region, especially in the Manderson Field. Production Taxes Production taxes, which are generally based on a fixed percentage of revenue, increased 161% to $4.4 million during the nine months of 1997, compared to the same period in 1996. In addition to the effect of higher oil and gas revenue during the 1997 period, 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. General and Administrative Expenses For the nine months ended September 30, 1997, general and administrative expenses increased $1.9 million to $7.3 million, compared to the same period in 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. Depreciation, Depletion and Amortization The Company provides for depreciation, depletion and amortization ("DD&A") on its oil and gas properties using the future gross revenue method based on recoverable reserves valued at current prices. For the nine months ended September 30, 1997, DD&A on the Company's oil and gas properties increased $8.1 million over the same period in 1996. Production gains increased DD&A by $8.7 million, partially offset by a $0.6 million reduction attributable to a decline in the DD&A rate. In addition, depreciation on assets other than oil and gas properties increased $1.3 million primarily due to the expansion of the Company's operations in the Mid-Continent and Rocky Mountain regions. Interest and Other Income, Net Interest and other income was lower during the nine-month period ended September 30, 1997 compared to the same period in 1996 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 Expense Interest expense increased $4.0 million to $15.1 million for the nine months ended September 30, 1997, as compared to the same period in 1996. Higher average borrowings in 1997 due to the expansion of the Company's oil and gas 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. RESULTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31, 1996, 1995 AND 1994 Results of Operations Net income for the year ended December 31, 1996 was $19.9 million, or $0.83 per share, compared to $21.3 million, or $0.91 per share, for the year ended December 31, 1995. Income from continuing operations was $21.7 million, or $0.91 per share, for the year ended December 31, 1996, compared to $23.4 million, or $1.00 per share, for the year ended December 31, 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 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. Net income for the year ended December 31, 1995 was $21.3 million, or $0.91 per share, compared to $24.2 million, or $1.02 per share, for the year ended December 31, 1994. Income from continuing operations 21 22 was $23.4 million, or $1.00 per share, for 1995, compared to $23.6 million, or $1.00 per share, for 1994. A significant increase in gas production in 1995, compared to 1994, was offset by the impact of lower natural gas prices and higher net interest costs. Loss from discontinued operations in 1995 was $2.1 million, or $0.09 per share, compared to income from discontinued operations of $0.6 million, or $0.02 per share, in 1994. Lower natural gas prices and the absence of severe weather conditions during the peak 1994/1995 winter heating season were the primary reasons for the 1995 loss from discontinued operations. Revenue
YEAR ENDED DECEMBER 31, ------------------------------ 1994 1995 1996 ------- ------- -------- Production: Oil (Mbbl)......................................... 211 196 758 Gas (MMcf)......................................... 11,304 19,129 25,581 Total (MMcfe).............................. 12,570 20,305 30,129 Average Prices: Oil (per bbl)...................................... $ 15.16 $ 17.28 $ 20.69 Gas (per Mcf)...................................... 5.54 4.29 3.61 Total (per Mcfe)........................... 5.27 4.27 3.59 Revenue: Oil................................................ $ 3,198 $ 3,387 $ 15,684 Gas................................................ 63,017 83,242 92,331 ------- ------- -------- Total...................................... $66,215 $86,629 $108,015
Oil and Gas Production. The Company's oil and gas production during 1996 increased 48% to 30.1 Bcfe, compared to 20.3 Bcfe produced during 1995. Oil production increased 286% to 758 Mbbls and gas production increased 34% to 25.6 Bcf. Approximately 6.7 Bcfe of the increase in oil and gas production was attributable to the Company's VPP program, with the remainder resulting from a combination of lease acquisitions, exploration and development drilling. Oil and gas production during 1995 increased 62% to 20.3 Bcfe, compared to 12.6 Bcfe in 1994, primarily due to higher gas and oil volumes delivered under the Company's VPP program. Gas Revenue. In 1996, gas revenues increased $9.1 million to $92.3 million. Higher production from properties not covered by the Tennessee Gas Contract along with higher average 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 during 1995, largely due to the normal production decline from 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 percent of production covered by the Tennessee Gas Contract. Average non-Tennessee Gas Contract gas prices were $2.35 per Mcf in 1996, compared to $1.62 per Mcf in 1995. Natural gas sale prices under the Tennessee Gas Contract, excluding severance tax reimbursements, were $8.40 in 1996, compared to $7.90 in 1995. The early termination of the Tennessee Gas Contract, with its above-market pricing provisions, resulted in downward revisions in the amounts of $37.1 million for estimated future net revenues before income taxes (based upon a natural gas price of $3.69 per Mcf, the assumed realized price on December 31, 1996) and $34.7 million for PV-10. 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. Not only is the Company's oil and gas revenue more sensitive to spot market price changes, but significant declines in oil and gas prices, like those experienced in early 1997, if not offset by increases in proved oil and gas reserves, could result in a substantial increase in non-cash depreciation, depletion and amortization ("DD&A") accruals and could negatively impact earnings. The Company provides for DD&A using the future gross revenue method based on recoverable reserves valued at current prices. See Note 1 to Consolidated Financial Statements -- "Property, 22 23 Plant and Equipment" for a description of how the Company provides for DD&A and the related limitation on capitalized oil and gas property costs. The Company utilizes commodity price swaps, futures and options contracts and basis swaps (see Note 8 to Consolidated Financial Statements) to help mitigate the impact of fluctuations in the price of its natural gas and oil production. Gas revenues in 1995 increased $20.2 million to $83.2 million. Higher production from properties not covered by the Tennessee Gas Contract was partially offset by lower average non-Tennessee Gas Contract prices. Sales to Tennessee Gas were 6.9 Bcf in both 1995 and 1994. Average natural gas prices were $4.29 per Mcf in 1995, compared to $5.54 per Mcf in 1994. This decrease resulted from lower non-Tennessee Gas Contract gas prices of $1.62 in 1995, compared to $1.81 in 1994. Natural gas sale prices under the Tennessee Gas Contract, excluding severance tax reimbursements, were $7.90 in 1995, compared to $7.49 in 1994. Oil Revenue. In 1996, oil revenue increased $12.3 million to $15.7 million, compared to 1995. Production gains, primarily from properties in the Rocky Mountain region added $11.6 million. The remainder of the increase was due to higher average oil prices. Oil revenue in 1995 increased $0.2 million to $3.4 million mainly due to higher average oil prices. Lease Operating Expenses For the year ended December 31, 1996, lease operating expenses increased $3.0 million to $9.2 million, or $0.30 per Mcfe, primarily due to production increases in the Rocky Mountain region over 1995 lease operating expenses of $6.2 million, or $0.30 per Mcfe, and $6.2 million, or $0.49 per Mcfe, in 1994. The reduction in rate per Mcfe in 1995 compared to 1994 was primarily due to higher VPP volumes which do not bear any development or lease operating expenses. Production Taxes Production taxes increased $2.1 million to $2.5 million in 1996 over 1995 primarily due to the increased revenue and, to a lesser extent, an increase in average production tax rates, which are higher in the Rocky Mountain region as compared to the Gulf Coast region. In addition, a larger percentage of the Company's revenue was subject to production taxes in 1996, as compared to 1995, due to the decline in production covered under the Tennessee Gas Contract, which provided for reimbursement of severance taxes. In 1995, production taxes were $0.5 million, compared to $0.8 million in 1994. While total revenue increased significantly, revenue subject to production taxes was down slightly. The overall increase in revenue was mainly due to the VPP program, which generally are free of production taxes. General and Administrative Expenses 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. In 1995, general and administrative expenses decreased slightly to $4.7 million, compared to $4.9 million in 1994. Depreciation, Depletion and Amortization For the year ended December 31, 1996, depreciation, depletion and amortization ("DD&A") increased $7.2 million over DD&A for 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. In 1995, DD&A increased $19.4 million over 1994 DD&A to $38.2 million due to the increase in oil and gas revenue and an increase in the DD&A rate to 43.9% in 1995 from 28% in 1994. The increase in the DD&A rate in 1995 reflects the relative increase in the percentage of total proved reserves not covered by the Tennessee Gas Contract. 23 24 Interest and Other Income, Net Interest and other income was $5.1 million in 1996, compared to $4.5 million in 1995 and $1.2 million in 1994. Of these amounts, $4.4 million, $3.1 million and $0.2 million for the years 1996, 1995 and 1994, respectively, represented interest income accrued on the Tennessee Gas receivable. These amounts were included in the September 1996 cash payment received from Tennessee Gas. The Tennessee Gas Contract was terminated effective January 1, 1997. See Note 9 to Consolidated Financial Statements. Interest Expense Interest expense was $14.1 million in 1996, compared to $6.8 million in 1995 and $2.0 million in 1994. 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, as well as in 1995 compared to 1994, were used to expand the Company's operations. The increases in interest expense during the periods were partially offset by the increase in interest income as discussed above. Income Taxes The income tax provision was $12.7 million in 1996, representing an effective tax rate of 36.9%, compared to effective rates of 33.6% and 34.2% in 1995 and 1994, respectively. See Note 7 to Consolidated Financial Statements for the reconciliation of the statutory federal income tax rate to the Company's effective tax rates. A substantial portion of the income taxes reflected on the Company's income statements during these periods is deferred to future years. LIQUIDITY AND CAPITAL RESOURCES Cash Flow From Operating Activities Net income adjusted for non-cash charges increased to $57.6 million for the nine months ended September 30, 1997, compared to $54.2 million during the same period in 1996. The increase reflects cash flow from the properties acquired as part of the Medallion Acquisition, which more than offset the impact of the termination of the Tennessee Gas Contract ($25.7 million). Net cash provided by operating activities was $61.9 million during the 1997 nine-month period, compared to $105.1 million for the nine months ended September 30, 1996. The 1996 period included the receipt of approximately $70 million from Tennessee Gas on September 30, 1996 for past underpayments and interest pursuant to the Tennessee Gas Contract. The reduction in trade accounts receivable ($58.1 million) and in accounts payable and accrued liabilities ($54.6 million) were largely related to the discontinuance of the natural gas transportation and marketing 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 nine months ended September 30, 1997 were $171.9 million of which $91.2 million was for development drilling, including $10.8 million for Manderson Field infrastructure, $45.6 million for the acquisition of proved reserves under the Company's VPP program and $33.0 million for lease acquisitions, seismic surveys and exploratory drilling. As of March 31, 1997, the Company completed the sale of its principal natural gas transportation asset for a net sale price of $27.9 million, the proceeds of which were used to reduce indebtedness under its Bank Credit Facilities, and recognized an after-tax gain of $5.9 million. The 1997 capital budget was initially set at $160 million and was subsequently increased to $210 million for 1997 in order to further the Company's expansion in the Rocky Mountain region and to provide additional 24 25 funding for the VPP program. The Company believes that internally generated cash and additional borrowings under the Bank Credit Facilities are sufficient to fund its capital program. The Company has established a preliminary capital expenditure budget for 1998 of $183 million, consisting of $95 million for development drilling, $30 million for exploration, $45 million for VPP transactions, $10 million for working interest acquisitions and $3 million for other expenditures. The program is expected to be largely funded by cash flow from operations, borrowings under the Bank Credit Facilities and, to a lesser extent, the sale of non-strategic assets. Capital expenditures in 1996 were $282.2 million, of which $183.1 million was related to the Medallion Acquisition (see Note 2 to Consolidated Financial Statements), $54.9 million was for development drilling, including $13.8 million in the Bob West Field, $15.9 million was for the purchase of proved reserves under the Company's VPP program and $18.2 million was for 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 (including the Michigan Acquisition), $33 million was for the Rocky Mountain Acquisition and $19.4 million was for the development of the Bob West Field. The remainder was largely for lease acquisitions, seismic evaluations and exploratory drilling ($16.9 million) and development drilling ($7.5 million) on non-Tennessee Gas Contract properties. The Company funded its capital expenditures through a combination of additional borrowings under its credit facilities and internally generated cash. Debt Financing The Company 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 mature on January 15, 2003 and bear interest at the rate of 11% per annum, payable semi-annually. The Senior Notes are redeemable at the option of the Company, in whole or in part, commencing January 15, 2000, at pre-determined redemption prices set forth within the Senior Notes Indenture. 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 by the Company to 50% of the Company's cumulative net income during the period beginning October 1, 1995. Credit Facility In September 1996, the Company consolidated two separate credit agreements creating one revolving credit facility (the "Credit Facility") which will mature on September 30, 2000. The Credit Facility 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 limited to approximately $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 September 30, 1997, the weighted average interest rate under the Credit Facility was 6.8% and $74.5 million was outstanding. Revolving Credit Agreement Simultaneous with the consummation of the Medallion Acquisition in January 1997, 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 and a pledge of Medallion's common stock. The Revolving Credit Agreement permits the Company to borrow at interest rates 25 26 based upon the 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 September 30, 1997, the weighted average interest rate under the Revolving Credit Agreement was 7.8% and $51.7 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. 26 27 BUSINESS AND PROPERTIES GENERAL KCS is an independent oil and gas company engaged in the acquisition, exploration, development and production of oil and gas. Through its experienced management and technical staff, the Company has grown significantly and created a geographically diversified reserve base by implementing a balanced program of development drilling, reserve acquisitions and exploration drilling. The Company concentrates its activities in areas where it has accumulated geological knowledge and technical expertise and where it can retain significant operating control. As a result of these efforts, KCS has compiled a multi-year inventory of over 600 potential drilling and recompletion locations, including a significant number of sites in the Manderson Field in the Big Horn Basin in Wyoming where the Company believes it has the potential to significantly increase its reserves. Additionally, the Company augments its working interest ownership of properties with a volumetric production payment ("VPP") program to acquire priority rights to a portion of the oil and gas from other parties' producing properties. The Company plans to spend $183 million on capital expenditures in 1998, of which $95 million is for development drilling, $30 million is for exploration, $45 million is for the VPP program, $10 million is for working interest acquisitions and $3 million is for other expenditures. The Company currently plans to drill approximately 175 development wells and to participate in approximately 60 exploratory prospects during 1998. The Company's operations are primarily focused in the Rocky Mountain, Gulf Coast, and Mid-Continent/West Texas regions, and through its VPP program primarily in the Gulf of Mexico and Michigan. As of December 31, 1996, the Company had estimated proved reserves of 355.8 Bcfe with an estimated pre-tax present value of future net revenues of $557.6 million. These estimated reserves were 75% natural gas and 87% proved developed, and approximately 10% were attributable to the Company's VPP program. The Company operates properties comprising approximately 72% of its reserves (excluding VPP reserves) at December 31, 1996. A significant focus of the Company's future development is in the Manderson Field in the Big Horn Basin in Wyoming. Since it acquired the field in November 1995, the Company has increased its acreage position from 7,500 to over 61,000 gross acres, and has undertaken an extensive exploration and development drilling program. Through September 30, 1997, the Company had drilled 54 wells, investing $35 million, and had spent $15.3 million to install infrastructure in the field. Most of these wells are currently shut-in or awaiting completion, remediation or stimulation because of delays in construction of a sour gas treatment plant and associated gas injection system. Operations at the plant and injection system commenced on December 3, 1997. Based on drilling and production results and accumulation of additional seismic data, the Company believes that there are seven productive formations located in the greater Manderson Field and that they have significant reserve potential. The Company plans to spend $12 million in the fourth quarter of 1997 to complete a sour gas treatment plant in the Manderson Field, bring the shut-in wells on production and drill 17 additional wells. In 1998, the Company plans to spend approximately $40 to $50 million to drill and complete as many as 70 to 100 wells in this field. The Company has successfully increased its reserves through opportunistic acquisitions. In May 1997, KCS completed an acquisition of properties in the Langham Creek Field near Houston, Texas for $17 million, which enabled it to assume operatorship and increase its average working interest in the area to approximately 61%. In December 1996, the Company completed a major acquisition of oil and gas properties, principally in the Mid-Continent region, for an aggregate purchase price of $199 million. As a result of the Medallion Acquisition, the Company more than doubled its reserve base and production rate and significantly expanded its presence in the Mid-Continent region. In November 1995, the Company completed an acquisition in the Rocky Mountain region for $33 million, which resulted in numerous exploration and development opportunities, including the Manderson Field. Through its VPP program, the Company is able to add reserves at very attractive rates of return and increase its exposure to acquisition, development and exploration opportunities. In the three years ended 27 28 September 30, 1997, the Company invested $124 million in 25 separate VPP transactions, acquiring 71.8 Bcf of natural gas and 1.5 MMbbls of oil. BUSINESS STRATEGY KCS intends to continue to broaden its reserve base and increase production and cash flow through a balanced program of development drilling, reserve acquisitions and exploration drilling. The Company extensively utilizes advanced technology, most notably 3-D seismic, computer-enhanced basin analysis, and reservoir simulation and stimulation techniques, to better delineate and produce reserves. The key components of the Company's business strategy include: (i) exploiting and developing its multi-year inventory of development drilling locations, (ii) capitalizing on the development potential of the Manderson Field, (iii) acquiring properties with growth potential, (iv) controlling its major properties, (v) continuing to expand its VPP program and (vi) pursuing a balanced exploration program that includes high-potential opportunities. KEY STRENGTHS To implement its business strategy, the Company intends to take advantage of several key strengths, including the following: Proven Growth Record. The Company has achieved substantial growth in reserves, production and EBITDA since 1992. KCS's estimated proved reserves have increased at a compound annual growth rate of 57%, from 60.0 Bcfe as of December 31, 1992 to 355.8 Bcfe as of December 31, 1996. Over this period, production has increased at a compound annual growth rate of 61%, from 4.4 Bcfe in 1992 to 30.1 Bcfe in 1996. Similarly, the Company's EBITDA has increased at a compound annual growth rate of 81%, from $8.3 million for the year ended December 31, 1992 to $88.9 million for the year ended December 31, 1996. For the nine months ended September 30, 1997, the Company had oil and gas production of 41.2 Bcfe and EBITDA of $72.0 million, compared to 22.2 Bcfe and $65.8 million for the same period in 1996. Innovative and Creative Approach to Expansion. The Company has demonstrated the ability to identify and acquire oil and gas reserves in a disciplined, creative manner and believes it has become one of the leaders in the acquisition of oil and gas reserves through VPP transactions. Large Multi-year Inventory of Drilling Opportunities. The Company has identified more than 600 potential drilling and recompletion locations, representing a three to four-year inventory. In addition, the Company believes that there are significant exploratory opportunities in the acreage it has assembled, including more than 265,000 gross undeveloped acres, in the onshore Gulf Coast regions of Texas and Louisiana and in the Rocky Mountain and Mid-Continent regions. Geographically Diversified Property Base. The Company operates in three distinct regions: the Rocky Mountains, the Gulf Coast and the Mid-Continent/West Texas regions. As a result, it benefits from diversification with respect to risks associated with focusing on any one geographical region. Successful Drilling Program. During the three-year period ended December 31, 1996, the Company participated in the drilling of 118 development wells and 70 exploratory wells with a 93% and 46% completion rate. During the first nine months of 1997, the Company participated in the drilling of 71 development wells, 86% of which were completed and 23 exploratory wells, 43% of which were completed. Over the five-year period ended December 31, 1996, the Company replaced approximately 114% of its production through drilling. High Operating Margins. The Company's drilling success and emphasis on an efficient administrative and operating structure have enabled the Company to generate high cash margins that the Company believes compare favorably with its peer companies. Control of Major Properties. The Company seeks to operate and own a majority working interest in its major properties, which gives it greater control over the timing and nature of future development as well as over operating costs and the marketing of production. The Company operates properties comprising approximately 72% of its reserves (excluding VPP reserves) at December 31, 1996. 28 29 Experienced, Motivated Management Team with a Significant Equity Stake. The Company's senior management has extensive experience in the oil and gas industry and is motivated to increase stockholder value. The Company's compensation system is strongly geared to "pay for performance" with incentives directly tied to operating and financial goals and objectives. Members of the Company's management and directors currently own approximately 14% of the Company's common stock, and the Company has established minimum direct ownership requirements for all officers and directors. The Company's executive offices are located at 379 Thornall Street, Edison, New Jersey 08837, and its telephone number is (732) 632-1770. The Company has regional operating offices in Worland, Wyoming; Houston, Texas; and Tulsa, Oklahoma. OIL AND GAS OPERATIONS AND PRINCIPAL PROPERTIES From 1991 through 1996, the Company's most significant property was the Bob West Field in south Texas, which accounted for approximately 34% of the Company's gas production and 61% of oil and gas revenues during that six-year period. Most of the Company's natural gas sold from the Bob West Field 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 settlement covering all claims and litigation between them and terminated the contract effective January 1, 1997. Prior to their sale earlier in 1997, the Company also operated an intrastate natural gas transportation business and a natural gas marketing and services business, both of which are reflected in the Company's financial statements as discontinued operations. The Company sold its 150-mile intrastate pipeline system for an adjusted net sale price of $27.9 million and recorded an after-tax gain of $5.9 million. The Company also sold its natural gas marketing operations. The Company has retained its natural gas gathering systems in Texas, Montana and Louisiana, which primarily serve Company-operated wells. 29 30 Approximately 84% of the Company's PV-10 of estimated proved reserves at December 31, 1996 (excluding the impact of oil and gas hedging activities) and 90% of its total proved oil and gas reserves were attributable to properties in which it has a working interest. The remaining 16% of PV-10 of proved reserves (excluding the impact of oil and gas hedging activities) and 10% of proved reserves were attributable to its reserves acquired through the VPP program. The Company operates properties comprising approximately 72% of its reserves (excluding VPP reserves) at December 31, 1996. The following table sets forth data as of December 31, 1996 regarding the number of gross producing wells, the estimated quantities of proved oil and gas reserves and the PV-10 attributable to the Company's principal working interest and VPP properties. Except where otherwise provided by contractual agreement, future cash inflows are estimated using year-end prices. Oil and gas prices at December 31, 1996 are not necessarily reflective of the prices the Company expects to receive in the future. Other than gas sold under certain contractual arrangements, including swaps, futures contracts and options, average realized gas prices of $3.54 per Mcf and average realized oil prices of $22.45 per bbl were in effect at December 31, 1996.
ESTIMATED PROVED RESERVES GROSS ------------------------------- % OF PRODUCING OIL NATURAL GAS TOTAL PV-10 TOTAL LOCATION WELLS (MBBLS) (MMCF) (MMCFE) ($000'S) PV-10 -------- --------- ------- ----------- ------- -------- ----- Rocky Mountain Region: Manderson Field, Wyoming............. 32 3,574 13,027 34,471 $ 41,558 8% Ignacio Blanco Field, Colorado....... 49 -- 9,944 9,944 7,646 1 Dragon Trail Field, Colorado......... 160 1 6,921 6,927 7,378 1 Others............................... 1,335 3,295 23,037 42,807 39,916 7 ----- ------ ------- ------- -------- --- Total............................. 1,576 6,870 52,929 94,149 96,498 17 Gulf Coast Region: Bob West Field, Texas................ 50 -- 23,025 23,025 39,945 7 Langham Creek Area, Texas............ 12 193 16,232 17,390 33,935 6 Eugene Island 251, Gulf of Mexico.... 7 67 3,004 3,406 11,088 2 Bayou Rambio Field, Louisiana........ 1 23 2,600 2,738 6,621 1 South Timbalier 148, Gulf of Mexico............................ 10 87 1,978 2,500 6,404 1 Laurel Ridge Field, Louisiana........ 2 71 1,329 1,755 6,303 1 Glasscock Ranch Field, Texas......... 10 70 2,863 3,283 5,736 1 Others............................... 314 1,380 23,660 31,940 69,215 13 ----- ------ ------- ------- -------- --- Total............................. 406 1,891 74,691 86,037 179,247 32 Mid-Continent/West Texas Region: Sawyer Canyon Field, Texas........... 345 65 50,845 51,235 84,427 15 Elm Grove Field, Louisiana........... 29 50 17,278 17,578 38,409 7 Aubrey/Wilsonia Fields, Louisiana.... 7 228 2,512 3,880 10,596 2 Mills Ranch Field, Texas............. 16 8 4,078 4,126 8,126 2 Others............................... 594 2,453 33,793 48,511 71,925 13 ----- ------ ------- ------- -------- --- Total............................. 991 2,804 108,506 125,330 213,483 39 Other Regions: Newhall-Potrero Field, California.... 35 1,758 1,577 12,125 11,559 2 Mayfield/Hayes Properties, Michigan.......................... 6 196 2,681 3,857 8,845 2 Others............................... 24 36 498 720 1,214 -- ----- ------ ------- ------- -------- --- Total............................. 65 1,990 4,756 16,702 21,618 4 Total Working Interest Properties................. 3,038 13,555 240,882 322,218 510,846 92 Volumetric Production Payments (VPP): Niagaran Reef Trend, Michigan........ 95 803 11,060 15,878 46,539 8 Gulf of Mexico....................... 30 160 15,648 16,608 45,607 6 Others............................... 127 113 435 1,109 3,844 3 ----- ------ ------- ------- -------- --- Total VPP Properties......... 252 1,076 27,143 33,595 95,990 17 Hedging Effects.............. -- -- -- -- (49,224) (9) Total Company.............. 3,290 14,631 268,025 355,813 $557,612 100% ===== ====== ======= ======= ======== ===
30 31 All of the Company's exploration and development activities are located within the United States. Set forth below are descriptions of certain of the Company's working interest and VPP producing properties and those targeted for significant drilling activity during the remainder of 1997 and 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. Estimated proved reserves in the region were 94,149 MMcfe at December 31, 1996. The Company has budgeted $70 million for development and exploratory drilling activities in the region during 1998 and expects to have spent $73 million for such activities during 1997, including approximately $16 million for Manderson Field infrastructure. During the nine months ended September 30, 1997, the Company drilled 37 gross (37 net) development wells and 6 gross (5.3 net) exploratory wells in the Rocky Mountain Region. It expects to drill another 18 gross (18 net) development wells by the end of the year and as many as 125 gross (125 net) development wells and 8 gross (7.3 net) exploratory wells during 1998. 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 acreage holdings and 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 514,072 gross (377,957 net) developed and undeveloped acres as of September 30, 1997. Following the Rocky Mountain Acquisition, the Company hired highly experienced and technically competent exploration, engineering and operational personnel with experience in the Rocky Mountain region who were formerly employed by the seller. The Company's staff in the region totaled 80 persons as of September 30, 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 Rocky Mountain Acquisition to more than 61,000 gross (56,000 net) acres at September 30, 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 and the 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. Through September 30, 1997, the Company had drilled a total of 54 wells targeting the Phosphoria, Muddy, Frontier and Octh Louie formations. Based on drilling and production results, coupled with the acquisition and interpretation of additional seismic data, the Company believes that the seven productive 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. At December 31, 1996, 31 32 the Company's proved reserves included 3,574 Mbbls of oil and 13,027 MMcf of gas from its acreage in the field, representing 10% of its proved reserves. Through September 30, 1997, of the 54 wells the Company had drilled, 42 wells targeted the Phosphoria in the Manderson Field. As of September 30, 1997, eight of the completed Phosphoria wells were stimulated and tested at rates ranging from 200 to 1,900 bbls of oil per day and from 450 to 4,000 Mcf of natural gas per day. The presence of sour gas from the Phosphoria formation 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 have been shut-in for extended periods of time awaiting completion of a sour gas processing facility (amine plant) and an associated acid gas injection system. As of September 30, 1997, nine wells drilled to the Phosphoria had been plugged back to the shallower Octh Louie or Muddy formations due to well bore damage caused by being shut-in, 11 Phosphoria wells were awaiting completion, 13 wells were awaiting stimulation or remediation and one Phosphoria well had been completed to a full-stream re-injection well. In addition, eight previously stimulated wells may require remediation due to effects of being shut-in for extended periods. Through September 30, 1997, the Company also drilled 12 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, with four wells still in the process of being completed. 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 processing sour gas in late July 1997. Although operation of the amine plant had been severely limited due to delays in receipt of acid gas disposal equipment, operations at the plant and the associated acid gas injection system commenced on December 3, 1997. Once fully operational, the Company's treatment plant will have the design 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 design capacity, assuming treatment to pipeline specifications, would permit oil production from the Manderson Field at up to 14,000 bbls 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. See "Risk Factors -- Operating Risks." 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 received an approved permit to drill and complete 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 plans to drill the second acid gas injection well early in the first quarter of 1998. 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 September 30, 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 bbls 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. The Company also has the option of treating the sour gas produced from the Phosphoria to pipeline specification at its own amine plant and using the nearby third-party gas treatment facility to remove the natural gas liquids from sweet gas from the shallower formations. Based 32 33 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. At November 30, 1997, the Company had two drilling rigs and eight completion rigs in the field and plans to have drilled at least 70 wells targeting the Phosphoria, Muddy, Octh Louie and Frontier formations by year-end 1997, 50 of which it estimates will be on line (although less than one-third will have been stimulated). In 1998, the Company plans to drill an additional 70 to 100 wells in the field. The exact mix of formations to be targeted will depend on several factors, including relative oil and gas pricing, sour gas treatment plant and gas re-injection capacity, timing of receipt of permits, the availability of natural gas liquids processing and gas and oil transportation capacity. During September 1997, the average production attributable to the Company's interest in the Manderson Field was 4,252 (2,833 re-injected) Mcf of natural gas and 352 bbls of oil per day, as most of the Company's wells remained shut-in pending completion of the amine plant and related acid gas injection facilities. Operations at the amine plant and the acid gas injection system commenced on December 3, 1997. Other Big Horn Basin Properties In addition to its holdings in the Manderson Field, the Company also has interests in five other producing properties with many of the same formations as the Manderson Field in the Big Horn Basin, totaling 114,381 gross (114,024 net) acres. 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 (70,000 net) acres. As of September 30, 1997, one new well had been drilled and completed to the Dakota sand at a depth of approximately 11,000 feet and pipe had been set on a second well which was awaiting a completion rig. The Company plans to drill at least 10 wells during 1998. Drilling results also indicate the presence of possible hydrocarbons in the Muddy, Frontier, Cody, Mesa Verde, Phosphoria and the Tensleep formations. GULF COAST REGION The Company's Gulf Coast Region operations are comprised primarily of onshore properties in Texas and Louisiana, including the Bob West Field in south Texas and the Langham Creek Area near Houston, Texas. The Company also owns non-operated interests in the Gulf of Mexico. Estimated proved reserves in the region, (exclusive of VPP interests) were 86,037 MMcfe as of December 31, 1996. The Company has budgeted $35 million for development and exploratory drilling activities in the region during 1998 and expects to have spent $34 million for such activities during 1997. During the nine months ended September 30, 1997, the Company drilled 12 gross (7.0 net) development wells and 16 gross (7.7 net) exploratory wells in the Gulf Coast Region. It expects to drill another 4 gross (3.65 net) development wells and 5 gross (4.25 net) exploratory wells by the end of 1997 and expects to participate in approximately 16 gross development wells and 17 gross exploratory wells during 1998. 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 has been the Company's most significant producing property, accounting for approximately 35% of gas production and 61% of oil and gas revenues during the six-year period ended December 31, 1996. 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 34 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. During 33 34 September 1997, the average combined rate of production attributable to the Company's net revenue interest in these areas was approximately 6,815 Mcf of natural gas per day. 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 the Wilcox formation from 9,000 to 16,500 feet. The Company acquired additional working interests in the Langham Creek Area in Harris County, Texas 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 15 wells in this area, representing an average working interest of approximately 61%. During September 1997, the average production attributable to the Company's interest was approximately 11,140 Mcf of natural gas and 100 bbls of condensate per day. 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. The Company plans to continue active development in the area and plans to drill as many as five additional wells targeting these sands in 1998. In addition, the Company is currently completing a 16,500-foot well to test the deeper Wilcox sands on trend with North Milton Field, which field has produced approximately 200 Bcf to date, and has initiated a 3-D seismic survey to better delineate potential drilling locations. Results of the 3-D seismic survey are expected to be completed during the first quarter of 1998 and could change the number of potential drilling locations. 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, West Cameron and Galveston Island areas) which are operated by other companies, primarily Newfield Exploration Company ("Newfield"). The Company has interests in 53 gross (5.0 net) wells with an average working interest of approximately 9%. During September 1997, average daily production from this area attributable to the Company's interest was approximately 8,700 Mcf of natural gas and 364 bbls of oil. These fields produce from various Pleistocene, Pliocene and Miocene sands ranging from 6,000 feet to 15,000 feet in depth. The Company's participation with Newfield in the development of these offshore reserves was initiated in 1990. The last year of active participation in new leasehold acquisitions with Newfield was 1992, although the Company has continued to participate in the development of the properties where it already owns leases. During 1997, Newfield drilled one successful development well at the South Timbalier 148 field and one unsuccessful exploration well at the South Timbalier 111 field. The Company has aggregate working interests in proved reserves of 11.8 Bcfe in the Gulf of Mexico, of which 96% are proved developed. The Company also has acquired substantial reserves in the Gulf of Mexico under its VPP program. See "-- Volumetric Production Payment Program." Laurel Ridge Field The Company is the operator of this field located in Iberville Parish, Louisiana and has a 26% net revenue interest in 3,773 gross (1,221 net) acres around two discovery wells. The #1 Claiborne Plantation was completed in August 1995 in the Cibicides hazzardi (Frio) sand and the #2 Claiborne Plantation was completed in December 1995 in the shallower Miogyp (Frio) formation. A 3-D seismic program has been shot and is currently being evaluated to identify additional locations. During September 1997, the average production attributable to the Company's interest was 1,340 Mcf of natural gas and 126 bbls of oil per day. 34 35 MID-CONTINENT/WEST TEXAS REGION General In the Mid-Continent/West Texas Region, the Company has active development and exploration drilling programs in the Anadarko, Ardmore, Arklatex, Arkoma, and Permian Basins. Estimated proved reserves in the region were 125,330 MMcfe as of December 31, 1996. The Company has budgeted $30 million for development and exploratory drilling activities in the region during 1998 and expects to have spent $29 million for such activities during 1997. During the nine months ended September 30, 1997, the Company participated in the drilling of 22 gross (16.5 net) development wells and 1 gross (0.9 net) exploratory wells. The Company expects to drill 12 gross (7.5 net) additional development wells and 1 gross (0.4 net) additional exploratory wells by the end of the year. The Company plans to continue to exploit areas of the various basins that require development wells for adequate reserve drainage and intends to drill 40 locations in these areas during 1998. Also, the Company plans to drill two exploratory wells in 1998. 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. The Medallion Acquisition more than doubled the Company's reserve base and rate of oil and gas production and added management and technical expertise, particularly in the new Mid-Continent region. 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 gas (78% of total proved reserves) 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 14% of the Company's proved reserves as of December 31, 1996. As of September 30, 1997, the Company owned interests in 345 gross (309 net) wells, of which it operates 332 gross (309 net) wells. The Company's average working interest in this field was 90%, and its leasehold position at September 30, 1997 consisted of approximately 34,887 gross (34,053 net) acres. During September 1997, the average combined rate of production attributable to the Company's interest was approximately 14,600 Mcf of natural gas and 4 bbls of condensate per day. 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's 51,235 MMcfe of proved reserves attributable to the Sawyer Canyon Field at December 31, 1996 are 97% proved developed. 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 currently plans to drill up to seven additional locations, one of which will be drilled in the fourth quarter of 1997, to exploit the remaining proved undeveloped reserves. The Company also believes that additional proved reserves may ultimately be attributed to many of the 30 or more 40-acre drilling locations remaining on the property. The Company has drilled and is producing one of these additional locations in 1997 and a second location is scheduled to be drilled in the fourth quarter of 1997. In addition to exploiting these Canyon sand development opportunities, the Company intends to continue 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. 35 36 Elm Grove Field The Company's reserve holdings of 17,578 MMcfe in the Elm Grove Field, Bossier Parish, Louisiana represent approximately 5% of the Company's total proved reserves as of December 31, 1996 and are 97% proved developed. 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 September 30, 1997, the Company owned an interest in 29 gross (25 net) wells, of which 27 gross (25 net) were operated by the Company. The Company's operated leasehold position consisted of approximately 5,760 gross (5,545 net) acres. Average daily production from the Elm Grove Field, net to its interest, was approximately 4,400 Mcf of natural gas and 12 bbls of oil during September 1997. The Company has drilled and completed one Cotton Valley well this year and plans to re-fracture one of the thirteen wells drilled by the Company since it first acquired its interest in the field in September 1994. Also, the Company has identified three 2,500-foot Tuscaloosa development locations which it plans to drill in the fourth quarter of this year. The Company has identified several behind pipe zones and plans to drill three to five additional Cotton Valley and Tuscaloosa wells in 1998. OTHER REGIONS Newhall-Potrero Field The Company's Newhall-Potrero Field is located in Los Angeles County, California, outside the city of Valencia. At December 31, 1996, net proved reserves were 12,125 MMcfe, all of which were proved developed. The Company is the operator and owns a 100% working interest in 35 active wells. Average daily production from the area, net to its interest, was approximately 836 Mcf of natural gas and 417 bbls of oil during September 1997. 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 non-operated working interests averaging 19% in 23 active producing wells located in the northern Niagaran Reef trend of Michigan. At December 31, 1996, net proved reserves attributed to these interests were 3,179 MMcf and 231 Mbbls with a total PV-10 of $10.1 million. Of this PV-10 amount, 59% was attributable to three wells in the Mayfield "28" reef and 29% was attributable to five wells in the Hayes "11" reef. During September 1997, daily production net to the Company's interests from all the Michigan wells averaged approximately 95 bbls of oil and 750 Mcf of gas. 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"), which currently operates the majority of the wells in which the Company has an interest. The Company intends to become the operator of these properties on or about January 1, 1998. During 1997, the Company began expanding its involvement in the area by acquiring a 30% working interest 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, where per well cumulative productions have exceeded 450 Mbbls of oil. This project is currently in the final stages of seismic processing, and, following interpretation, the project's operator expects to finalize leasing and embark on a multi-well drilling program that could result in the drilling of 30 or more test wells over the next several years. 36 37 VOLUMETRIC PRODUCTION PAYMENT PROGRAM General The Company augments its working interest ownership of properties with a volumetric production payment ("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 volumetric production payment 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 volumetric production payments 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 is currently not the operator of any of the properties underlying its volumetric production payments, and it does not bear any development or lease operating expenses. The Company intends to become the operator of the properties underlying the Michigan VPP transaction on or about January 1, 1998. After delivery of the oil and gas volumes, the Company arranges for further downstream transportation and sells such volumes to available markets. The Company believes that its VPP program diversifies its reserve base and achieves attractive rates of return while minimizing the Company's exposure to certain development, operating and reserve volume risks. Typically, the estimated proved reserves of the properties underlying a volumetric production payment are substantially greater than the specified reserve volumes required to be delivered pursuant to the production payment. In the three years ended September 30, 1997, the Company had invested $124 million in 25 separate transactions under the VPP program, and had acquired proved reserves of 80,865 MMcfe, consisting of 71,805 MMcf of natural gas and 1,510 Mbbls of oil. This represents an average net acquisition cost of $1.54 per Mcfe, without the burden of development and lease operating expenses. Through September 30, 1997, the Company had recovered approximately $75 million from the sale of oil and gas received under its VPP program. Scheduled for delivery under the VPP program after September 30, 1997 are 42,328 MMcf of gas and 1,008 Mbbls of oil. The Company's unrecovered cost under its VPP program, including future commitments of $10.6 million, is $1.17 per Mcfe. The VPP program accounted for 33,595 MMcfe (10%) of the Company's total proved oil and gas reserves as of December 31, 1996. The properties underlying the VPP program are principally located in two major regions, the Gulf of Mexico and the Niagaran Reef trend in Michigan. During the nine months ended September 30, 1997, the Company invested $45.5 million in 10 separate VPP transactions and acquired 22,805 MMcf of gas and 110 Mbbls of oil. The newly acquired reserves are primarily located in 11 blocks in the offshore Gulf of Mexico. The following table shows, as of September 30, 1997, the oil and gas deliveries to the Company scheduled to be made pursuant to its VPP program over the period from October 1, 1997 through December 31, 2006. Total future net cash flows to the Company from the volumetric production payment deliveries scheduled below are estimated to be $126.6 million, based on spot market prices in effect at September 30, 1997 ($2.57 per MMBtu (Henry Hub) and $17.63 per bbl (Koch WTI EDQ posting), before adjustments for appropriate basis differentials and Btu content).
NATURAL GAS OIL TOTAL % OF PERIOD FROM TO (MMCFE) (MBBLS) (MMCFE) TOTAL ----------- -- ----------- ------- ------- ---------- October 1, 1997 December 31, 1997......... 4,389 87 4,911 10% January 1, 1998 December 31, 1998......... 22,145 386 24,461 51 January 1, 1999 December 31, 1999......... 10,087 173 11,125 23 January 1, 2000 December 31, 2000......... 1,803 109 2,457 5 January 1, 2001 December 31, 2001......... 1,369 75 1,819 4 January 1, 2002 December 31, 2006......... 2,535 178 3,603 7 ------ ----- ------ --- 42,328 1,008 48,376 100% ====== ===== ====== ===
37 38 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, currently operated by Hawkins. The Niagaran Reef reservoirs are typically found at depths between 4,000 and 6,500 feet. The Company intends to become the operator of the properties underlying the Michigan VPP transaction on or about January 1, 1998. Of the remaining 9,187 MMcf and 645 Mbbls to be delivered under the volumetric production payment, the Company is scheduled to receive 603 MMcf and 47 Mbbls during the last three months of 1997, 2,195 MMcf and 162 Mbbls in 1998, with the balance to be delivered between 1999 and 2006. Gulf of Mexico VPP Properties Hall-Houston Oil Company Properties. The Company has acquired interests in 12 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 1994, 1995, 1996 and the first nine months of 1997 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 9,640 MMcf during 1996 and 4,400 MMcf during the nine months ended September 30, 1997 and is scheduled to receive deliveries totaling 2,173 MMcf during the balance of 1997, 7,164 MMcf in 1998, and 4,922 MMcf in 1999. ATP Oil & Gas Properties. The Company has acquired interests in 8 blocks off the coast of Louisiana, one block off the coast of Texas and one onshore property in Texas through volumetric production payment contracts with ATP Oil & Gas Co. of Houston, Texas ("ATP"), which is the operator of all of the blocks. The blocks contain 10 wells drilled during 1996 and the first nine months of 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 427 MMcfe during 1996 and 928 MMcfe during the nine months ended September 30, 1997 and is scheduled to receive deliveries totaling 1,765 MMcfe during the balance of 1997, 13,904 MMcfe in 1998, and 3,791 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. Other VPP Properties The Company is also scheduled to receive deliveries totaling 88 MMcfe during the remainder of 1997 and 352 MMcfe from 1998 to 1999 from several smaller volumetric production payments. EXPLORATION PROGRAM During the three-year period ended December 31, 1996, the Company participated in the drilling of 70 exploratory wells with a 46% success rate. Discoveries included wells in the Langham Creek Area, the Laurel Ridge Field, the Tensas Parish Area and the Manderson Field. During the first nine months of 1997, the Company participated in the drilling of 23 exploratory wells and completed 10 wells. Of the 1997 exploration budget of $25 million, $16.8 million was spent during the nine months ended September 30, 1997. The Company plans to participate in approximately 60 exploratory prospects in 1998, committing approximately 40% of its $30 million 1998 exploration budget to higher risk, higher potential projects. The Company's policy is to commit no more than 25% of its operating cash flow to exploration activities and generally to have no more than a $750,000 dry hole cost exposure for any exploratory well. The Company has established an initial budget of $30 million for exploration in 1998 and intends to participate in drilling a wide variety of prospects, including both moderate-risk and high-risk, high-potential prospects in order to 38 39 maintain a balanced drilling program with the potential for significant reserve additions. During 1998, the Company plans to continue 3-D and 2-D seismic data acquisition and analysis. Exploration activities will focus primarily on properties located in the onshore Gulf Coast regions of Texas and Louisiana and in the Rocky Mountains. Major ongoing exploration projects include the Franklin Deep, Laurel Ridge, Bayou Carlin and Bayou Segnett prospects in south Louisiana; the Langham Creek Deep and Buna Gap prospects in southeast Texas; the Buck prospect in northeast Texas; the Wilde Horse Butte in Wyoming, the Breeze Anticline prospect in Colorado; the Montana Tyler prospect in Montana and the Spearfish and Lodgepole prospects in North Dakota. OIL AND GAS RESERVES All information in this Prospectus relating to estimates of the Company's proved reserves is derived from reports prepared for the Company by Ryder Scott Company, H.J. Gruy and Associates, Inc., R.A. Lenser and Associates, Inc. and Netherland, Sewell and Associates, Inc., each in accordance with the rules and regulations of the SEC. These 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. Although reserve engineers' reports with respect to reserves underlying the Company's VPP program are utilized by the Company to support its own analysis of such reserves, the proved reserves, related future net revenues and PV-10 that the Company reports with respect to volumetric production payments are taken directly from the amounts contracted for pursuant to the VPP agreements (which amounts are substantially less than the net working interest production reflected in the independent reserve engineers' reports). The following table sets forth as of December 31, 1996, the historical summary information with respect to (i) the estimates made by the reserve engineers of the Company's proved oil and gas reserves attributable to working interests plus (ii) the reserve amounts contracted for pursuant to the VPP agreements.
DECEMBER 31, 1996 ------------ PROVED RESERVES: Oil (Mbbls)................................................. 14,631 Natural gas (MMcf).......................................... 268,025 Total (MMcfe).......................................... 355,813 Future net revenues ($000).................................. $849,265 Present value of future net revenues before income taxes ($000).................................................... $557,612 PROVED DEVELOPED RESERVES: Oil (Mbbls)................................................. 12,133 Natural gas (MMcf).......................................... 236,454 Total (MMcfe).......................................... 309,252 Future net revenues ($000).................................. $750,990 Present value of future net revenues before income taxes ($000).................................................... $494,240
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. As of December 31, 1996, spot market gas prices of $3.90 per Mcf (Henry Hub) and $23.38 per bbl (Koch WTI EDQ posting) were in effect. These prices were substantially higher than spot market prices as of September 30, 1997, which were $2.57 per Mcf (Henry Hub) and $17.63 per bbl (Koch WTI EDQ posting). The prices for natural gas and, to a lesser extent, oil, are subject to substantial seasonal fluctuations, and prices for each are subject to substantial fluctuations as a result of numerous other factors. See "Risk Factors -- Volatile Nature of Oil and Gas Markets; Fluctuations in Prices" and "-- Uncertainty of Estimates of Oil and Gas Reserves and Future Net Cash Flows." 39 40 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 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. See "Risk Factors -- Volatile Nature of Oil and Gas Markets; Fluctuations in Prices" and "-- Uncertainty of Estimates of Oil and Gas Reserves and Future Net Cash Flows." ACREAGE The following table sets forth certain information with respect to developed and undeveloped leased acreage of the Company as of September 30, 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. See "-- Volumetric Production Payment Program and Underlying Principal Properties."
DEVELOPED ACRES UNDEVELOPED ACRES ----------------- ----------------- STATE GROSS NET GROSS NET ----- ------- ------- ------- ------- Wyoming........................................ 257,425 207,259 50,548 50,548 Texas.......................................... 122,714 71,157 42,330 22,407 Montana........................................ 85,433 46,938 29,047 22,222 Louisiana...................................... 114,393 27,911 39,857 32,576 Oklahoma....................................... 49,217 19,302 12,006 7,559 Colorado....................................... 27,254 12,946 7,020 5,270 Other.......................................... 64,569 11,639 84,533 26,988 ------- ------- ------- ------- Total................................ 721,005 397,152 265,341 167,570 ======= ======= ======= =======
TITLE TO OIL AND GAS PROPERTIES Substantially all of the Company's property interests not the subject of its VPP program are held pursuant to leases from third parties. A title opinion is typically obtained prior to acquiring these properties. The Company or the relevant operator routinely obtain title opinions on substantially all of the properties that the Company has drilled or participated in drilling. With respect to acquisitions of proved properties, the Company generally obtains updated title opinions covering properties constituting at least 80% of the value of the acquisition, and there are usually older, existing opinions covering the remaining properties. The Company believes that it has satisfactory title to its properties in accordance with standards generally accepted in the oil and gas industry. In addition, the Company's properties are subject to customary royalty interests, overriding royalty interests, liens for current taxes, and other burdens. The Company typically takes the same approach to approving title for volumetric production payments as it does in drilling its own wells or in property acquisitions. The operator will generally have a drilling title opinion or a division order title opinion (on producing wells) for the properties being conveyed. In most cases, the Company will require that the operator update any existing title opinions to reflect the current working interest and net revenue interest subjected to the volumetric production payment conveyed to the Company. By updating the title, any existing mortgages, liens, lawsuits and potential encumbrances will be disclosed. 40 41 Only when the Company believes that it has satisfactory title to the properties in accordance with generally accepted industry standards will the Company proceed with a volumetric production payment. MARKETING OF OIL AND GAS PRODUCTION The Company markets substantially all of the oil and gas production from Company-operated wells and its volumetric production payment volumes to pipelines, local distribution companies and third-party natural gas marketers. The Company believes that its marketing activities add value by giving the Company opportunities to obtain competitive prices for products, minimize pipeline and purchaser balancing problems, maintain continuous sales of production and secure prompt payment. Substantially all of the Company's natural gas is sold under short-term contracts (one year or less) providing for variable or market sensitive prices. The Company sells its oil production in each of its producing regions pursuant to contracts based on postings by major purchasers. The price of natural gas is influenced by supply and demand factors for natural gas in the United States, Mexico and Canada, as well as prices of competing fuels. Average oil prices are reflective of the world oil market during the applicable period. Market prices for oil and gas, which are volatile in nature, have a significant impact on the Company's revenue, net income and cash flow. In connection with the marketing of its oil and gas production, the Company engages in oil and gas price risk management activities primarily through the use of oil and gas futures and options contracts and "fixed for floating" price swap agreements. The Company utilizes oil and gas futures contracts for the purpose of hedging the risks associated with fluctuating oil and gas prices and accounts for such contracts in accordance with FASB Statement No. 80, "Accounting for Futures Contracts." Since these contracts qualify as hedges and correlate to market price movements of oil and gas, any gains or losses resulting from market changes will be offset by losses or gains on corresponding physical transactions. The swap agreements on notional volumes require payments to (or the receipt of payments from) counterparties to such agreements based on the differential between a fixed and variable price for the oil or gas. The Company maintains coverage of such notional volumes with adequate physical volume deliveries at the hub points used to price such arrangements. The Company records these transactions under settlement accounting guidelines and, accordingly, includes gains or losses in oil and gas revenues in the period of the swapped production. The Company intends to continue to consider various risk management arrangements to stabilize cash flow and earnings and reduce the Company's susceptibility to volatility in oil and gas prices. The Company has two separate natural gas price swaps in place as a result of the Medallion Acquisition. For the calendar years 1996, 1997 and 1998, these transactions cover 11.7 million MMBtu, 8.1 million MMBtu and 4.8 million MMBtu of natural gas, respectively, and result in annual weighted average prices per MMBtu of $2.072, $2.020 and $1.983, respectively. SIGNIFICANT CUSTOMER One customer, Tennessee Gas, accounted for approximately 82%, 72% and 40% of the oil and gas revenue for the years ended December 31, 1994, 1995, and 1996, respectively. No other single customer accounted for more than 10% of the Company's consolidated revenue during these periods or in the nine months ended September 30, 1997. Effective January 1, 1997, the Company's contract with Tennessee Gas was terminated. 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. 41 42 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 a 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 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 as a producer or on the Company's natural gas marketing efforts. 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 42 43 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 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 oil and gas leases, which are subject to the regulation of the United States Minerals Management Service ("MMS"). The MMS has issued a notice of proposed rulemaking in which it proposes 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 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 better reflects its market value, establish a new MMS form for collecting differential data, and 43 44 amend the valuation procedure for the sale of federal royalty oil. The Company cannot predict what action the MMS will take on this matter, nor can it predict how the Company will be affected by any change to this regulation. 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 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 44 45 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 and operates a natural gas pipeline and 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 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 45 46 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. LEGAL PROCEEDINGS The Company is a party to three lawsuits involving the holders of royalty interests on the acreage that was covered by the Tennessee Gas Contract. The Company is a co-plaintiff in the first of these lawsuits that was filed in Dallas County, Texas, and is a defendant in two subsequently filed suits in Zapata County, Texas. On May 30, 1997, one of the Zapata County suits was dismissed in connection with a partial settlement with certain of the royalty owners that is discussed below. On October 22, 1997, the other Zapata County suit was dismissed by the court on its own motion, inasmuch as the suit had been abated since September 15, 1995 in favor of the earlier-filed suit in Dallas County. The Dallas County action was instituted to obtain a declaratory judgment that the royalty holders' claim that their royalty payments should be based on the price paid by Tennessee Gas for the natural gas purchased by it under the Tennessee Gas Contract is erroneous. The Company paid royalties for this natural gas produced from the Guerra "A", Guerra "B" and Jesus Yzaguirre Units based upon the spot market price. Because its leases have market-value royalty provisions, the Company believes it is in full compliance under the leases with its royalty holders. Its position has been confirmed in the Dallas County suit, where the trial judge has granted the Company and its co-plaintiffs' motions for summary judgment on this issue. In addition, the Dallas County trial judge has granted summary judgment against the royalty owners with respect to their various counterclaims concerning the Company's Jesus Yzaguirre Unit and the jointly-owned Guerra "A" and Guerra "B" Units. The royalty owners had also counterclaimed against the Company with respect to the Jesus Yzaguirre Unit, alleging (i) that the largest lease contained therein had terminated in December 1975 and (ii) that certain of the royalty owners were entitled to royalties based upon the Tennessee Gas Contract price because of their 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 settled the issue of lease termination, and on June 2, 1997, the trial judge signed an order of dismissal with prejudice as to that issue. On the issue of the effect of the 1992 division orders, the parties filed renewed motions for summary judgment. 46 47 On August 12, 1997, the trial judge signed an order granting the Company's motion and denying the royalty owners' motion. At a hearing on October 29, 1997, the trial judge entered a final judgment in favor of the Company based upon the prior separate summary judgments in favor of the Company's position on the issues and counterclaims involved with the Jesus Yzaguirre Unit lawsuit. The royalty owners in the Guerra "A" and Guerra "B" Units and in the Jesus Yzaguirre Unit have appealed the trial court's decision to the Fifth District Court of Appeals in Dallas, Texas. While the Company believes its positions are meritorious and that it should prevail, there can be no assurance as to the ultimate outcome of these matters. The Company is also party to various other lawsuits and governmental proceedings, all arising in the ordinary course of business. Although the outcome of these lawsuits cannot be predicted with certainty, the Company 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. 47 48 MANAGEMENT EXECUTIVE OFFICERS, DIRECTORS AND CERTAIN KEY EMPLOYEES The following table sets forth the name, age and present position with the Company of each of the Company's executive officers, directors and certain other key employees.
NAME AGE POSITION WITH THE COMPANY ---- --- ------------------------- James W. Christmas....... 49 President, Chief Executive Officer and Director Henry A. Jurand.......... 48 Senior Vice President, Chief Financial Officer and Secretary C.R. Devine.............. 51 Vice President, Oil and Gas Operations; President, KCS Resources, Inc. Frederick Dwyer.......... 37 Vice President and Controller Kathryn M. Kinnamon...... 33 Vice President, Treasurer and Asst. Secretary Harry Lee Stout.......... 49 President, KCS Energy Services, Inc. Gene C. Daley............ 47 President, KCS Medallion Resources, Inc. J. Chris Jacobsen........ 42 Senior Vice President, KCS Medallion Resources, Inc. Dan A. Magee............. 55 Vice President, KCS Resources, Inc. d/b/a KCS Mountain Resources, Inc. G. Stanton Geary......... 63 Director Stewart B. Kean.......... 63 Director and Chairman of the Board James E. Murphy, Jr. .... 41 Director Robert G. Raynolds....... 45 Director Joel D. Siegel........... 55 Director Christopher A. Viggiano............... 43 Director
James W. Christmas has served as President and Chief Executive Officer and as a director of the Company since its inception in 1988. Prior to joining the Company, Mr. Christmas spent ten years with NUI Corporation, serving in a variety of officer capacities and as President of several of its subsidiaries. While Mr. Christmas was Vice President of Planning of NUI Corporation, he was in charge of the spin-off of its non-regulated businesses that resulted in the formation of KCS Energy, Inc. Mr. Christmas began his career with Arthur Andersen & Co. Henry A. Jurand was appointed Senior Vice President in March 1997. He has served as Chief Financial Officer since January 1996, Vice President of the Company from September 1990 to March 1997, as Treasurer from March 1991 to December 1995, and as Secretary since February 1992. From 1988 to 1990, he was a Senior Vice President of Private Capital Partners, Inc., in New York City. From 1977 to 1988, he was employed by Baltimore Gas and Electric Company, holding management positions including Vice President and Chief Financial Officer of Constellation Holdings, Inc., a subsidiary, and President of Constellation Investments, Inc. On September 15, 1997, Mr. Jurand announced his retirement from the Company, effective December 31, 1997, to pursue a career in academia. The Company has initiated a search for his successor. C. R. Devine was named Vice President, Oil and Gas Operations of the Company in December 1992 and President of KCS Resources, Inc., a subsidiary of the Company engaged in oil and gas exploration and production, in December 1993. He has served as principal operating officer of the Company's oil and gas operations since 1988. He has been employed by the Company and its predecessor companies since 1974. Frederick Dwyer was appointed Vice President and Controller of the Company in March 1997. He served as Assistant Vice President and Controller from May 1996 to March 1997. He joined the Company upon its formation in 1988, holding various management and supervisory positions. He is a certified public accountant and began his career with Peat, Marwick, Mitchell & Co. Kathryn M. Kinnamon was appointed Vice President and Treasurer of the Company in March 1997. She served as Treasurer since January 1996, as Assistant Vice President from May 1996 to March 1997 and as Assistant Treasurer from May 1991 to December 1995. She joined the Company upon its formation in 1988, holding various management and supervisory positions. 48 49 Harry Lee Stout has served as President of KCS Energy Marketing, Inc., the Company's subsidiary, since joining the Company in August 1991. In September 1996, he was named President of KCS Energy Services, Inc., the subsidiary of the Company engaged in the volumetric production payment program. From 1990 to 1991, he was Vice President of Minerex Corporation in Houston, Texas. From 1978 to 1990, he was employed by Enron Corp. of Houston, Texas, holding various management positions including Senior Vice President of Houston Pipe Line Company and Executive Vice President, Enron Gas Marketing Company, both of which are subsidiaries of Enron Corp. Gene C. Daley was named President of KCS Medallion Resources, Inc. in December 1997. He previously served as Senior Vice President, Exploration and Development of KCS Medallion Resources, Inc. (formerly InterCoast Oil and Gas Company) since 1991. Prior to joining InterCoast he served as President of Carter Resources, Inc. from its inception in 1974 until its acquisition by InterCoast in 1991. From 1972 to 1974 he was an offshore exploration geologist for Texaco, Inc. J. Chris Jacobsen has served as Senior Vice President, Exploration, Development and Reserves of KCS Medallion Resources, Inc. since 1994 and also has responsibility as director of reservoir engineering for all of the Company. From 1982 to 1994 he was Senior Vice President of Netherland, Sewell & Associates. From 1977 to 1982 he was employed by Exxon Company U.S.A. holding various engineering and supervisory positions. Dan A. Magee has served as Vice President of KCS Resources, Inc., d/b/a KCS Mountain Resources, Inc. since May 1996. Prior to May 1996 he was a consultant to KCS Resources, Inc. in connection with acquisition activities beginning May 1995. From 1992 to 1995 he was a consulting engineer and Manager of Acquisitions at Hanson Production Company. From 1974 to 1992 he was the Production, Drilling and Operations Manager for Edwin L. Cox and Cox Oil & Gas, Inc. G. Stanton Geary has served as a director of the Company since 1988. He is proprietor of Gemini Associates, Pomfret, Connecticut, a venture capital consulting firm, and business manager of the Rectory School, Pomfret, Connecticut. Stewart B. Kean has served as Chairman of the Board of Directors of the Company since 1988. He was President of Utility Propane Company, a former subsidiary of the Company, from 1965 to 1989. He is past President of the National LP Gas Association and past President of the World LP Gas Forum. He currently serves as President of the Liberty Hall Foundation. Mr. Kean is Robert G. Raynolds' uncle. James E. Murphy, Jr. has served as a director of the Company since 1988. Mr. Murphy heads his own political and governmental relations consulting firm offering strategic planning and management consulting services to Republican candidates nationwide, with extensive experience at the presidential, state and congressional levels. Based in Gaithersburg, Maryland, he also advises corporations and industry groups on strategic planning, governmental relations and grassroots lobbying projects. Robert G. Raynolds has served as a director of the Company since August 1995. He has been an independent consulting geologist for several major and independent oil and gas companies from 1992 until the present and was a geologist with Amoco Production Company from 1983 until 1992. Mr. Raynolds is Stewart B. Kean's nephew. Joel D. Siegel has served as a director of the Company since 1988. He is an attorney-at-law and has been President of the law firm, Orloff, Lowenbach, Stifelman & Siegel, P.A. of Roseland, New Jersey, since 1975. Orloff, Lowenbach, Stifelman & Siegel, P.A. serves as outside legal counsel to the Company. Mr. Siegel served as President and Chief Executive Officer of Constellation Bancorp, Elizabeth, New Jersey, and Constellation Bank, Elizabeth, New Jersey, for the period April 26, 1991 to December 6, 1991. Christopher A. Viggiano has served as a director of the Company since 1988. Mr. Viggiano has been President, Chairman of the Board and majority owner of O'Bryan Glass Corp., Queens, New York, since December 1, 1991, and served as Vice President and a member of the board of directors of O'Bryan Glass Corp. from 1985 to December 1, 1991. He is a Certified Public Accountant. 49 50 SECURITY OWNERSHIP BY CERTAIN BENEFICIAL OWNERS AND MANAGEMENT As of September 30, 1997, there were 29,394,894 shares of the Company's Common Stock outstanding. These shares were held by 1,149 holders of record. The following table sets forth information as to the number and percentage of shares owned beneficially as of September 30, 1997 by each executive officer and director of the Company, by all executive officers and directors as a group and by each person known by the Company to be a beneficial owner of more than 5% of the Company's Common Stock.
SHARES OWNED PERCENT BENEFICIALLY(1) OF CLASS --------------- -------- James W. Christmas...................................... 1,007,023(2)(3) 3.4% C. R. Devine............................................ 116,869(2) * Henry A. Jurand......................................... 37,615(2) * Frederick Dwyer......................................... 7,794(2) * Kathryn M. Kinnamon..................................... 3,712(2) * Harry Lee Stout......................................... 61,724(2) * G. Stanton Geary........................................ 12,654(2) * Stewart B. Kean......................................... 2,761,829(2)(4) 9.4% James E. Murphy, Jr..................................... 30,884(2) * Robert G. Raynolds...................................... 7,160(2) * Joel D. Siegel.......................................... 191,388(2)(5) * Christopher A. Viggiano................................. 58,388(2) * Executive officers and directors as a group (12 persons).............................................. 4,297,040 14.3% Metropolitan Life Insurance Company(6).................. 3,361,000 11.4% One Madison Avenue New York, New York 10010 Warburg, Pincus Counsellors, Inc........................ 1,918,100 6.5% 466 Lexington Avenue New York, New York 10017
- --------------- * Less than 1% (1) Unless otherwise indicated, beneficial owner has sole voting and investment power. (2) Includes shares that (i) may be purchased as a result of options granted that are exercisable within 60 days of November 1, 1997 of 600,000, 27,500, 17,500, 30,000 and 200 for Messrs. Christmas, Devine, Jurand, Stout, and Dwyer, respectively; 200 for Ms. Kinnamon; 8,000 each for Messrs. Geary, S.B. Kean, Murphy, Siegel and Viggiano and 4,000 for Mr. Raynolds and (ii) are allocated to the beneficial owner's account under 401(k) plans. (3) Includes 36,000 shares held in trusts established for the benefit of Mr. Christmas' children, the beneficial ownership of which is disclaimed by Mr. Christmas. (4) Includes 1,025,648 shares held under certain family trusts as to which Mr. Kean shares voting and investment power. (5) Includes 16,000 shares held in trusts established for the benefit of Mr. Siegel's children, the beneficial ownership of which is disclaimed by Mr. Siegel. (6) Includes 3,337,600 shares (11.4%) owned by an affiliate of Metropolitan Life Insurance Company, State Street Research and Management Company, One Financial Center, 30th Floor, Boston, Massachu- setts 02111. In December 1994, the Board of Directors adopted a policy requiring minimum levels of ownership of the Company's Common Stock by its directors and by executive officers of the Company and its subsidiaries. Within a four-year period, directors are required to become beneficial owners of Common Stock with a market value equivalent to four times their annual retainer. During such period, the president and chief executive officer must become the owner of Common Stock with a market value of four times his annual base salary. For 50 51 vice presidents of the Company and presidents of subsidiaries, the multiple of annual base salary is two and one-half times and for vice presidents of subsidiaries it is one-half. DESCRIPTION OF EXISTING INDEBTEDNESS The Company and certain of its subsidiaries borrow funds for working capital and property acquisitions from several banks under two Bank Credit Facilities. The following summaries of the Credit Facility and Revolving Credit Agreement do not purport to be complete and are subject to, and qualified in their entirety by reference to the applicable credit agreements. The lenders under the Bank Credit Facilities have provided waivers or consents as the Company has determined to be necessary to permit the issuance of the Notes. CREDIT FACILITY Certain subsidiaries of the Company are borrowers under the Credit Facility with a group of banks which provides for revolving credit and letters of credit for up to $150 million in the aggregate (the "Commitment Amount"). The Credit Facility matures on September 30, 2000. The actual amount available for borrowing under the Credit Facility is determined by a fluctuating borrowing base (the "Borrowing Base") that is a function of a periodic valuation by the lenders of the borrowers' oil and gas reserves. The amount of credit available to the borrowers under the Credit Facility is the lesser of the Borrowing Base or the Commitment Amount. The Borrowing Base is currently $75 million. Although the oil and gas reserves pledged as collateral under the Credit Facility may support borrowings greater than $75 million, the Senior Notes Indenture effectively limits the borrowing base under this facility to the greater of $75 million or 15% of adjusted consolidated net tangible assets (as defined in the Senior Notes Indenture). Repayment of principal under the Credit Facility is required to the extent the aggregate amount of borrowing and letters of credit outstanding exceeds the Borrowing Base as calculated from time to time. The obligations of the borrowers under the Credit Facility are secured by first liens on (a) those oil and gas properties owned by the borrowers which are included in the calculation of the Borrowing Base and on the hydrocarbon production from those oil and gas properties and (b) the other assets of the borrowers, including accounts receivable, inventory and machinery and equipment related to the oil and gas properties. Commitment fees of 3/8 of 1% per annum are paid on the difference between the amount actually borrowed and the lesser of the Commitment Amount and the Borrowing Base. The borrowers have the option of borrowing at the following rates of interest per annum (subject to immaterial adjustments): (i) the prime rate, plus a spread ranging from 0% to 0.50%, (ii) the London Interbank Offered Rate ("LIBOR") plus a spread ranging from 0.625% to 1.50%. The spread under each alternative rate is determined quarterly based upon the consolidated debt-to-EBITDA ratio of the Company and its subsidiaries. At December 26, 1997, there was $74.5 million outstanding under the Credit Facility. To the extent that the lenders have a commitment to make advances under the Credit Facility, or outstanding indebtedness exists under the Credit Facility, the borrowers may not incur or have outstanding any other indebtedness, except as expressly permitted by the credit agreement. The credit agreement permits the borrowers to incur indebtedness to the Company and other subsidiaries of the Company under certain circumstances, to incur obligations under oil and gas leases entered into in the ordinary course of business, to continue to pay in accordance with their terms certain specified indebtedness, to incur indebtedness of up to $1 million which otherwise would be prohibited under the Credit Facility and to incur purchase money indebtedness and indebtedness under equipment leases, the aggregate outstanding principal balance of which does not exceed $1 million at any time. Other covenants and provisions in the Credit Facility prohibit or restrict, among other things, the borrowers' ability to (a) encumber its assets; (b) enter into negative pledge agreements with respect to its assets; (c) merge or consolidate; (d) dissolve or liquidate; (e) amend its corporate charter or corporate structure, activities or nature in any manner which could have a material adverse effect; (f) become a general partner, joint venturer or venturer with respect to any transaction except 51 52 joint operating agreements, exploration agreements and similar arrangements, containing customary terms and entered into in the ordinary course of business; (g) declare or pay certain dividends or make certain payments on account of capital stock or redeem, retire or otherwise acquire for value any of its capital stock at any time an Event of Default exists; (h) make any distribution of assets; (i) repay any indebtedness to the Company or any affiliate of the Company at any time an Event of Default exists, except for certain inter-company indebtedness specified in the Credit Facility; (j) lend money or acquire any securities, other than a fractional undivided interest in oil and gas properties, obligations of the United States of America, certificates of deposit and other institutional debt obligations, certain specified loans and advances, advances in accordance with the Company's cash management program and repurchase agreements (within specified limits); (k) enter into transactions with an affiliate on terms less favorable to the Company than would be available in a comparable arms-length transaction; (l) sell or otherwise dispose of assets except in the ordinary course of business; (m) enter into sale-leaseback transactions; and (n) prepay any debt. Events of default under the Credit Facility include, among other things, (a) a failure of the borrowers to pay principal, interest or any other payment due under the Credit Facility; (b) certain defaults in respect of other indebtedness; (c) a material breach of any representation or warranty; (d) a breach of certain agreements and covenants, including all negative covenants, contained in the Credit Facility; (e) a breach of any other covenants in the Credit Facility which has not been cured within 30 days; (f) a failure by the Company to perform, observe or comply with the negative covenants and financial covenants contained in the Company's guaranty described below, (g) certain acts of bankruptcy, insolvency or dissolution and (h) the rendering of a final judgment in excess of $2.5 million that is not discharged or stayed within a specified period. The Company has guaranteed the obligations of its subsidiary borrowers under the Credit Facility pursuant to a Guaranty Agreement. This guaranty prohibits or restricts, among other things, the Company's ability to (a) merge or consolidate, (b) dissolve or liquidate, (c) amend its corporate charter or corporate structure, activities or nature in any manner which could have a material adverse effect and (d) pay dividends in excess of 50% of Consolidated Net Income (as defined in the guaranty) for the period from September 30, 1993 to the time such dividend is paid. Additionally, the guaranty requires that (a) the Company and its subsidiaries on a consolidated basis maintain a minimum Consolidated Tangible Net Worth (as defined in the guaranty), and (b) the Company and its subsidiaries on a consolidated basis maintain a minimum EBITDA to interest expense ratio. The Company is currently in compliance with all such covenants. REVOLVING CREDIT AGREEMENT In January 1997, simultaneous with the consummation of the Medallion Acquisition, the Company and certain of its subsidiaries entered into the Revolving Credit Agreement with a group of banks. The Revolving Credit Agreement will mature September 30, 2000. The amount of credit available at any time under the Revolving Credit Agreement is the lesser of (i) the maximum credit commitment of $150 million (the "Revolving Commitment Amount") and (ii) the aggregate amount of indebtedness (the "Revolving Borrowing Base") which can be supported by the lenders' evaluation of the oil and gas reserves attributable to the oil and gas properties pledged as collateral to the lenders. In addition to the oil and gas properties, the stock of the subsidiaries acquired in the Medallion Acquisition were also pledged as collateral. The Revolving Borrowing Base is currently set at $90 million. Commitment fees of 3/8 of 1% per annum are paid on the difference between the amounts actually borrowed and the lesser of the Revolving Commitment Amount and the Revolving Borrowing Base. The borrowers have the option of borrowing at the following rates of interest per annum (subject to immaterial adjustments): (i) the prime rate, plus a spread ranging from 0% to 0.625%, (ii) the LIBOR plus a spread ranging from 0.75% to 1.625%. The spread under each alternative rate is determined quarterly based upon the consolidated debt-to-EBITDA ratio of the Company and its subsidiaries. At December 26, 1997, there was $66.1 million outstanding under the Revolving Credit Agreement, not including $0.5 million reserved for existing letters of credit. 52 53 The Revolving Credit Agreement includes customary affirmative and negative covenants which, among other things, require the meeting of certain financial tests and limit the borrowers with respect to incurrence of additional indebtedness, liens, mergers, consolidation or changes in its corporate structure, dividends, loans, transactions with affiliates, disposition of assets and sale and leaseback agreements similar to those described above with respect to the Credit Facility. The borrowers are currently in compliance with all such covenants. Events of default under the Revolving Credit Agreement include, among other things, (a) a failure of the borrowers to pay principal, interest or any other payment due under the Credit Facility; (b) certain defaults in respect of other indebtedness; (c) a material breach of any representation or warranty; (d) a breach of certain agreements and covenants, including all negative covenants, contained in the Credit Facility; (e) a breach of any other covenants in the Credit Facility which has not been cured within 30 days; (f) a failure by the Company to perform, observe or comply with the negative covenants and financial covenants contained in the Company's guaranty described below; (g) certain acts of bankruptcy, insolvency or dissolution and (h) the rendering of a final judgment in excess of $2.5 million that is not discharged or stayed within a specified period. 11% SENIOR NOTES DUE 2003 In January 1996, the Company privately offered and sold $150,000,000 aggregate principal amount at maturity of 11% Senior Notes due 2003, Series A, pursuant to the Senior Notes Indenture between the Company and State Street Bank and Trust Company (as successor trustee to Fleet National Bank of Connecticut). Subsequent to the private offering and sale of the original senior notes, the Company filed a Registration Statement with the Commission and exchanged such original senior notes for 11% Senior Notes due 2003, Series B ("Senior Notes"), of the Company with terms substantially identical to such notes, except that the new securities did not contain transfer restrictions on the resale of such securities. Interest on the Senior Notes is payable on January 15 and July 15 of each year. Such payment commenced on July 15, 1996. The Senior Notes are redeemable at the option of the Company, in whole or in part, at anytime on or after January 15, 2000, at the redemption prices set forth in the Senior Notes Indenture, together with accrued interest to the date of redemption. In the event the Company consummates a Public Equity Offering (as defined in the Senior Notes Indenture) on or prior to January 15, 1999, the Company may at its option use all or a portion of the proceeds from such offering to redeem up to $35 million principal amount of the Senior Notes at a redemption price equal to 111% of the aggregate principal amount thereof, together with accrued interest to the date of redemption, provided that at least $115 million in aggregate principal amount of Senior Notes remains outstanding immediately after such redemption. The Senior Notes are unconditionally guaranteed on a senior unsecured basis by each of the Company's current and certain of the Company's future subsidiaries, and such subsidiary guarantees rank pari passu in right of payment with all existing and future senior indebtedness of the subsidiary guarantors and senior to all subordinated indebtedness of the subsidiary guarantors. The Senior Notes are senior unsecured obligations of the Company ranking pari passu in right of payment with all existing and future senior indebtedness of the Company and senior to all subordinated indebtedness of the Company. The Senior Notes and the subsidiary guarantees, however, are effectively subordinated to secured indebtedness of the Company and the subsidiary guarantors, respectively, with respect to the assets securing such indebtedness, including indebtedness of certain subsidiary guarantors under the Bank Credit Facilities which is secured by liens on substantially all of the assets of such subsidiary guarantors and guaranteed by the Company. Upon the occurrence of a Change of Control (as defined in the Senior Notes Indenture), each holder of Senior Notes will have the right to require the Company to purchase all or a portion of such holder's Senior Notes at a price equal to 101% of the aggregate principal amount thereof, together with accrued interest to the date of purchase. 53 54 The Senior Notes Indenture contains certain covenants, including covenants which limit: (i) indebtedness; (ii) restricted payments; (iii) issuances and sales of capital stock of restricted subsidiaries; (iv) sale/leaseback transactions; (v) transactions with affiliates; (vi) liens; (vii) asset sales; (viii) dividends and other payment restrictions affecting restricted subsidiaries; (ix) conduct of business; and (x) mergers, consolidations and sales of assets. In addition, the Senior Notes Indenture includes various circumstances that will constitute, upon occurrence and subject in certain cases to notice and grace periods, an event of default thereunder. DESCRIPTION OF THE NOTES The Notes will be issued under an indenture (the "Indenture") to be entered into among the Company, as issuer, KCS Resources, Inc., KCS Michigan Resources, Inc., KCS Energy Marketing, Inc., KCS Medallion Resources, Inc., KCS Energy Services, Inc., Medallion California Properties Co., Medallion Gas Services, Inc., National Enerdrill Corporation and Proliq, Inc., as Subsidiary Guarantors, and State Street Bank and Trust Company, as trustee (the "Trustee"). The Indenture will be subject to and governed by the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act"). The following summary of certain provisions of the Indenture does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all of the provisions of the Indenture, including the definitions of certain terms contained therein and those terms that are made a part of the Indenture by reference to the Trust Indenture Act. A form of the Indenture is filed as an exhibit to the Registration Statement of which this Prospectus is a part. Capitalized terms not otherwise defined below or elsewhere in this Prospectus have the meanings given to them in the Indenture. The definitions of certain capitalized terms used in the following summary are set forth below under "-- Certain Definitions." The Indenture will provide for the issuance of up to $125 million of Notes in connection with the Offering (the "Offered Notes"). The Indenture will also provide the Company the flexibility of issuing up to $25 million of additional Notes in the future; however, any issuance of such additional Notes would be subject to the covenant described under "-- Certain Covenants -- Limitation on Indebtedness and Disqualified Capital Stock." The Offered Notes and any such additional Notes are collectively referred to as the "Notes" in this "Description of the Notes." As used in this "Description of the Notes," the term "Company" refers only to KCS Energy, Inc. GENERAL The Offered Notes will be unsecured senior subordinated obligations of the Company limited to $125 million aggregate principal amount. The Notes will be issued only in registered form, without coupons, in denominations of $1,000 and integral multiples thereof. Principal of, premium, if any, and interest on the Notes will be payable at the office or agency of the Company in the City of New York maintained for such purpose, and the Notes may be surrendered for transfer or exchange at the corporate trust office of the Trustee. In addition, in the event the Notes do not remain in book-entry form, interest may be paid, at the option of the Company, by check mailed to the Holders of the Notes at their respective addresses as shown on the Note Register, subject to the right of any Holder of Notes in the principal amount of $500,000 or more to request payment by wire transfer. No service charge will be made for any transfer, exchange or redemption of the Notes, but the Company or the Trustee may require payment of a sum sufficient to cover any tax or other governmental charge that may be payable in connection therewith. The obligations of the Company under the Notes will be guaranteed on a senior subordinated basis by the Subsidiary Guarantors. See "-- Subsidiary Guarantees of Notes." MATURITY, INTEREST AND PRINCIPAL PAYMENTS The Notes will mature on January 15, 2008. Interest on the Notes will accrue from January 21, 1998 at the rate of 8 7/8% per annum and will be payable semiannually in cash on January 15 and July 15 of each year, commencing July 15, 1998, to the Persons in whose name the Notes are registered in the Note Register at the close of business on January 1 or July 1 next preceding such interest payment date. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months. 54 55 REDEMPTION Optional Redemption. The Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after January 15, 2003, upon not less than 30 or more than 60 days' notice, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, to the date of redemption (subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the date of redemption), if redeemed during the 12-month period beginning on January 15 of the years indicated below:
REDEMPTION YEAR PRICE - ---- ---------- 2003............................................... 104.438% 2004............................................... 102.958% 2005............................................... 101.479% 2006 and thereafter................................ 100.00%
In the event that less than all of the Notes are to be redeemed, the particular Notes (or any portion thereof that is an integral multiple of $1,000) to be redeemed shall be selected not less than 30 nor more than 60 days prior to the date of redemption by the Trustee, from the outstanding Notes not previously called for redemption, pro rata, by lot or by any other method the Trustee shall deem fair and appropriate. Notwithstanding the foregoing, at any time on or prior to January 15, 2001, up to 33 1/3% of the aggregate principal amount of Notes originally issued will be redeemable, at the option of the Company, from the Net Cash Proceeds of a Public Equity Offering, at a redemption price equal to 108.875% of the principal amount thereof, together with accrued and unpaid interest to the date of redemption, provided that at least 66 2/3% of the aggregate principal amount of Notes originally issued remains outstanding immediately after such redemption and that such redemption occurs within 60 days following the closing of such Public Equity Offering. Offers to Purchase. As described below, (a) upon the occurrence of a Change of Control, the Company will be obligated to make an offer to purchase all outstanding Notes at a purchase price equal to 101% of the principal amount thereof, together with accrued and unpaid interest, if any, to the date of purchase and (b) upon certain sales or other dispositions of assets, the Company may be obligated to make offers to purchase Notes with a portion of the Net Available Proceeds of such sales or other dispositions at a purchase price equal to 100% of the principal amount thereof, together with accrued and unpaid interest, if any, to the date of purchase. See " -- Certain Covenants -- Change of Control" and " -- Limitation on Asset Sales." SUBORDINATION The payment of principal of, premium, if any, and interest, on the Notes and any other payment obligations of the Company in respect of the Notes (including any obligation to repurchase the Notes) will be subordinated in certain circumstances in right of payment, as set forth in the Indenture, to the prior payment in full of the Senior Notes and all other Senior Indebtedness of the Company, whether outstanding on the date of the Indenture or thereafter incurred. The Subsidiary Guarantees will also be subordinated (to the same extent and in the same manner as the Notes are subordinated to Senior Indebtedness of the Company) to the prior payment in full of all Senior Indebtedness of the Subsidiary Guarantors. See "-- Subsidiary Guarantees of Notes." As of September 30, 1997, Senior Indebtedness of the Company and the Subsidiary Guarantors on a consolidated basis was approximately $276.2 million. The Notes and the Subsidiary Guarantees will rank prior in right of payment only to other Indebtedness of the Company or the Subsidiary Guarantors, as the case may be, which is expressly subordinated in right of payment to the Notes or the Subsidiary Guarantees, as the case may be. There is currently no Indebtedness of the Company or any Subsidiary Guarantor which would constitute such Subordinated Indebtedness. Subject to certain limitations, the Company and its Subsidiaries may incur additional Indebtedness (including Senior Indebtedness) in the future. See " -- Certain Covenants -- Limitation on Indebtedness and Disqualified Capital Stock." Upon any distribution to creditors of the Company in a liquidation or dissolution of the Company or in a bankruptcy, reorganization, insolvency, receivership or similar proceeding relating to the Company or its 55 56 property, an assignment for the benefit of creditors or any marshaling of the Company's assets and liabilities, the holders of Senior Indebtedness will be entitled to receive payment in full of all amounts due in respect of such Senior Indebtedness (including interest after the commencement of any such proceeding at the rate specified in the applicable Senior Indebtedness) before the Holders of Notes will be entitled to receive any payment with respect to the Notes, and until all amounts due with respect to Senior Indebtedness are paid in full, any distribution to which the Holders of Notes would be entitled shall be made to the holders of Senior Indebtedness (except that Holders of Notes may receive securities that are subordinated at least to the same extent as the Notes to Senior Indebtedness of the Company and any securities issued in exchange for Senior Indebtedness of the Company and Holders of Notes may also receive payments made from the trust described under "-- Legal Defeasance or Covenant Defeasance of Indenture"). The Company also may not make any payment upon or in respect of the Notes (except in such subordinated securities or from the trust described under "-- Legal Defeasance or Covenant Defeasance of Indenture") if (i) a default in the payment of the principal of, premium, if any, or interest on Designated Senior Indebtedness of the Company occurs and is continuing beyond any applicable period of grace or (ii) any other default occurs and is continuing with respect to Designated Senior Indebtedness of the Company that permits, or with the giving of notice or passage of time or both (unless cured or waived) will permit, holders of the Designated Senior Indebtedness as to which such default relates to accelerate its maturity and the Trustee receives a notice of such default (a "Payment Blockage Notice") from the Company or the holders of any Designated Senior Indebtedness of the Company. Payments on the Notes shall be resumed (a) in the case of a payment default, upon the earliest of the date on which such default is cured or waived or holders of such Designated Senior Indebtedness agree to such resumption or such Designated Senior Indebtedness has been repaid in full and (b) in case of a nonpayment default, the earliest of the date on which such nonpayment default is cured or waived or holders of such Designated Senior Indebtedness agree to such resumption or such Designated Senior Indebtedness has been repaid in full or 179 days after the date on which the applicable Payment Blockage Notice is received, unless the maturity of any Designated Senior Indebtedness of the Company has been accelerated (and such acceleration has not been rescinded or annulled). No new period of payment blockage in the case of a nonpayment default may be commenced unless and until (i) 360 days have elapsed since the date of commencement of the immediately prior Payment Blockage Notice period and (ii) all scheduled payments of principal, premium, if any, and interest on the Notes that have come due have been paid in full in cash. No nonpayment default that existed or was continuing on the date of delivery of any Payment Blockage Notice to the Trustee shall be, or be made, the basis for a subsequent Payment Blockage Notice, unless such default has been cured or waived for a period of not less than 90 consecutive days commencing after the date of delivery of such Payment Blockage Notice. In no event will a payment blockage period in the case of a nonpayment default extend beyond 179 days from the date of the receipt by the Trustee of the notice and there must be a 181 consecutive day period in any 360-day period during which no such payment blockage period is in effect. In the event that, notwithstanding the foregoing, the Company makes any payment or distribution to the Trustee or the Holder of any Note prohibited by the subordination provisions of the Indenture, then such payment or distribution will be required to be paid over and delivered forthwith to the holders (or their representative) of Designated Senior Indebtedness of the Company. If the Company fails to make any payment on the Notes when due or within any applicable grace period, whether or not on account of the payment blockage provisions described above, such failure would constitute an Event of Default under the Indenture and would enable the Holders of the Notes to accelerate the maturity thereof. See "-- Events of Default." The Indenture will further require that the Company promptly notify holders of Senior Indebtedness if payment of the Notes is accelerated because of an Event of Default. As a result of the subordination provisions described above, in the event of a liquidation or insolvency of the Company, Holders of Notes may recover less ratably than creditors of the Company who are holders of Senior Indebtedness, and funds which would be otherwise payable to the Holders of the Notes will be paid to the holders of the Senior Indebtedness of the Company to the extent necessary to pay such Senior Indebtedness in full, and the Company may be unable to meet its obligations in full with respect to the Notes. 56 57 SUBSIDIARY GUARANTEES OF NOTES Each Subsidiary Guarantor will unconditionally guarantee, jointly and severally, to each Holder and the Trustee, the full and prompt performance of the Company's obligations under the Indenture and the Notes, including the payment of principal of, premium, if any, and interest on the Notes pursuant to its Subsidiary Guarantee. The initial Subsidiary Guarantors are currently all of the Company's subsidiaries. In addition to the initial Subsidiary Guarantors, the Company is obligated under the Indenture to cause each Restricted Subsidiary that becomes, or comes into existence as, a Restricted Subsidiary after the date of the Indenture and has assets, businesses, divisions, real property or equipment with a fair market value (as determined in good faith by the Board of Directors of the Company) in excess of $1 million to execute and deliver a supplement to the Indenture pursuant to which such Restricted Subsidiary will guarantee the payment of the Notes on the same terms and conditions as the Subsidiary Guarantees by the initial Subsidiary Guarantors. The Subsidiary Guarantee of each Subsidiary Guarantor will be unsecured and subordinated (to the same extent and in the same manner as the Notes are subordinated to Senior Indebtedness of the Company) to the prior payment in full of all Senior Indebtedness of such Subsidiary Guarantor. The obligations of each Subsidiary Guarantor will be limited to the maximum amount as will, after giving effect to all other contingent and fixed liabilities of such Subsidiary Guarantor and after giving effect to any collections from or payments made by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Subsidiary Guarantee or pursuant to its contribution obligations under the Indenture, result in the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law. Each Subsidiary Guarantor that makes a payment or distribution under a Subsidiary Guarantee shall be entitled to a contribution from each other Subsidiary Guarantor in a pro rata amount based on the Adjusted Net Assets of each Subsidiary Guarantor. Each Subsidiary Guarantor may consolidate with or merge into or sell or otherwise dispose of all or substantially all of its properties and assets to the Company or another Subsidiary Guarantor without limitation, except to the extent any such transaction is subject to the "Merger, Consolidation and Sale of Assets" covenant of the Indenture. Each Subsidiary Guarantor may consolidate with or merge into or sell all or substantially all of its properties and assets to a Person other than the Company or another Subsidiary Guarantor (whether or not affiliated with the Subsidiary Guarantor), provided that (a) if the surviving Person is not the Subsidiary Guarantor, the surviving Person agrees to assume such Subsidiary Guarantor's Subsidiary Guarantee and all its obligations pursuant to the Indenture (except to the extent the following paragraph would result in the release of such Subsidiary Guarantee) and (b) such transaction does not (i) violate any of the covenants described below under "-- Certain Covenants" or (ii) result in a Default or Event of Default immediately thereafter that is continuing. Upon the sale or other disposition (by merger or otherwise) of a Subsidiary Guarantor (or all or substantially all of its properties and assets) to a Person other than the Company or another Subsidiary Guarantor and pursuant to a transaction that is otherwise in compliance with the Indenture (including as described in the foregoing paragraph), such Subsidiary Guarantor shall be deemed released from its Subsidiary Guarantee and the related obligations set forth in the Indenture; provided, however, that any such release shall occur only to the extent that all obligations of such Subsidiary Guarantor under all of its guarantees of, and under all of its pledges of assets or other security interests which secure, other Indebtedness of the Company or any Restricted Subsidiary shall also be released upon such sale or other disposition. Each Subsidiary Guarantor that is designated as an Unrestricted Subsidiary in accordance with the Indenture shall be released from its Subsidiary Guarantee and related obligations set forth in the Indenture for so long as it remains an Unrestricted Subsidiary. Separate financial statements of the Subsidiary Guarantors have not been provided because the Subsidiary Guarantors are jointly and severally liable for the obligations of the Company under the Notes and the aggregate assets, earnings and equity of the Subsidiary Guarantors are substantially equivalent to the consolidated assets, earnings and equity of the Company. 57 58 CERTAIN COVENANTS The Indenture will contain, among others, the covenants described below. Limitation on Indebtedness and Disqualified Capital Stock. The Company will not, and will not permit any of its Restricted Subsidiaries to, create, incur, issue, assume, guarantee or in any manner become directly or indirectly liable for the payment of (collectively, "incur") any Indebtedness (including any Acquired Indebtedness but excluding any Permitted Indebtedness) or any Disqualified Capital Stock, unless, on a pro forma basis after giving effect to such incurrence and the application of the proceeds therefrom, the Consolidated EBITDA Coverage Ratio for the four full quarters immediately preceding such event, taken as one period, would have been equal to or greater than 2.5 to 1.0. Limitation on Restricted Payments. (a) The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly: (i) declare or pay any dividend on, or make any other distribution to holders of, any shares of Capital Stock of the Company (other than dividends or distributions payable solely in shares of Qualified Capital Stock of the Company or in options, warrants or other rights to purchase Qualified Capital Stock of the Company); (ii) purchase, redeem or otherwise acquire or retire for value any Capital Stock of the Company or any Affiliate thereof (other than any Restricted Subsidiary) or any options, warrants or other rights to acquire such Capital Stock; (iii) make any principal payment on or repurchase, redeem, defease or otherwise acquire or retire for value, prior to any scheduled principal payment, scheduled sinking fund payment or maturity, any Subordinated Indebtedness, except in any case out of the net cash proceeds of Permitted Refinancing Indebtedness; or (iv) make any Restricted Investment; (such payments or other actions described in clauses (i) through (iv) being collectively referred to as "Restricted Payments"), unless at the time of and after giving effect to the proposed Restricted Payment (the amount of any such Restricted Payment, if other than cash, shall be the amount determined by the Board of Directors of the Company, whose determination shall be conclusive and evidenced by a Board Resolution), (1) no Default or Event of Default shall have occurred and be continuing, (2) the Company could incur $1.00 of additional Indebtedness (other than Permitted Indebtedness) in accordance with the "-- Limitation on Indebtedness and Disqualified Capital Stock" covenant, and (3) the aggregate amount of all Restricted Payments declared or made after the date of the Indenture shall not exceed the sum (without duplication) of the following: (A) 50% of the Consolidated Net Income of the Company accrued on a cumulative basis during the period beginning on October 1, 1997 and ending on the last day of the Company's last fiscal quarter ending prior to the date of such proposed Restricted Payment (or, if such Consolidated Net Income is a loss, minus 100% of such loss), (B) the aggregate Net Cash Proceeds received after the date of the Indenture by the Company from the issuance or sale (other than to any of its Restricted Subsidiaries) of shares of Qualified Capital Stock of the Company or any options, warrants or rights to purchase such shares of Qualified Capital Stock of the Company, (C) the aggregate Net Cash Proceeds received after the date of the Indenture by the Company (other than from any of its Restricted Subsidiaries) upon the exercise of any options, warrants or rights to purchase shares of Qualified Capital Stock of the Company, (D) the aggregate Net Cash Proceeds received after the date of the Indenture by the Company from the issuance or sale (other than to any of its Restricted Subsidiaries) of Indebtedness or shares of Disqualified Capital Stock that have been converted into or exchanged for Qualified Capital Stock of the 58 59 Company, together with the aggregate cash received by the Company at the time of such conversion or exchange, (E) to the extent not otherwise included in Consolidated Net Income, the net reduction in Investments in Unrestricted Subsidiaries resulting from dividends, repayments of loans or advances, or other transfers of assets, in each case to the Company or a Restricted Subsidiary after the date of the Indenture from any Unrestricted Subsidiary or from the redesignation of an Unrestricted Subsidiary as a Restricted Subsidiary (valued in each case as provided in the definition of Investment), not to exceed in the case of any Unrestricted Subsidiary the total amount of Investments (other than Permitted Investments) in such Unrestricted Subsidiary made by the Company and its Restricted Subsidiaries in such Unrestricted Subsidiary after the date of the Indenture, and (F) $25 million. (b) Notwithstanding paragraph (a) above, the Company and its Restricted Subsidiaries may take the following actions so long as (in the case of clauses (ii), (iii) and (iv) below) no Default or Event of Default shall have occurred and be continuing: (i) the payment of any dividend on any Capital Stock of the Company within 60 days after the date of declaration thereof, if at such declaration date such declaration complied with the provisions of paragraph (a) above (and such payment shall be deemed to have been paid on such date of declaration for purposes of any calculation required by the provisions of paragraph (a) above); (ii) the repurchase, redemption or other acquisition or retirement of any shares of any class of Capital Stock of the Company or any Restricted Subsidiary, in exchange for, or out of the aggregate Net Cash Proceeds from, a substantially concurrent issuance and sale (other than to a Restricted Subsidiary) of shares of Qualified Capital Stock of the Company; (iii) the purchase, redemption, repayment, defeasance or other acquisition or retirement for value of any Subordinated Indebtedness in exchange for, or out of the aggregate Net Cash Proceeds from, a substantially concurrent issuance and sale (other than to a Restricted Subsidiary) of shares of Qualified Capital Stock of the Company; and (iv) repurchases, acquisitions or retirements of shares of Qualified Capital Stock of the Company deemed to occur upon the exercise of stock options or similar rights issued under employee benefit plans of the Company if such shares represent all or a portion of the exercise price or are surrendered in connection with satisfying any federal income tax obligation. The actions described in clauses (i), (ii), (iii) and (iv) of this paragraph (b) shall be Restricted Payments that shall be permitted to be made in accordance with this paragraph (b) but shall reduce the amount that would otherwise be available for Restricted Payments under clause (3) of paragraph (a), provided that any dividend paid pursuant to clause (i) of this paragraph (b) shall reduce the amount that would otherwise be available under clause (3) of paragraph (a) when declared, but not also when subsequently paid pursuant to such clause (i). Limitation on Issuances and Sales of Capital Stock of Restricted Subsidiaries. The Company (i) will not permit any Restricted Subsidiary to issue or sell any Capital Stock to any Person other than the Company or another Restricted Subsidiary (unless, after giving effect thereto, such Restricted Subsidiary no longer qualifies as such) and (ii) will not permit any Person other than the Company or a Restricted Subsidiary to own any Capital Stock of any Restricted Subsidiary. Limitation on Transactions with Affiliates. The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, enter into or suffer to exist any transaction or series of related transactions (including, without limitation, the sale, purchase, exchange or lease of assets or property or the rendering of any services) with, or for the benefit of, any Affiliate of the Company (other than the Company or a Restricted Subsidiary), unless (i) such transaction or series of transactions is on terms that are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that would be 59 60 available in a comparable arm's length transaction with unrelated third parties, (ii) with respect to any one transaction or series of transactions involving aggregate payments in excess of $1 million, the Company delivers an Officers' Certificate to the Trustee certifying that such transaction or series of transactions complies with clause (i) above and that such transaction or series of transactions has been approved by a majority of the Disinterested Directors of the Company, and (iii) with respect to any one transaction or series of transactions involving aggregate payments in excess of $10 million, the Officers' Certificate referred to in clause (ii) above also certifies that the Company has obtained a written opinion from an independent nationally recognized investment banking firm or appraisal firm specializing or having a speciality in the type and subject matter of the transaction or series of transactions at issue, which opinion shall be to the effect set forth in clause (i) above or shall state that such transaction or series of transactions is fair from a financial point of view to the Company or such Restricted Subsidiary; provided, however, that the foregoing restriction shall not apply to (w) loans or advances to officers, directors and employees of the Company or any Restricted Subsidiary made in the ordinary course of business and consistent with past practices of the Company and its Restricted Subsidiaries in an aggregate amount not to exceed $1 million outstanding at any one time, (x) indemnities of officers, directors, employees and other agents of the Company or any Restricted Subsidiary permitted by corporate charter or other organizational document, bylaw or statutory provisions, (y) the payment of reasonable and customary regular fees to directors of the Company or any of its Restricted Subsidiaries who are not employees of the Company or any Affiliate and (z) the Company's employee compensation and other benefit arrangements. Limitation on Other Senior Subordinated Indebtedness. The Company will not incur any Indebtedness that is expressly subordinate or junior in right of payment to any Senior Indebtedness of the Company and senior in right of payment to the Notes, and no Subsidiary Guarantor will incur any Indebtedness that is expressly subordinate or junior in right of payment to any Senior Indebtedness of such Subsidiary Guarantor and senior in right of payment to its Subsidiary Guarantee; provided, however, that the foregoing limitations will not apply to distinctions between categories of Indebtedness that exist by reason of any Liens arising or created in respect of some but not all such Indebtedness. Limitation on Liens. The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create, incur, assume, affirm or suffer to exist or become effective any Lien of any kind, except for Permitted Liens, upon any of their respective property or assets, whether now owned or acquired after the date of the Indenture, or any income, profits or proceeds therefrom, to secure (a) any Indebtedness of the Company or such Restricted Subsidiary (if it is not also a Subsidiary Guarantor), unless prior to, or contemporaneously therewith, the Notes are equally and ratably secured, or (b) any Indebtedness of any Subsidiary Guarantor, unless prior to, or contemporaneously therewith, the Subsidiary Guarantees are equally and ratably secured; provided, however, that if such Indebtedness is expressly subordinated in right of payment to the Notes or the Subsidiary Guarantees, the Lien securing such Indebtedness will be subordinated and junior to the Lien securing the Notes or the Subsidiary Guarantees, as the case may be, with the same relative priority as such Indebtedness has with respect to the Notes or the Subsidiary Guarantees. The foregoing covenant will not apply to any Lien securing Acquired Indebtedness, provided that any such Lien extends only to the property or assets that were subject to such Lien prior to the related acquisition by the Company or such Restricted Subsidiary and was not created, incurred or assumed in contemplation of such transaction. The incurrence of additional secured Indebtedness by the Company and its Restricted Subsidiaries is subject to further limitations on the incurrence of Indebtedness as described under " -- Limitation on Indebtedness and Disqualified Capital Stock." Change of Control. Upon the occurrence of a Change of Control, the Company shall be obligated to make an offer to purchase all of the then outstanding Notes (a "Change of Control Offer"), and shall purchase, on a Business Day (the "Change of Control Purchase Date") not more than 60 nor less than 30 days following such Change of Control, all of the then outstanding Notes validly tendered pursuant to such Change of Control Offer, at a purchase price (the "Change of Control Purchase Price") equal to 101% of the principal amount thereof plus accrued and unpaid interest, if any, to the Change of Control Purchase Date. The Change of Control Offer is required to remain open for at least 20 Business Days and until the close of business on the fifth Business Day prior to the Change of Control Purchase Date. 60 61 In order to effect such Change of Control Offer, the Company shall, not later than the 30th day after the Change of Control, give to the Trustee and each Holder a notice of the Change of Control Offer, which notice shall govern the terms of the Change of Control Offer and shall state, among other things, the procedures that Holders must follow to accept the Change of Control Offer. The occurrence of a Change of Control would result in the holders of any then outstanding Senior Notes having the right under the Senior Indenture to require the Company to make an offer to purchase all of such Senior Notes upon substantially the same terms as the Notes. Further, the existing Bank Credit Facilities contain, and any future credit agreements or other agreements relating to Indebtedness or other obligations of the Company may contain, prohibitions or restrictions on the Company's ability to effect a Change of Control Offer, which would then also be blocked by the subordination provisions of the Indenture. In the event a Change of Control occurs at a time when such prohibitions or restrictions are in effect, the Company could seek the consent of its lenders to the repurchase of Notes or could attempt to refinance the borrowings or renegotiate the agreements that contain such prohibitions. If the Company does not obtain such a consent or repay such borrowings or change such agreements, the Company will be effectively prohibited from repurchasing Notes. Failure by the Company to purchase the Notes when required would result in an Event of Default, whether or not such purchase is permitted by the subordination provisions of the Indenture. See " -- Subordination" and " -- Events of Default." There can be no assurance that the Company would have adequate resources to repay or refinance all Indebtedness and other obligations owing under the Bank Credit Facilities and such other agreements and to fund the purchase of the Senior Notes and the Notes upon a Change of Control. The Company will not be required to make a Change of Control Offer upon a Change of Control if another Person makes the Change of Control Offer at the same purchase price, at the same times and otherwise in substantial compliance with the requirements applicable to a Change of Control Offer to be made by the Company and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer. The definition of Change of Control includes a phrase relating to the disposition of "all or substantially all" of the properties and assets of the Company and its Restricted Subsidiaries, taken as a whole. Although there is a developing body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of the Notes to require the Company to purchase such Notes as a result of a disposition of less than all of the properties and assets of the Company and its Restricted Subsidiaries, taken as a whole, to another Person may be uncertain. The Company intends to comply with Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder, if applicable, in the event that a Change of Control occurs and the Company is required to purchase Notes as described above. The existence of a Holder's right to require, subject to certain conditions, the Company to repurchase its Notes upon a Change of Control may deter a third party from acquiring the Company in a transaction that constitutes, or results in, a Change of Control. Limitation on Asset Sales. (a) The Company will not, and will not permit any Restricted Subsidiary to, engage in any Asset Sale unless (i) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Sale at least equal to the fair market value of the assets and properties sold or otherwise disposed of pursuant to the Asset Sale (as determined by the Board of Directors of the Company, whose determination shall be conclusive and evidenced by a Board Resolution), (ii) at least 75% of the consideration received by the Company or the Restricted Subsidiary, as the case may be, in respect of such Asset Sale consists of cash, Cash Equivalents or properties used in the Oil and Gas Business of the Company or its Restricted Subsidiaries and (iii) the Company delivers to the Trustee an Officers' Certificate certifying that such Asset Sale complies with clauses (i) and (ii). The amount (without duplication) of any Indebtedness (other than Subordinated Indebtedness) of the Company or such Restricted Subsidiary that is expressly assumed by the transferee in such Asset Sale and with respect to which the Company or such Restricted Subsidiary, as the case may be, is unconditionally released by the holder of such Indebtedness, shall be deemed to be cash or Cash Equivalents for purposes of clause (ii) and shall also be deemed to constitute a 61 62 repayment of, and a permanent reduction in, the amount of such Indebtedness for purposes of the following paragraph. (b) If the Company or any Restricted Subsidiary engages in an Asset Sale, the Company or such Restricted Subsidiary may either, no later than 360 days after such Asset Sale, (i) apply all or any of the Net Available Proceeds therefrom to repay Senior Indebtedness (including Senior Notes) or Pari Passu Indebtedness (provided that in connection with the reduction of Pari Passu Indebtedness, the Company or such Restricted Subsidiary redeems a pro rata portion of the Notes) of the Company or any Restricted Subsidiary, provided, in each case, that the related loan commitment (if any) is thereby permanently reduced by the amount of such Indebtedness so repaid, or (ii) invest all or any part of the Net Available Proceeds thereof in properties and assets that will be used in the Oil and Gas Business of the Company or its Restricted Subsidiaries, as the case may be. The amount of such Net Available Proceeds not applied or invested as provided in this paragraph will constitute "Excess Proceeds." (c) When the aggregate amount of Excess Proceeds equals or exceeds $10 million, the Company will be required to make an offer to purchase, from all Holders of the Notes, an aggregate principal amount of Notes equal to such Excess Proceeds as follows: (i) The Company will make an offer to purchase (a "Net Proceeds Offer") from all Holders of the Notes in accordance with the procedures set forth in the Indenture the maximum principal amount (expressed as a multiple of $1,000) of Notes that may be purchased out of the amount (the "Payment Amount") of such Excess Proceeds. (ii) The offer price for the Notes will be payable in cash in an amount equal to 100% of the principal amount of the Notes tendered pursuant to a Net Proceeds Offer, plus accrued and unpaid interest, if any, to the date such Net Proceeds Offer is consummated (the "Offered Price"), in accordance with the procedures set forth in the Indenture. To the extent that the aggregate Offered Price of the Notes tendered pursuant to a Net Proceeds Offer is less than the Payment Amount relating thereto (such shortfall constituting a "Net Proceeds Deficiency"), the Company may use such Net Proceeds Deficiency, or a portion thereof, for general corporate purposes, subject to the limitations of the "Limitation on Restricted Payments" covenant. (iii) If the aggregate Offered Price of Notes validly tendered and not withdrawn by Holders thereof exceeds the Payment Amount, Notes to be purchased will be selected on a pro rata basis. (iv) Upon completion of such Net Proceeds Offer, the amount of Excess Proceeds shall be reset to zero. The Company will not permit any Restricted Subsidiary to enter into or suffer to exist any agreement that would place any restriction of any kind (other than pursuant to law or regulation) on the ability of the Company to make a Net Proceeds Offer following any Asset Sale. The Company intends to comply with Rule 14e-1 under the Exchange Act, and any other securities laws and regulations thereunder, if applicable, in the event that an Asset Sale occurs and the Company is required to purchase Notes as described above. Limitation on Guarantees by Subsidiary Guarantors. The Company will not permit any Subsidiary Guarantor to guarantee the payment of any Subordinated Indebtedness of the Company unless such guarantee shall be subordinated to such Subsidiary Guarantor's Subsidiary Guarantee at least to the same extent as such Subordinated Indebtedness is subordinated to the Notes; provided, however, that this covenant will not be applicable to any guarantee of any Subsidiary Guarantor that (i) existed at the time such Person became a Subsidiary of the Company and (ii) was not incurred in connection with, or in contemplation of, such Person becoming a Subsidiary of the Company. Limitation on Dividends and Other Payment Restrictions Affecting Restricted Subsidiaries. The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create or suffer to exist or allow to become effective any consensual encumbrance or restriction of any kind on the ability of any Restricted Subsidiary (a) to pay dividends, in cash or otherwise, or make any other distributions on its Capital Stock, or make payments on any Indebtedness owed, to the Company or any other Restricted Subsidiary, (b) to make loans or advances to the Company or any other Restricted Subsidiary or (c) to transfer any of its property or assets to the Company or any other Restricted Subsidiary (any such restrictions being collectively 62 63 referred to herein as a "Payment Restriction"), except for such encumbrances or restrictions existing under or by reason of (i) customary provisions restricting subletting or assignment of any lease governing a leasehold interest of the Company or any Restricted Subsidiary, or customary restrictions in licenses relating to the property covered thereby and entered into in the ordinary course of business, (ii) any instrument governing Indebtedness of a Person acquired by the Company or any Restricted Subsidiary at the time of such acquisition, which encumbrance or restriction is not applicable to any other Person, other than the Person, or the property or assets of the Person, so acquired, provided that such Indebtedness was not incurred in anticipation of such acquisition or (iii) the Bank Credit Facilities as in effect on the date of the Indenture or any agreement that amends, modifies, supplements, restates, extends, renews, refinances or replaces the Bank Credit Facilities, provided that the terms and conditions of any Payment Restrictions thereunder are not materially less favorable to the Holders of the Notes than those under the Bank Credit Facilities as in effect on the date of the Indenture. Limitation on Conduct of Business. The Company will not, and will not permit any of its Restricted Subsidiaries to, engage in the conduct of any business other than the Oil and Gas Business. Reports. The Company will file on a timely basis with the Commission, to the extent such filings are accepted by the Commission and whether or not the Company has a class of securities registered under the Exchange Act, the annual reports, quarterly reports and other documents that the Company would be required to file if it were subject to Section 13 or 15 of the Exchange Act. The Company will also be required (a) to file with the Trustee (with exhibits), and provide to each Holder of Notes (without exhibits), without cost to such Holder, copies of such reports and documents within 15 days after the date on which the Company files such reports and documents with the Commission or the date on which the Company would be required to file such reports and documents if the Company were so required and (b) if filing such reports and documents with the Commission is not accepted by the Commission or is prohibited under the Exchange Act, to supply at its cost copies of such reports and documents (including any exhibits thereto) to any Holder of Notes promptly upon written request. Future Designation of Restricted and Unrestricted Subsidiaries. The foregoing covenants (including calculation of financial ratios and the determination of limitations on the incurrence of Indebtedness and Liens) may be affected by the designation by the Company of any existing or future Subsidiary of the Company as an Unrestricted Subsidiary. The definition of "Unrestricted Subsidiary" set forth under the caption "-- Certain Definitions" describes the circumstances under which a Subsidiary of the Company may be designated as an Unrestricted Subsidiary by the Board of Directors of the Company. MERGER, CONSOLIDATION AND SALE OF ASSETS The Company will not, in any single transaction or series of related transactions, merge or consolidate with or into any other Person, or sell, assign, convey, transfer, lease or otherwise dispose of all or substantially all of the properties and assets of the Company and its Restricted Subsidiaries on a consolidated basis to any Person or group of Affiliated Persons, and the Company will not permit any of its Restricted Subsidiaries to enter into any such transaction or series of transactions if such transaction or series of transactions, in the aggregate, would result in the sale, assignment, conveyance, transfer, lease or other disposition of all or substantially all of the properties and assets of the Company and its Restricted Subsidiaries on a consolidated basis to any other Person or group of Affiliated Persons, unless at the time and after giving effect thereto (i) either (A) if the transaction is a merger or consolidation, the Company shall be the surviving Person of such merger or consolidation, or (B) the Person (if other than the Company) formed by such consolidation or into which the Company is merged or to which the properties and assets of the Company or its Restricted Subsidiaries, as the case may be, are sold, assigned, conveyed, transferred, leased or otherwise disposed of (any such surviving Person or transferee Person being the "Surviving Entity") shall be a corporation organized and existing under the laws of the United States of America, any state thereof or the District of Columbia and shall, in either case, expressly assume by a supplemental indenture to the Indenture executed and delivered to the Trustee, in form satisfactory to the Trustee, all the obligations of the Company under the Notes and the Indenture, and, in each case, the Indenture shall remain in full force and effect; (ii) immediately before and immediately after giving effect to such transaction or series of transactions on a 63 64 pro forma basis (and treating any Indebtedness not previously an obligation of Company or any of its Restricted Subsidiaries which becomes an obligation of the Company or any of its Restricted Subsidiaries in connection with or as a result of such transaction as having been incurred at the time of such transaction), no Default or Event of Default shall have occurred and be continuing; (iii) except in the case of the consolidation or merger of any Restricted Subsidiary with or into the Company, immediately after giving effect to such transaction or transactions on a pro forma basis, the Consolidated Net Worth of the Company (or the Surviving Entity if the Company is not the continuing obligor under the Indenture) is at least equal to the Consolidated Net Worth of the Company immediately before such transaction or transactions; (iv) except in the case of the consolidation or merger of the Company with or into a Restricted Subsidiary or any Restricted Subsidiary with or into the Company or another Restricted Subsidiary, immediately before and immediately after giving effect to such transaction or transactions on a pro forma basis (assuming that the transaction or transactions occurred on the first day of the period of four fiscal quarters ending immediately prior to the consummation of such transaction or transactions, with the appropriate adjustments with respect to the transaction or transactions being included in such pro forma calculation), the Company (or the Surviving Entity if the Company is not the continuing obligor under the Indenture) could incur $1.00 of additional Indebtedness (other than Permitted Indebtedness) pursuant to the "-- Limitation on Indebtedness and Disqualified Capital Stock" covenant; (v) if the Company is not the continuing obligor under the Indenture, then each Subsidiary Guarantor, unless it is the Surviving Entity, shall have by supplemental indenture to the Indenture confirmed that its Subsidiary Guarantee of the Notes shall apply to the Surviving Entity's obligations under the Indenture and the Notes; (vi) if any of the properties or assets of the Company or any of its Restricted Subsidiaries would upon such transaction or series of related transactions become subject to any Lien (other than a Permitted Lien), the creation and imposition of such Lien shall have been in compliance with the "Limitation on Liens" covenant; and (vii) the Company (or the Surviving Entity if the Company is not the continuing obligor under the Indenture) shall have delivered to the Trustee, in form and substance reasonably satisfactory to the Trustee, (a) an Officers' Certificate stating that such consolidation, merger, transfer, lease or other disposition and any supplemental indenture in respect thereto comply with the requirements under the Indenture and (b) an Opinion of Counsel stating that the requirements of clause (i) of this paragraph have been satisfied. Upon any consolidation or merger or any sale, assignment, lease, conveyance, transfer or other disposition of all or substantially all of the properties and assets of the Company and its Restricted Subsidiaries on a consolidated basis in accordance with the foregoing, in which the Company is not the continuing corporation, the Surviving Entity shall succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture with the same effect as if the Surviving Entity had been named as the Company therein, and thereafter the Company, except in the case of a lease, will be discharged from all obligations and covenants under the Indenture and the Notes and may be liquidated and dissolved. EVENTS OF DEFAULT The following will be "Events of Default" under the Indenture: (i) default in the payment of the principal of or premium, if any, on any of the Notes, whether such payment is due at Stated Maturity, upon redemption, upon repurchase pursuant to a Change of Control Offer or a Net Proceeds Offer, upon acceleration or otherwise; or (ii) default in the payment of any installment of interest on any of the Notes, when due, and the continuance of such default for a period of 30 days (even if such payment is prohibited by the subordination provisions of the Indenture); or (iii) default in the performance or breach of the provisions of the "Merger, Consolidation and Sale of Assets" section of the Indenture, the failure to make or consummate a Change of Control Offer in accordance with the provisions of the "Change of Control" covenant or the failure to make or consummate a Net Proceeds Offer in accordance with the provisions of the "Limitation on Asset Sales" covenant; or (iv) the Company or any Subsidiary Guarantor shall fail to perform or observe any other term, covenant or agreement contained in the Notes, any Subsidiary Guarantee or the Indenture (other than a default 64 65 specified in (i), (ii) or (iii) above) for a period of 60 days after written notice of such failure stating that it is a "notice of default" under the Indenture and requiring the Company or such Subsidiary Guarantor to remedy the same shall have been given (x) to the Company by the Trustee or (y) to the Company and the Trustee by the Holders of at least 25% in aggregate principal amount of the Notes then outstanding; or (v) the occurrence and continuation beyond any applicable grace period of any default in the payment of the principal of, premium, if any, or interest on any Indebtedness of the Company (other than the Notes) or any Subsidiary Guarantor or any other Restricted Subsidiary for money borrowed when due, or any other default resulting in acceleration of any Indebtedness of the Company or any Subsidiary Guarantor or any other Restricted Subsidiary for money borrowed, provided that the aggregate principal amount of such Indebtedness shall exceed $5.0 million and provided, further, that if any such default is cured or waived or any such acceleration rescinded, or such Indebtedness is repaid, within a period of 10 days from the continuation of such default beyond the applicable grace period or the occurrence of such acceleration, as the case may be, such Event of Default under the Indenture and any consequential acceleration of the Notes shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree; or (vi) any Subsidiary Guarantee shall for any reason cease to be, or be asserted by the Company or any Subsidiary Guarantor, as applicable, not to be, in full force and effect (except pursuant to the release of any such Subsidiary Guarantee in accordance with the Indenture); or (vii) final judgments or orders rendered against the Company or any Subsidiary Guarantor or any other Restricted Subsidiary that are unsatisfied and that require the payment in money, either individually or in an aggregate amount, that is more than $5.0 million over the coverage under applicable insurance policies and either (A) commencement by any creditor of an enforcement proceeding upon such judgment (other than a judgment that is stayed by reason of pending appeal or otherwise) or (B) the occurrence of a 60-day period during which a stay of such judgment or order, by reason of pending appeal or otherwise, was not in effect; or (viii) the entry of a decree or order by a court having jurisdiction in the premises (A) for relief in respect of the Company or any Subsidiary Guarantor or any other Restricted Subsidiary in an involuntary case or proceeding under any applicable federal or state bankruptcy, insolvency, reorganization or other similar law or (B) adjudging the Company or any Subsidiary Guarantor or any other Restricted Subsidiary bankrupt or insolvent, or approving a petition seeking reorganization, arrangement, adjustment or composition of the Company or any Subsidiary Guarantor or any other Restricted Subsidiary under any applicable federal or state law, or appointing under any such law a custodian, receiver, liquidator, assignee, trustee, sequestrator or other similar official of the Company or any Subsidiary Guarantor or any other Restricted Subsidiary or of a substantial part of its consolidated assets, or ordering the winding up or liquidation of its affairs, and the continuance of any such decree or order for relief or any such other decree or order unstayed and in effect for a period of 60 consecutive days; or (ix) the commencement by the Company or any Subsidiary Guarantor or any other Restricted Subsidiary of a voluntary case or proceeding under any applicable federal or state bankruptcy, insolvency, reorganization or other similar law or any other case or proceeding to be adjudicated bankrupt or insolvent, or the consent by the Company or any Subsidiary Guarantor or any other Restricted Subsidiary to the entry of a decree or order for relief in respect thereof in an involuntary case or proceeding under any applicable federal or state bankruptcy, insolvency, reorganization or other similar law or to the commencement of any bankruptcy or insolvency case or proceeding against it, or the filing by the Company or any Subsidiary Guarantor or any other Restricted Subsidiary of a petition or consent seeking reorganization or relief under any applicable federal or state law, or the consent by it under any such law to the filing of any such petition or to the appointment of or taking possession by a custodian, receiver, liquidator, assignee, trustee or sequestrator (or other similar official) of the Company or any Subsidiary Guarantor or any other Restricted Subsidiary or of any substantial part of its consolidated assets, or the making by it of an assignment for the benefit of creditors under any such law, or the admission by it in writing of its inability to pay its debts generally as they become due or taking of corporate action by the Company or any Subsidiary Guarantor or any other Restricted Subsidiary in furtherance of any such action. 65 66 If an Event of Default (other than as specified in clause (viii) or (ix) above) shall occur and be continuing, the Trustee, by written notice to the Company, or the Holders of at least 25% in aggregate principal amount of the Notes then outstanding, by written notice to the Trustee and the Company, may, and the Trustee upon the request of the Holders of not less than 25% in aggregate principal amount of the Notes then outstanding shall, declare the principal of, premium, if any, and accrued and unpaid interest on all of the Notes due and payable immediately, upon which declaration all amounts payable in respect of the Notes shall be immediately due and payable. If an Event of Default specified in clause (viii) or (ix) above occurs and is continuing, then the principal of, premium, if any, and accrued and unpaid interest on all of the Notes shall become and be immediately due and payable without any declaration, notice or other act on the part of the Trustee or any Holder of Notes. After a declaration of acceleration under the Indenture, but before a judgment or decree for payment of the money due has been obtained by the Trustee, the Holders of a majority in aggregate principal amount of the outstanding Notes, by written notice to the Company, the Subsidiary Guarantors and the Trustee, may rescind and annul such declaration if (a) the Company or any Subsidiary Guarantor has paid or deposited with the Trustee a sum sufficient to pay (i) all sums paid or advanced by the Trustee under the Indenture and the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, (ii) all overdue interest on all Notes, (iii) the principal of and premium, if any, on any Notes which have become due otherwise than by such declaration of acceleration and interest thereon at the rate borne by the Notes, and (iv) to the extent that payment of such interest is lawful, interest upon overdue interest and overdue principal at the rate borne by the Notes (without duplication of any amount paid or deposited pursuant to clause (ii) or (iii)); (b) the rescission would not conflict with any judgment or decree of a court of competent jurisdiction; and (c) all Events of Default, other than the non-payment of principal of, premium, if any, or interest on the Notes that has become due solely by such declaration of acceleration, have been cured or waived. No Holder will have any right to institute any proceeding with respect to the Indenture or any remedy thereunder, unless such Holder has notified the Trustee of a continuing Event of Default and the Holders of at least 25% in aggregate principal amount of the outstanding Notes have made written request, and offered reasonable indemnity, to the Trustee to institute such proceeding as Trustee under the Notes and the Indenture, the Trustee has failed to institute such proceeding within 60 days after receipt of such notice and the Trustee, within such 60-day period, has not received directions inconsistent with such written request by Holders of a majority in aggregate principal amount of the outstanding Notes. Such limitations will not apply, however, to a suit instituted by the Holder of a Note for the enforcement of the payment of the principal of, premium, if any, or interest on such Note on or after the respective due dates expressed in such Note. During the existence of an Event of Default, the Trustee will be required to exercise such rights and powers vested in it under the Indenture and use the same degree of care and skill in its exercise thereof as a prudent person would exercise under the circumstances in the conduct of such person's own affairs. Subject to the provisions of the Indenture relating to the duties of the Trustee in case an Event of Default shall occur and be continuing, the Trustee will not be under any obligation to exercise any of its rights or powers under the Indenture at the request or direction of any of the Holders unless such Holders shall have offered to the Trustee reasonable security or indemnity. Subject to certain provisions concerning the rights of the Trustee, the Holders of a majority in aggregate principal amount of the outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee under the Indenture. If a Default or an Event of Default occurs and is continuing and is known to the Trustee, the Trustee shall mail to each Holder notice of the Default or Event of Default within 60 days after the occurrence thereof. Except in the case of a Default or an Event of Default in payment of principal of, premium, if any, or interest on any Notes, the Trustee may withhold the notice to the Holders of the Notes if the Trustee determines in good faith that withholding the notice is in the interest of the Holders of the Notes. 66 67 The Company will be required to furnish to the Trustee annual and quarterly statements as to the performance by the Company of its obligations under the Indenture and as to any default in such performance. The Company is also required to notify the Trustee within 10 days of any Default or Event of Default. LEGAL DEFEASANCE OR COVENANT DEFEASANCE OF INDENTURE The Company may, at its option and at any time, terminate the obligations of the Company and the Subsidiary Guarantors with respect to the outstanding Notes (such action being a "legal defeasance"). Such legal defeasance means that the Company and the Subsidiary Guarantors shall be deemed to have paid and discharged the entire Indebtedness represented by the outstanding Notes and to have been discharged from all their other obligations with respect to the Notes and the Subsidiary Guarantees, except for, among other things, (i) the rights of Holders of outstanding Notes to receive payment in respect of the principal of, premium, if any, and interest on such Notes when such payments are due, (ii) the Company's obligations to replace any temporary Notes, register the transfer or exchange of any Notes, replace mutilated, destroyed, lost or stolen Notes and maintain an office or agency for payments in respect of the Notes, (iii) the rights, powers, trusts, duties and immunities of the Trustee, and (iv) the defeasance provisions of the Indenture. In addition, the Company may, at its option and at any time, elect to terminate the obligations of the Company and each Subsidiary Guarantor with respect to certain covenants that are set forth in the Indenture, some of which are described under "-- Certain Covenants" above, and any omission to comply with such obligations shall not constitute a Default or an Event of Default with respect to the Notes (such action being a "covenant defeasance"). In order to exercise either legal defeasance or covenant defeasance, (i) the Company or any Subsidiary Guarantor must irrevocably deposit with the Trustee, in trust, for the benefit of the Holders of the Notes, cash in United States dollars, U.S. Government Obligations (as defined in the Indenture), or a combination thereof, in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, premium, if any, and interest on the outstanding Notes to redemption or maturity; (ii) the Company shall have delivered to the Trustee an Opinion of Counsel to the effect that the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such legal defeasance or covenant defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such legal defeasance or covenant defeasance had not occurred (in the case of legal defeasance, such opinion must refer to and be based upon a published ruling of the Internal Revenue Service or a change in applicable federal income tax laws); (iii) no Default or Event of Default shall have occurred and be continuing on the date of such deposit or insofar as clauses (viii) and (ix) under the first paragraph of "Events of Default" are concerned, at any time during the period ending on the 91st day after the date of deposit; (iv) such legal defeasance or covenant defeasance shall not cause the Trustee to have a conflicting interest under the Indenture or the Trust Indenture Act with respect to any securities of the Company or any Subsidiary Guarantor; (v) such legal defeasance or covenant defeasance shall not result in a breach or violation of, or constitute a default under, any material agreement or instrument to which the Company or any Subsidiary Guarantor is a party or by which it is bound; and (vi) the Company shall have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel satisfactory to the Trustee, which, taken together, state that all conditions precedent under the Indenture to either legal defeasance or covenant defeasance, as the case may be, have been complied with. SATISFACTION AND DISCHARGE The Indenture will be discharged and will cease to be of further effect (except as to surviving rights of registration of transfer or exchange of the Notes, as expressly provided for in the Indenture) as to all outstanding Notes when (i) either (a) all the Notes theretofore authenticated and delivered (except lost, stolen, mutilated or destroyed Notes which have been replaced or paid and Notes for whose payment money or certain United States government obligations have theretofore been deposited in trust or segregated and held in trust by the Company and thereafter repaid to the Company or discharged from such trust) have been delivered to the Trustee for cancellation or (b) all Notes not theretofore delivered to the Trustee for 67 68 cancellation have become due and payable or will become due and payable at their Stated Maturity within one year, or are to be called for redemption within one year under arrangements satisfactory to the Trustee for the serving of notice of redemption by the Trustee in the name, and at the expense, of the Company, and the Company has irrevocably deposited or caused to be deposited with the Trustee funds in an amount sufficient to pay and discharge the entire Indebtedness on the Notes not theretofore delivered to the Trustee for cancellation, for principal of, premium, if any, and interest on the Notes to the date of deposit (in the case of Notes which have become due and payable) or to the Stated Maturity or Redemption Date, as the case may be, together with instructions from the Company irrevocably directing the Trustee to apply such funds to the payment thereof at maturity or redemption, as the case may be; (ii) the Company has paid all other sums payable under the Indenture by the Company; and (iii) the Company has delivered to the Trustee an Officers' Certificate and an Opinion of Counsel which, taken together, state that all conditions precedent under the Indenture relating to the satisfaction and discharge of the Indenture have been complied with. AMENDMENTS AND WAIVERS From time to time, the Company, the Subsidiary Guarantors and the Trustee may, without the consent of the Holders of the Notes, amend or supplement the Indenture or the Notes for certain specified purposes, including, among other things, curing ambiguities, defects or inconsistencies, qualifying, or maintaining the qualification of, the Indenture under the Trust Indenture Act, adding or releasing any Subsidiary Guarantor pursuant to the terms of the Indenture, or making any change that does not materially adversely affect the rights of any Holder of Notes. Other amendments and modifications of the Indenture or the Notes may be made by the Company, the Subsidiary Guarantors and the Trustee with the consent of the Holders of not less than a majority of the aggregate principal amount of the outstanding Notes; provided, however, that no such modification or amendment may, without the consent of the Holder of each outstanding Note affected thereby, (a) change the Stated Maturity of the principal of, or any installment of interest on, any Note, (b) reduce the principal amount of, premium, if any, or interest on any Note, (c) change the coin or currency of payment of principal of, premium, if any, or interest on, any Note, (d) impair the right to institute suit for the enforcement of any payment on or with respect to any Note, (e) reduce the above-stated percentage of aggregate principal amount of outstanding Notes necessary to modify or amend the Indenture, (f) reduce the percentage of aggregate principal amount of outstanding Notes necessary for waiver of compliance with certain provisions of the Indenture or for waiver of certain defaults, (g) modify any provisions of the Indenture relating to the modification and amendment of the Indenture or the waiver of past defaults or covenants, except as otherwise specified, (h) modify any provisions of the Indenture relating to subordination of the Notes or the Subsidiary Guarantees in a manner adverse to the Holders or (i) amend, change or modify the obligation of the Company to make and consummate a Change of Control Offer in the event of a Change of Control or make and consummate a Net Proceeds Offer with respect to any Asset Sale or modify any of the provisions or definitions with respect thereto. The Holders of not less than a majority in aggregate principal amount of the outstanding Notes may, on behalf of the Holders of all Notes, waive any past default under the Indenture, except a default in the payment of principal of, premium, if any, or interest on the Notes, or in respect of a covenant or provision which under the Indenture cannot be modified or amended without the consent of the Holder of each Note outstanding. THE TRUSTEE State Street Bank and Trust Company will serve as trustee under the Indenture. The Indenture (including provisions of the Trust Indenture Act incorporated by reference therein) will contain limitations on the rights of the Trustee thereunder, should it become a creditor of the Company, to obtain payment of claims in certain cases or to realize on certain property received by it in respect of any such claims, as security or otherwise. The Indenture will permit the Trustee to engage in other transactions; provided, however, if it acquires any conflicting interest (as defined in the Trust Indenture Act) it must eliminate such conflict or resign. 68 69 State Street Bank and Trust Company is also the trustee under the Senior Notes Indenture. Pursuant to the Trust Indenture Act, should a default occur with respect to either the Senior Notes or the Notes, State Street Bank and Trust Company would be required to resign as trustee under one of the indentures within 90 days of such default, unless such default were cured, duly waived or otherwise eliminated. GOVERNING LAW The Indenture, the Notes and the Subsidiary Guarantees will be governed by, and construed and enforced in accordance with, the laws of the State of New York. CERTAIN DEFINITIONS "Acquired Indebtedness" means Indebtedness of a Person (a) existing at the time such Person becomes a Restricted Subsidiary or (b) assumed in connection with acquisitions of properties or assets from such Person (other than any Indebtedness incurred in connection with, or in contemplation of, such Person becoming a Restricted Subsidiary or such acquisition). Acquired Indebtedness shall be deemed to be incurred on the date the acquired Person becomes a Restricted Subsidiary or the date of the related acquisition of properties or assets from such Person. "Adjusted Net Assets" of a Subsidiary Guarantor at any date shall mean the amount by which the fair value of the properties and assets of such Subsidiary Guarantor exceeds the total amount of liabilities, including, without limitation, contingent liabilities (after giving effect to all other fixed and contingent liabilities incurred or assumed on such date), but excluding liabilities under its Subsidiary Guarantee, of such Subsidiary Guarantor at such date. "Affiliate" means, with respect to any specified Person, any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, "control," when used with respect to any Person, means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms "controlling" and "controlled" have meanings correlative to the foregoing. For purposes of this definition, beneficial ownership of 10% or more of the voting common equity (on a fully diluted basis) or options or warrants to purchase such equity (but only if exercisable at the date of determination or within 60 days thereof) of a Person shall be deemed to constitute control of such Person. "Asset Sale" means any sale, issuance, conveyance, transfer, lease or other disposition to any Person other than the Company or any of its Restricted Subsidiaries (including, without limitation, by means of a merger or consolidation) (collectively, for purposes of this definition, a "transfer"), directly or indirectly, in one or a series of related transactions, of (a) any Capital Stock of any Restricted Subsidiary held by the Company or any Restricted Subsidiary, (b) all or substantially all of the properties and assets of any division or line of business of the Company or any of its Restricted Subsidiaries or (c) any other properties or assets of the Company or any of its Restricted Subsidiaries other than (i) a transfer of cash, Cash Equivalents, hydrocarbons or other mineral products in the ordinary course of business or (ii) any lease, abandonment, disposition, relinquishment or farm-out of any oil and gas properties in the ordinary course of business. For the purposes of this definition, the term "Asset Sale" also shall not include (i) any transfer of properties or assets (including Capital Stock) that is governed by, and made in accordance with, the provisions described under "-- Merger, Consolidation and Sale of Assets"; (ii) any transfer of properties or assets to an Unrestricted Subsidiary, if permitted under the "Limitation on Restricted Payments" covenant; or (iii) any transfer of properties or assets (including Capital Stock) having a fair market value of less than $2 million. "Average Life" means, with respect to any Indebtedness, as at any date of determination, the quotient obtained by dividing (a) the sum of the products of (i) the number of years (and any portion thereof) from the date of determination to the date or dates of each successive scheduled principal payment (including, without limitation, any sinking fund or mandatory redemption payment requirements) of such Indebtedness multiplied by (ii) the amount of each such principal payment by (b) the sum of all such principal payments. 69 70 "Bank Credit Facilities" means (i) that certain Credit Agreement dated effective as of September 25, 1996, as amended, among KCS Resources, Inc., KCS Pipeline Systems, Inc., KCS Michigan Resources, Inc., and KCS Energy Marketing, Inc., as Borrowers, KCS Energy, Inc., as Guarantor, and Canadian Imperial Bank of Commerce, New York Agency, as Agent, CIBC, Inc., as Collateral Agent, Bank One, Texas, N.A., as Co-Agent, and NationsBank of Texas, N.A., as Co-Agent, and (ii) that certain Credit Agreement dated as of January 2, 1997, as amended, among KCS Medallion Resources, Inc., KCS Energy, Inc., KCS Energy Services, Inc. and Medallion Gas Services, Inc., as Borrowers, and Canadian Imperial Bank of Commerce, New York Agency, as Agent, and CIBC, Inc., as Collateral Agent, in each case as the same may be amended, modified, supplemented, extended, restated, replaced, renewed or refinanced from time to time in one or more credit agreements, loan agreements, instruments or similar agreements, as such may be further amended, modified, supplemented, extended, restated, replaced, renewed or refinanced. "Capital Stock" means, with respect to any Person, any and all shares, interests, participations, rights or other equivalents in the equity interests (however designated) in such Person, and any rights (other than debt securities convertible into an equity interest), warrants or options exercisable for, exchangeable for or convertible into such an equity interest in such Person. "Capitalized Lease Obligation" means any obligation to pay rent or other amounts under a lease of (or other agreement conveying the right to use) any property (whether real, personal or mixed) that is required to be classified and accounted for as a capital lease obligation under GAAP, and, for the purpose of the Indenture, the amount of such obligation at any date shall be the capitalized amount thereof at such date, determined in accordance with GAAP. "Cash Equivalents" means (i) any evidence of Indebtedness with a maturity of 180 days or less issued or directly and fully guaranteed or insured by the United States of America or any agency or instrumentality thereof (provided that the full faith and credit of the United States of America is pledged in support thereof); (ii) demand and time deposits and certificates of deposit or acceptances with a maturity of 180 days or less of any financial institution that is a member of the Federal Reserve System having combined capital and surplus and undivided profits of not less than $500 million; (iii) commercial paper with a maturity of 180 days or less issued by a corporation that is not an Affiliate of the Company and is organized under the laws of any state of the United States or the District of Columbia and rated at least A-l by S&P or at least P-l by Moody's; (iv) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clause (i) above entered into with any commercial bank meeting the specifications of clause (ii) above; (v) overnight bank deposits and bankers acceptances at any commercial bank meeting the qualifications specified in clause (ii) above; (vi) deposits available for withdrawal on demand with any commercial bank not meeting the qualifications specified in clause (ii) above but which is a lending bank under any of the Bank Credit Facilities, provided all such deposits do not exceed $5 million in the aggregate at any one time; (vii) demand and time deposits and certificates of deposit with any commercial bank organized in the United States not meeting the qualifications specified in clause (ii) above, provided that such deposits and certificates support bond, letter of credit and other similar types of obligations incurred in the ordinary course of business; and (viii) investments in money market or other mutual funds substantially all of whose assets comprise securities of the types described in clauses (i) through (v) above. "Change of Control" means the occurrence of any event or series of events by which: (a) any "person" or "group" (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act) is or becomes the beneficial owner (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 50% of the total Voting Stock of the Company; (b) the Company consolidates with or merges into another Person or any Person consolidates with, or merges into, the Company, in any such event pursuant to a transaction in which the outstanding Voting Stock of the Company is changed into or exchanged for cash, securities or other property, other than any such transaction where (i) the outstanding Voting Stock of the Company is changed into or exchanged for Voting Stock of the surviving or resulting Person that is Qualified Capital Stock and (ii) the holders of the Voting Stock of the Company immediately prior to such transaction own, directly or indirectly, not less than a majority of the Voting Stock of the surviving or resulting Person immediately after such transaction; (c) the Company, either individually or in conjunction with one or more Restricted Subsidiaries, sells, assigns, conveys, transfers, leases or otherwise disposes of, or the Restricted Subsidiaries 70 71 sell, assign, convey, transfer, lease or otherwise dispose of, all or substantially all of the properties and assets of the Company and such Restricted Subsidiaries, taken as a whole (either in one transaction or a series of related transactions), including Capital Stock of the Restricted Subsidiaries, to any Person (other than the Company or a Restricted Subsidiary); (d) during any consecutive two-year period, individuals who at the beginning of such period constituted the Board of Directors of the Company (together with any new directors whose election by such Board of Directors or whose nomination for election by the stockholders of the Company was approved by a vote of 66 2/3% of the directors then still in office who were either directors at the beginning of such period or whose election or nomination for election was previously so approved) cease for any reason to constitute a majority of the Board of Directors of the Company then in office; or (e) the liquidation or dissolution of the Company. "Common Stock" of any Person means Capital Stock of such Person that does not rank prior, as to the payment of dividends or as to the distribution of assets upon any voluntary or involuntary liquidation, dissolution or winding up of such Person, to shares of Capital Stock of any other class of such Person. "Consolidated EBITDA Coverage Ratio" means, for any period, the ratio on a pro forma basis of (a) the sum of Consolidated Net Income, Consolidated Interest Expense, Consolidated Income Tax Expense and Consolidated Non-cash Charges deducted in computing Consolidated Net Income, in each case, for such period, of the Company and its Restricted Subsidiaries on a consolidated basis, all determined in accordance with GAAP, decreased (to the extent included in determining Consolidated Net Income) by the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, to (b) the sum of such Consolidated Interest Expense for such period; provided, however, that (i) the Consolidated EBITDA Coverage Ratio shall be calculated on a pro forma basis assuming that (A) the Indebtedness to be incurred (and all other Indebtedness incurred after the first day of such period of four full fiscal quarters referred to in the covenant described under "-- Certain Covenants -- Limitation on Indebtedness and Disqualified Capital Stock" through and including the date of determination), and (if applicable) the application of the net proceeds therefrom (and from any other such Indebtedness), including to refinance other Indebtedness, had been incurred on the first day of such four-quarter period and, in the case of Acquired Indebtedness, on the assumption that the related transaction (whether by means of purchase, merger or otherwise) also had occurred on such date with the appropriate adjustments with respect to such acquisition being included in such pro forma calculation and (B) any acquisition or disposition by the Company or any Restricted Subsidiary of any properties or assets outside the ordinary course of business, or any repayment of any principal amount of any Indebtedness of the Company or any Restricted Subsidiary prior to the Stated Maturity thereof, in either case since the first day of such period of four full fiscal quarters through and including the date of determination, had been consummated on such first day of such four-quarter period, (ii) in making such computation, the Consolidated Interest Expense attributable to interest on any Indebtedness required to be computed on a pro forma basis in accordance with the covenant described under "-- Certain Covenants -- Limitation on Indebtedness and Disqualified Capital Stock" and (A) bearing a floating interest rate shall be computed as if the rate in effect on the date of computation had been the applicable rate for the entire period and (B) which was not outstanding during the period for which the computation is being made but which bears, at the option of the Company, a fixed or floating rate of interest, shall be computed by applying, at the option of the Company, either the fixed or floating rate, (iii) in making such computation, the Consolidated Interest Expense attributable to interest on any Indebtedness under a revolving credit facility required to be computed on a pro forma basis in accordance with the covenant described under "-- Certain Covenants -- Limitation on Indebtedness and Disqualified Capital Stock" shall be computed based upon the average daily balance of such Indebtedness during the applicable period, provided that such average daily balance shall be reduced by the amount of any repayment of Indebtedness under a revolving credit facility during the applicable period, which repayment permanently reduced the commitments or amounts available to be reborrowed under such facility, (iv) notwithstanding clauses (ii) and (iii) of this proviso, interest on Indebtedness determined on a fluctuating basis, to the extent such interest is covered by agreements relating to Interest Rate Protection Obligations, shall be deemed to have accrued at the rate per annum resulting after giving effect to the operation of such agreements, (v) in making such 71 72 calculation, Consolidated Interest Expense shall exclude interest attributable to Dollar-Denominated Production Payments, and (vi) if after the first day of the period referred to in clause (a) of this definition the Company has permanently retired any Indebtedness out of the Net Cash Proceeds of the issuance and sale of shares of Qualified Capital Stock of the Company within 30 days of such issuance and sale, Consolidated Interest Expense shall be calculated on a pro forma basis as if such Indebtedness had been retired on the first day of such period. "Consolidated Income Tax Expense" means, for any period, the provision for federal, state, local and foreign income taxes (including state franchise taxes accounted for as income taxes in accordance with GAAP) of the Company and its Restricted Subsidiaries for such period as determined on a consolidated basis in accordance with GAAP. "Consolidated Interest Expense" means, for any period, without duplication, the sum of (i) the interest expense of the Company and its Restricted Subsidiaries for such period as determined on a consolidated basis in accordance with GAAP, including, without limitation, (a) any amortization of debt discount, (b) the net cost under Interest Rate Protection Obligations (including any amortization of discounts), (c) the interest portion of any deferred payment obligation constituting Indebtedness, (d) all commissions, discounts and other fees and charges owed with respect to letters of credit and bankers' acceptance financing and (e) all accrued interest, in each case to the extent attributable to such period, (ii) to the extent any Indebtedness of any Person (other than the Company or a Restricted Subsidiary) is guaranteed by the Company or any Restricted Subsidiary, the aggregate amount of interest paid (to the extent not accrued in a prior period) or accrued by such other Person during such period attributable to any such Indebtedness, in each case to the extent attributable to that period, (iii) the aggregate amount of the interest component of Capitalized Lease Obligations paid (to the extent not accrued in a prior period), accrued or scheduled to be paid or accrued by the Company and its Restricted Subsidiaries during such period as determined on a consolidated basis in accordance with GAAP and (iv) the aggregate amount of dividends paid (to the extent not accrued in a prior period) or accrued on Preferred Stock or Disqualified Capital Stock of the Company and its Restricted Subsidiaries, to the extent such Preferred Stock or Disqualified Capital Stock is owned by Persons other than Restricted Subsidiaries, less, to the extent included in any of clauses (i) through (iv), amortization of capitalized debt issuance costs of the Company and its Restricted Subsidiaries during such period. "Consolidated Net Income" means, for any period, the consolidated net income (or loss) of the Company and its Restricted Subsidiaries for such period as determined in accordance with GAAP, adjusted by excluding (a) net after-tax extraordinary gains or losses (less all fees and expenses relating thereto), (b) net after-tax gains or losses (less all fees and expenses relating thereto) attributable to Asset Sales, (c) the net income (or net loss) of any Person (other than the Company or any of its Restricted Subsidiaries), in which the Company or any of its Restricted Subsidiaries has an ownership interest, except to the extent of the amount of dividends or other distributions actually paid to the Company or any of its Restricted Subsidiaries in cash by such other Person during such period (regardless of whether such cash dividends or distributions is attributable to net income (or net loss) of such Person during such period or during any prior period), (d) net income (or net loss) of any Person combined with the Company or any of its Restricted Subsidiaries on a "pooling of interests" basis attributable to any period prior to the date of combination, (e) the net income of any Restricted Subsidiary to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary is not at the date of determination permitted, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, (f) income resulting from transfers of assets received by the Company or any Restricted Subsidiary from an Unrestricted Subsidiary and (g) any write-downs of non-current assets, provided, however, that any ceiling limitation writedowns under Commission guidelines shall be treated as capitalized costs, as if such writedowns had not occurred. "Consolidated Net Worth" means, at any date, the consolidated stockholders' equity of the Company less the amount of such stockholders' equity attributable to Disqualified Capital Stock or treasury stock of the Company and its Restricted Subsidiaries, as determined in accordance with GAAP. 72 73 "Consolidated Non-cash Charges" means, for any period, the aggregate depreciation, depletion, amortization and other non-cash expenses of the Company and its Restricted Subsidiaries reducing Consolidated Net Income for such period, determined on a consolidated basis in accordance with GAAP (excluding any such non-cash charge for which an accrual of or reserve for cash charges for any future period is required). "Default" means any event, act or condition that is, or after notice or passage of time or both would become, an Event of Default. "Designated Senior Indebtedness" means (i) any Senior Indebtedness under or in respect of any of the Bank Credit Facilities and the Senior Notes and (ii) any other Senior Indebtedness permitted under the Indenture the principal amount of which is $5 million or more and, in the case of this clause (ii), that has been designated by the Company in an Officers' Certificate delivered to the Trustee as "Designated Senior Indebtedness." "Disinterested Director" means, with respect to any transaction or series of transactions in respect of which the Board of Directors of the Company is required to deliver a resolution of the Board of Directors under the Indenture, a member of the Board of Directors of the Company who does not have any material direct or indirect financial interest (other than an interest arising solely from the beneficial ownership of Capital Stock of the Company) in or with respect to such transaction or series of transactions. "Disqualified Capital Stock" means any Capital Stock that, either by its terms, by the terms of any security into which it is convertible or exchangeable or by contract or otherwise, is, or upon the happening of an event or passage of time would be, required to be redeemed or repurchased prior to the final Stated Maturity of the Notes or is redeemable at the option of the holder thereof at any time prior to such final Stated Maturity, or is convertible into or exchangeable for debt securities at any time prior to such final Stated Maturity. For purposes of the covenant described under "-- Certain Covenants -- Limitation on Indebtedness and Disqualified Capital Stock" covenant, Disqualified Capital Stock shall be valued at the greater of its voluntary or involuntary maximum fixed redemption or repurchase price plus accrued and unpaid dividends. For such purposes, the "maximum fixed redemption or repurchase price" of any Disqualified Capital Stock which does not have a fixed redemption or repurchase price shall be calculated in accordance with the terms of such Disqualified Capital Stock as if such Disqualified Capital Stock were redeemed or repurchased on the date of determination, and if such price is based upon, or measured by, the fair market value of such Disqualified Capital Stock, such fair market value shall be determined in good faith by the board of directors of the issuer of such Disqualified Capital Stock; provided, however, that if such Disqualified Capital Stock is not at the date of determination permitted or required to be redeemed or repurchased, the "maximum fixed redemption or repurchase price" shall be the book value of such Disqualified Capital Stock. "Dollar-Denominated Production Payments" means production payment obligations of the Company or a Restricted Subsidiary recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith. "Event of Default" has the meaning set forth above under the caption "Events of Default." "GAAP" means generally accepted accounting principles, consistently applied, that are set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as may be approved by a significant segment of the accounting profession of the United States of America, which are applicable as of the date of the Indenture. The term "guarantee" means, as applied to any obligation, (i) a guarantee (other than by endorsement of negotiable instruments for collection in the ordinary course of business), direct or indirect, in any manner, of any part or all of such obligation and (ii) an agreement, direct or indirect, contingent or otherwise, the practical effect of which is to assure in any way the payment or performance (or payment of damages in the event of non-performance) of all or any part of such obligation, including, without limiting the foregoing, the payment of amounts drawn down under letters of credit. When used as a verb, "guarantee" has a corresponding meaning. 73 74 "Holder" means a Person in whose name a Note is registered in the Note Register. "Indebtedness" means, with respect to any Person, without duplication, (a) all liabilities of such Person, contingent or otherwise, for borrowed money or for the deferred purchase price of property or services (excluding any trade accounts payable and other accrued current liabilities incurred in the ordinary course of business) and all liabilities of such Person incurred in connection with any agreement to purchase, redeem, exchange, convert or otherwise acquire for value any Capital Stock of such Person, or any warrants, rights or options to acquire such Capital Stock, outstanding on the date of the Indenture or thereafter, if, and to the extent, any of the foregoing would appear as a liability upon a balance sheet of such Person prepared in accordance with GAAP, (b) all obligations of such Person evidenced by bonds, notes, debentures or other similar instruments, if, and to the extent, any of the foregoing would appear as a liability upon a balance sheet of such Person prepared in accordance with GAAP, (c) all indebtedness of such Person created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person (even if the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), but excluding trade accounts payable arising in the ordinary course of business, (d) all Capitalized Lease Obligations of such Person, (e) all Indebtedness referred to in the preceding clauses of other Persons and all dividends of other Persons, the payment of which is secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien upon property (including, without limitation, accounts and contract rights) owned by such Person, even though such Person has not assumed or become liable for the payment of such Indebtedness (the amount of such obligation being deemed to be the lesser of the value of such property or the amount of the obligation so secured), (f) all guarantees by such Person of Indebtedness referred to in this definition (including, with respect to any Production Payment, any warranties or guaranties of production or payment by such Person with respect to such Production Payment but excluding other contractual obligations of such Person with respect to such Production Payment) and (g) all obligations of such Person under or in respect of currency exchange contracts, oil and natural gas price hedging arrangements and Interest Rate Protection Obligations. Subject to clause (f) of the first sentence of this definition, neither Dollar-Denominated Production Payments nor Volumetric Production Payments shall be deemed to be Indebtedness. In addition, Disqualified Capital Stock shall not be deemed to be Indebtedness. "Interest Rate Protection Obligations" means the obligations of any Person pursuant to any arrangement with any other Person whereby, directly or indirectly, such Person is entitled to receive from time to time periodic payments calculated by applying either a floating or a fixed rate of interest on a stated notional amount in exchange for periodic payments made by such Person calculated by applying a fixed or a floating rate of interest on the same notional amount and shall include, without limitation, interest rate swaps, caps, floors, collars and similar agreements or arrangements designed to protect against or manage such Person's and any of its Subsidiaries exposure to fluctuations in interest rates. "Investment" means, with respect to any Person, any direct or indirect advance, loan, guarantee of Indebtedness or other extension of credit or capital contribution to (by means of any transfer of cash or other property or assets to others or any payment for property, assets or services for the account or use of others), or any purchase or acquisition by such Person of any Capital Stock, bonds, notes, debentures or other securities (including derivatives) or evidences of Indebtedness issued by, any other Person. In addition, the fair market value of the net assets of any Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary shall be deemed to be an "Investment" made by the Company in such Unrestricted Subsidiary at such time. "Investments" shall exclude (a) extensions of trade credit or other advances to customers on commercially reasonable terms in accordance with normal trade practices or otherwise in the ordinary course of business, (b) Interest Rate Protection Obligations entered into in the ordinary course of business or as required by any Permitted Indebtedness or any Indebtedness incurred in compliance with the "Limitation on Indebtedness and Disqualified Capital Stock" covenant, but only to the extent that the notional amounts of such Interest Rate Protection Obligations do not exceed 105% of the aggregate principal amount of such Indebtedness to which such Interest Rate Protection Obligations relate and (c) endorsements of negotiable instruments and documents in the ordinary course of business. 74 75 "Lien" means any mortgage, charge, pledge, lien (statutory or other), security interest, hypothecation, assignment for security, claim or similar type of encumbrance (including, without limitation, any agreement to give or grant any lease, conditional sale or other title retention agreement having substantially the same economic effect as any of the foregoing) upon or with respect to any property of any kind. A Person shall be deemed to own subject to a Lien any property which such Person has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement. "Maturity" means, with respect to any Note, the date on which any principal of such Note becomes due and payable as therein or in the Indenture provided, whether at the Stated Maturity with respect to such principal or by declaration of acceleration, call for redemption or purchase or otherwise. "Moody's" means Moody's Investors Service, Inc. and its successors. "Net Available Proceeds" means, with respect to any Asset Sale, the proceeds thereof in the form of cash or Cash Equivalents including payments in respect of deferred payment obligations when received in the form of cash or Cash Equivalents (except to the extent that such obligations are financed or sold with recourse to the Company or any Restricted Subsidiary), net of (i) brokerage commissions and other fees and expenses (including fees and expenses of legal counsel, accountants and investment banks) related to such Asset Sale, (ii) provisions for all taxes payable as a result of such Asset Sale, (iii) amounts required to be paid to any Person (other than the Company or any Restricted Subsidiary) owning a beneficial interest in the assets subject to the Asset Sale or having a Lien thereon and (iv) appropriate amounts to be provided by the Company or any Restricted Subsidiary, as the case may be, as a reserve required in accordance with GAAP consistently applied against any liabilities associated with such Asset Sale and retained by the Company or any Restricted Subsidiary, as the case may be, after such Asset Sale, including, without limitation, pension and other post-employment benefit liabilities, liabilities related to environmental matters and liabilities under any indemnification obligations associated with such Asset Sale, all as reflected in an Officers Certificate delivered to the Trustee; provided, however, that any amounts remaining after adjustments, revaluations or liquidations of such reserves shall constitute Net Available Proceeds. "Net Cash Proceeds," with respect to any issuance or sale of Qualified Capital Stock or other securities, means the cash proceeds of such issuance or sale net of attorneys' fees, accountants' fees, underwriters' or placement agents' fees, discounts or commissions and brokerage, consultant and other fees and expenses actually incurred in connection with such issuance or sale and net of taxes paid or payable as a result thereof. "Non-Recourse Indebtedness" means Indebtedness or that portion of Indebtedness of the Company or any Restricted Subsidiary incurred in connection with the acquisition by the Company or such Restricted Subsidiary of any property or assets and as to which (a) the holders of such Indebtedness agree that they will look solely to the property or assets so acquired and securing such Indebtedness for payment on or in respect of such Indebtedness, and neither the Company nor any Subsidiary (other than an Unrestricted Subsidiary) (i) provides credit support, including any undertaking, agreement or instrument which would constitute Indebtedness or (ii) is directly or indirectly liable for such Indebtedness, and (b) no default with respect to such Indebtedness would permit (after notice or passage of time or both), according to the terms thereof, any holder of any Indebtedness of the Company or a Restricted Subsidiary to declare a default on such Indebtedness or cause the payment thereof to be accelerated or payable prior to its Stated Maturity. "Note Register" means the register maintained by or for the Company in which the Company shall provide for the registration of the Notes and the transfer of the Notes. "Oil and Gas Business" means (i) the acquisition, exploration, development, operation and disposition of interests in oil, gas and other hydrocarbon properties, (ii) the gathering, marketing, treating, processing, storage, refining, selling and transporting of any production from such interests or properties, (iii) any business relating to or arising from exploration for or development, production, treatment, processing, storage, refining, transportation or marketing of oil, gas and other minerals and products produced in association therewith, and (iv) any activity necessary, appropriate or incidental to the activities described in the foregoing clauses (i) through (iii) of this definition. 75 76 "Pari Passu Indebtedness" means (i) Indebtedness of the Company that ranks pari passu in right of payment to the Notes and (ii) Indebtedness of any Restricted Subsidiary that ranks pari passu in right of payment to the Subsidiary Guarantees. "Permitted Indebtedness" means any of the following: (i) Indebtedness under the Bank Credit Facilities in an aggregate principal amount at any one time outstanding not to exceed the greater of $165 million or the borrowing base thereunder (the "Maximum Credit Amount"), plus all interest and fees under such facilities and any guarantee of any such Indebtedness; (ii) Indebtedness under the Offered Notes; (iii) Indebtedness outstanding or in effect on the date of the Indenture (and not repaid or defeased with the proceeds of the offering of the Notes); (iv) obligations pursuant to Interest Rate Protection Obligations, but only to the extent such obligations do not exceed 105% of the aggregate principal amount of the Indebtedness covered by such Interest Rate Protection Obligations; obligations under currency exchange contracts entered into in the ordinary course of business; hedging arrangements entered into in the ordinary course of business for the purpose of protecting production, purchases and resales against fluctuations in oil or natural gas prices; and any guarantee of any of the foregoing; (v) the Subsidiary Guarantees of the Notes (and any assumption of the obligations guaranteed thereby); (vi) Indebtedness of the Company to any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary to the Company or any other Restricted Subsidiary; (vii) Permitted Refinancing Indebtedness and any guarantee thereof; (viii) Non-Recourse Indebtedness; (ix) Indebtedness in respect of bid, performance or surety bonds issued for the account of the Company or any Restricted Subsidiary in the ordinary course of business, including guaranties and letters of credit supporting such bid, performance or surety obligations (in each case other than for an obligation for money borrowed); and (x) any additional Indebtedness in an aggregate principal amount not in excess of $25 million at any one time outstanding and any guarantee thereof. "Permitted Investments" means any of the following: (i) Investments in Cash Equivalents; (ii) Investments in the Company or any of its Restricted Subsidiaries; (iii) Investments in an amount not to exceed $10 million at any one time outstanding; (iv) Investments by the Company or any of its Restricted Subsidiaries in another Person, if as a result of such Investment (A) such other Person becomes a Restricted Subsidiary or (B) such other Person is merged or consolidated with or into, or transfers or conveys all or substantially all of its properties and assets to, the Company or a Restricted Subsidiary; (v) entry into operating agreements, joint ventures, partnership agreements, working interests, royalty interests, mineral leases, processing agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil and natural gas, unitization agreements, pooling arrangements, area of mutual interest agreements or other similar or customary agreements, transactions, properties, interests or arrangements, and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Oil and Gas Business, excluding, however, Investments in corporations; (vi) entry into any hedging arrangements in the ordinary course of business for the purpose of protecting the Company's or any Restricted Subsidiary's production, purchases and resales against fluctuations in oil or natural gas prices; (vii) Investments permitted under the "Limitation on Asset Sales" covenant or the "Limitation on Transactions with Affiliates" covenant; (viii) entry into any currency exchange contract in the ordinary course of business; or (ix) Investments in stock, obligations or securities received in settlement of debts owing to the Company or any Restricted Subsidiary as a result of bankruptcy or insolvency proceedings or upon the foreclosure, perfection or enforcement of any Lien in favor of the Company or any Restricted Subsidiary, in 76 77 each case as to debt owing to the Company or any Restricted Subsidiary that arose in the ordinary course of business of the Company or any such Restricted Subsidiary. "Permitted Liens" means the following types of Liens: (a) Liens existing as of the date of the Indenture (except to the extent such Liens secure Indebtedness that is repaid or defeased with proceeds of the offering of the Notes); (b) Liens securing the Notes or the Subsidiary Guarantees; (c) Liens in favor of the Company or any Restricted Subsidiary; (d) Liens securing Senior Indebtedness that is permitted by the terms of the Indenture; (e) Liens for taxes, assessments and governmental charges or claims either (i) not delinquent or (ii) contested in good faith by appropriate proceedings and as to which the Company or its Restricted Subsidiaries shall have set aside on its books such reserves as may be required pursuant to GAAP; (f) statutory Liens of landlords and Liens of carriers, warehousemen, mechanics, suppliers, materialmen, repairmen and other Liens imposed by law incurred in the ordinary course of business for sums not delinquent or being contested in good faith, if such reserve or other appropriate provision, if any, as shall be required by GAAP shall have been made in respect thereof; (g) Liens incurred or deposits made in the ordinary course of business in connection with workers' compensation, unemployment insurance and other types of social security, or to secure the payment or performance of tenders, statutory or regulatory obligations, surety and appeal bonds, bids, government contracts and leases, performance and return of money bonds and other similar obligations (exclusive of obligations for the payment of borrowed money but including lessee or operator obligations under statutes, governmental regulations or instruments related to the ownership, exploration and production of oil, gas and minerals on state, Federal or foreign lands or waters); (h) judgment and attachment Liens not giving rise to an Event of Default so long as any appropriate legal proceedings which may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such proceeding may be initiated shall not have expired; (i) easements, rights-of-way, restrictions and other similar charges or encumbrances not interfering in any material respect with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries; (j) any interest or title of a lessor under any Capitalized Lease Obligation or operating lease; (k) purchase money Liens; provided, however, that (i) the related purchase money Indebtedness shall not be secured by any property or assets of the Company or any Restricted Subsidiary other than the property or assets so acquired (including, without limitation, those acquired indirectly through the acquisition of stock or other ownership interests) and any proceeds therefrom and (ii) the Lien securing such Indebtedness shall be created within 90 days of such acquisition; (l) Liens securing obligations under hedging agreements that the Company or any Restricted Subsidiary enters into in the ordinary course of business for the purpose of protecting its production, purchases and resales against fluctuations in oil or natural gas prices; (m) Liens upon specific items of inventory or other goods of any Person securing such Person's obligations in respect of bankers acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods; (n) Liens securing reimbursement obligations with respect to commercial letters of credit which encumber documents and other property or assets relating to such letters of credit and products and proceeds thereof; (o) Liens encumbering property or assets under construction arising from progress or partial payments by a customer of the Company or its Restricted Subsidiaries relating to such property or assets; 77 78 (p) Liens encumbering deposits made to secure obligations arising from statutory, regulatory, contractual or warranty requirements of the Company or any of its Restricted Subsidiaries, including rights of offset and set-off; (q) Liens securing Interest Rate Protection Obligations which Interest Rate Protection Obligations relate to Indebtedness that is secured by Liens otherwise permitted under the Indenture; (r) Liens on, or related to, properties or assets to secure all or part of the costs incurred in the ordinary course of business for the exploration, drilling, development or operation thereof; (s) Liens on pipeline or pipeline facilities which arise by operation of law; (t) Liens arising under operating agreements, joint venture agreements, partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements and other agreements which are customary in the Oil and Gas Business; (u) Liens reserved in oil and gas mineral leases for bonus or rental payments or for compliance with the terms of such leases; (v) Liens constituting survey exceptions, encumbrances, easements, or reservations of, or rights to others for, rights-of-way, zoning or other restrictions as to the use of real properties, and minor defects of title which, in the case of any of the foregoing, were not incurred or created to secure the payment of borrowed money or the deferred purchase price of property, assets or services, and in the aggregate do not materially adversely affect the value of properties and assets of the Company and the Restricted Subsidiaries, taken as a whole, or materially impair the use of such properties and assets for the purposes for which such properties and assets are held by the Company or any Restricted Subsidiaries; (w) Liens securing Non-Recourse Indebtedness; provided, however, that the related Non-Recourse Indebtedness shall not be secured by any property or assets of the Company or any Restricted Subsidiary other than the property and assets acquired (including, without limitation, those acquired indirectly through the acquisition of stock or other ownership interests) by the Company or any Restricted Subsidiary with the proceeds of such Non-Recourse Indebtedness; and (x) Liens resulting from the deposit of funds or evidences of Indebtedness in trust for the purpose of defeasing Indebtedness of the Company or any of its Restricted Subsidiaries. Notwithstanding anything in clauses (a) through (x) of this definition, the term "Permitted Liens" does not include any Liens resulting from the creation, incurrence, issuance, assumption or guarantee of any Production Payments other than Production Payments that are created, incurred, issued, assumed or guaranteed in connection with the financing of, and within 30 days after, the acquisition of the properties or assets that are subject thereto. "Permitted Refinancing Indebtedness" means Indebtedness of the Company or a Restricted Subsidiary, the net proceeds of which are used to renew, extend, refinance, refund or repurchase (including, without limitation, pursuant to a Change of Control Offer or Net Proceeds Offer) outstanding Indebtedness of the Company or any Restricted Subsidiary, provided that (a) if the Indebtedness (including the Notes) being renewed, extended, refinanced, refunded or repurchased is pari passu with or subordinated in right of payment to either the Notes or the Subsidiary Guarantees, then such Indebtedness is pari passu with or subordinated in right of payment to the Notes or the Subsidiary Guarantees, as the case may be, at least to the same extent as the Indebtedness being renewed, extended, refinanced, refunded or repurchased, (b) such Indebtedness has a Stated Maturity for its final scheduled principal payment that is no earlier than the Stated Maturity for the final scheduled principal payment of the Indebtedness being renewed, extended, refinanced, refunded or repurchased and (c) such Indebtedness has an Average Life at the time such Indebtedness is incurred that is equal to or greater than the Average Life of the Indebtedness being renewed, extended, refinanced, refunded or repurchased; provided, further, that such Indebtedness is in an aggregate principal amount (or, if such Indebtedness is issued at a price less than the principal amount thereof, the aggregate amount of gross 78 79 proceeds therefrom is) not in excess of the aggregate principal amount then outstanding of the Indebtedness being renewed, extended, refinanced, refunded or repurchased (or if the Indebtedness being renewed, extended, refinanced, refunded or repurchased was issued at a price less than the principal amount thereof, then not in excess of the amount of liability in respect thereof determined in accordance with GAAP) plus the amount of any premium required to be paid in connection with such renewal, extension or refinancing, refunding or repurchase pursuant to the terms of the Indebtedness being renewed, extended, refinanced, refunded or repurchased or the amount of any premium reasonably determined by the Company as necessary to accomplish such renewal, extension, refinancing, refunding or repurchase, plus the amount of reasonable fees and expenses incurred by the Company or such Restricted Subsidiary in connection therewith. "Person" means any individual, corporation, limited liability company, partnership, joint venture, association, joint stock company, trust, unincorporated organization or government or any agency or political subdivision thereof. "Preferred Stock" means, with respect to any Person, any and all shares, interests, participations or other equivalents (however designated) of such Person's preferred or preference stock, whether now outstanding or issued after the date of the Indenture, including, without limitation, all classes and series of preferred or preference stock of such Person. "Production Payments" means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments. "Public Equity Offering" means an offer and sale of Common Stock of the Company pursuant to a registration statement that has been declared effective by the Commission pursuant to the Securities Act (other than a registration statement on Form S-8 or otherwise relating to equity securities issuable under any employee benefit plan of the Company). "Qualified Capital Stock" of any Person means any and all Capital Stock of such Person other than Disqualified Capital Stock. "Restricted Investment" means (without duplication) (i) the designation of a Subsidiary as an Unrestricted Subsidiary in the manner described in the definition of "Unrestricted Subsidiary" and (ii) any Investment other than a Permitted Investment. "Restricted Subsidiary" means any Subsidiary of the Company, whether existing on or after the date of the Indenture, unless such Subsidiary of the Company is an Unrestricted Subsidiary or is designated as an Unrestricted Subsidiary pursuant to the terms of the Indenture. "S&P" means Standard and Poor's Ratings Services, a division of The McGraw-Hill Companies, Inc., and its successors. "Senior Indebtedness" means (i) Indebtedness or other obligations under or in respect of any of the Bank Credit Facilities, (ii) Indebtedness under or in respect of the Senior Notes, (iii) any other Indebtedness permitted to be incurred by the Company or any Restricted Subsidiary under the terms of the Indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is on a parity with or subordinated in right of payment to the Notes or the Subsidiary Guarantees, as the case may be, (iv) all interest, fees and other obligations in respect of any Indebtedness referred to in the foregoing clauses (i) through (iii) and (v) any amounts due to the Trustee under the Indenture as fees, expenses or indemnities and other amounts. "Stated Maturity" means, when used with respect to any Indebtedness or any installment of interest thereon, the date specified in the instrument evidencing or governing such Indebtedness as the fixed date on which the principal of such Indebtedness or such installment of interest is due and payable. "Subordinated Indebtedness" means Indebtedness of the Company or a Subsidiary Guarantor which is expressly subordinated in right of payment to the Notes or the Subsidiary Guarantees, as the case may be. "Subsidiary" means, with respect to any Person, (i) a corporation a majority of whose Voting Stock is at the time, directly or indirectly, owned by such Person, by one or more Subsidiaries of such Person or by such 79 80 Person and one or more Subsidiaries thereof or (ii) any other Person (other than a corporation), including, without limitation, a joint venture, in which such Person, one or more Subsidiaries thereof or such Person and one or more Subsidiaries thereof, directly or indirectly, at the date of determination thereof, have at least majority ownership interest entitled to vote in the election of directors, managers or trustees thereof (or other Person performing similar functions). "Subsidiary Guarantee" means any guarantee of the Notes by any Subsidiary Guarantor in accordance with the provisions described under "-- Subsidiary Guarantees of Notes. "Subsidiary Guarantor" means (i) KCS Resources, Inc., (ii) KCS Michigan Resources, Inc., (iii) KCS Energy Marketing, Inc., (iv) KCS Medallion Resources, Inc., (v) KCS Energy Services, Inc., (vi) Medallion California Properties Co., (vii) Medallion Gas Services, Inc., (viii) National Enerdrill Corporation, (ix) Proliq, Inc., (x) each of the Company's other Restricted Subsidiaries, if any, executing a supplemental indenture in which such Subsidiary agrees to be bound by the terms of the Indenture and (xi) any Person that becomes a successor guarantor of the Notes in compliance with the provisions described under "-- Subsidiary Guarantees of Notes. "Unrestricted Subsidiary" means (i) any Subsidiary of the Company that at the time of determination will be designated an Unrestricted Subsidiary by the Board of Directors of the Company as provided below and (ii) any Subsidiary of an Unrestricted Subsidiary. The Board of Directors of the Company may designate any Subsidiary of the Company as an Unrestricted Subsidiary so long as (a) neither the Company nor any Restricted Subsidiary is directly or indirectly liable pursuant to the terms of any Indebtedness of such Subsidiary; (b) no default with respect to any Indebtedness of such Subsidiary would permit (upon notice, lapse of time or otherwise) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default on such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its Stated Maturity; (c) such designation as an Unrestricted Subsidiary would be permitted under the "Limitation on Restricted Payments" covenant; and (d) such designation shall not result in the creation or imposition of any Lien on any of the properties or assets of the Company or any Restricted Subsidiary (other than any Permitted Lien or any Lien the creation or imposition of which shall have been in compliance with the "Limitation on Liens" covenant); provided, however, that with respect to clause (a), the Company or a Restricted Subsidiary may be liable for Indebtedness of an Unrestricted Subsidiary if (x) such liability constituted a Permitted Investment or a Restricted Payment permitted by the "Limitation on Restricted Payments" covenant, in each case at the time of incurrence, or (y) the liability would be a Permitted Investment at the time of designation of such Subsidiary as an Unrestricted Subsidiary. Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing a Board Resolution with the Trustee giving effect to such designation. The Board of Directors of the Company may designate any Unrestricted Subsidiary as a Restricted Subsidiary if, immediately after giving effect to such designation on a pro forma basis, (i) no Default or Event of Default shall have occurred and be continuing, (ii) the Company could incur $1.00 of additional Indebtedness (not including the incurrence of Permitted Indebtedness) under the "Limitation on Indebtedness and Disqualified Capital Stock" covenant and (iii) if any of the properties and assets of the Company or any of its Restricted Subsidiaries would upon such designation become subject to any Lien (other than a Permitted Lien), the creation or imposition of such Lien shall have been in compliance with the "Limitation on Liens" covenant. "Volumetric Production Payments" means production payment obligations of the Company or a Restricted Subsidiary recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith. "Voting Stock" means any class or classes of Capital Stock pursuant to which the holders thereof have the general voting power under ordinary circumstances to elect at least a majority of the board of directors, managers or trustees of any Person (irrespective of whether or not, at the time, stock of any other class or classes shall have, or might have, voting power by reason of the happening of any contingency). FORM, DENOMINATION AND REGISTRATION The Notes will be issued in fully registered form, without coupons, in denominations of $1,000 in principal amount and integral multiples thereof. 80 81 Global Notes; Book-Entry Form Except as set forth below, the Notes will initially be issued in the form of one or more registered Notes in global form (the "Global Notes"). Each Global Note will be deposited on its issue date with, or on behalf of, DTC and registered in the name of Cede & Co. ("Cede"), as nominee. The Holders of Notes may hold their interests in the Global Notes directly through DTC if such Holder is a participant in DTC, or indirectly through organizations which are participants in DTC (the "Participants"). Transfers between Participants will be effected in the ordinary way in accordance with DTC rules and will be settled in same day funds. The laws of some states require that certain persons take physical delivery of securities in definitive form. Consequently, the ability to transfer beneficial interests in the Global Notes to such persons may be limited. The Holders of Notes who are not Participants may beneficially own interests in the Global Notes held by DTC only through Participants or certain banks, brokers, dealers, trust companies and other parties that clear through or maintain a custodial relationship with a Participant, either directly or indirectly ("Indirect Participants"). So long as Cede, as the nominee of DTC, is the registered owner of the Global Notes, Cede for all purposes will be considered the sole holder of the Global Notes. Payment of interest on and the redemption price or Change of Control Purchase Price (upon redemption at the option of the Company or repurchase at the option of the Holder upon a Change of Control) of the Global Notes will be made to Cede, the nominee for DTC, as the registered owner of the Global Notes, by wire transfer of immediately available funds. Neither the Company, the Trustee nor any Paying Agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests. The Company has been informed by DTC that, with respect to any payment of interest on and the redemption price or Change of Control Purchase Price (upon redemption at the option of the Company or repurchase at the option of the Holder upon a Change of Control) of the Global Notes, DTC's practice is to credit Participants' accounts on the payment date therefor with payments in amounts proportionate to their respective beneficial interests in the Notes represented by the Global Notes as shown on the records of DTC, unless DTC has reason to believe that it will not receive payment on such payment date. Payments by Participants to owners of beneficial interests in Notes represented by the Global Notes held through such Participants will be the responsibility of such Participants, as is now the case with securities held for the accounts of customers registered in "street name." Because DTC can only act on behalf of Participants, who in turn act on behalf of Indirect Participants and certain banks, the ability of a person having a beneficial interest in Notes represented by the Global Notes to pledge such interest to persons or entities that do not participate in the DTC system, or otherwise take actions in respect of such interest, may be affected by the lack of a physical certificate evidencing such interest. Neither the Company nor the Trustee (or any registrar or other agent under the Indenture) will have any responsibility for the performance by DTC or its Participants or Indirect Participants of their respective obligations under the rules and procedures governing their operations. DTC has advised the Company that it will take any action permitted to be taken by a holder of Notes (including, without limitation, the presentation of Notes for exchange as described below), only at the direction of one or more Participants to whose account with DTC interests in the Global Note are credited, and only in respect of the principal amount of the Notes represented by the Global Note as to which such Participant or Participants has or have given such direction. DTC has advised the Company as follows: DTC is a limited purpose trust company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code and a "clearing agency" registered pursuant to the provisions of Section 17A of the Exchange Act. DTC holds securities that its Participants deposit with DTC. DTC also facilitates the clearance and settlement of securities transactions between Participants through electronic book-entry 81 82 changes to the accounts of its Participants, thereby eliminating the need for physical movement of certificates. Participants include securities brokers and dealers, banks, trust companies and clearing corporations. Certain of such Participants (or their representatives), together with other entities, own DTC. Indirect access to the DTC system is available to others such as banks, brokers, dealers and trust companies that clear through, or maintain a custodial relationship with, a Participant, either directly or indirectly. Although DTC has agreed to the foregoing procedures in order to facilitate transfers of interests in each Global Note among Participants, it is under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. If DTC is at any time unwilling or unable to continue as depositary and a successor depositary is not appointed by the Company within 90 days, or at the Company's election at any time, the Company will cause the Notes to be issued in definitive form in exchange for the Global Notes. Certificated Notes Holders of Notes may request that certificated Notes be issued in exchange for Notes represented by the Global Note. In addition, certificated Notes may be issued in exchange for Notes represented by the Global Note in the circumstances described in the paragraph immediately prior to this one. UNDERWRITING Under the terms and subject to the conditions contained in the Underwriting Agreement dated the date hereof (the "Underwriting Agreement"), each of the underwriters named below (the "Underwriters") has severally agreed to purchase from the Company the principal amount of Notes set forth opposite the name of such Underwriter below:
PRINCIPAL AMOUNT UNDERWRITERS OF NOTES ------------ ---------------- Salomon Brothers Inc........................................ $ 62,500,000 Prudential Securities Incorporated ......................... 25,000,000 CIBC Oppenheimer Corp. ..................................... 12,500,000 Jefferies and Company, Inc. ................................ 12,500,000 Morgan Keegan & Company, Inc. .............................. 12,500,000 ------------ Total............................................. $125,000,000 ============
The Underwriting Agreement provides that the obligations of the several Underwriters to pay for and accept delivery of the Notes offered hereby are subject to the approval of certain legal matters by counsel and to certain other conditions. The Underwriters will be obligated to take and pay for all of the Notes offered hereby if any of such Notes are purchased. The Underwriters initially propose to offer part of the Notes offered hereby directly to the public at the public offering price set forth on the cover page of this Prospectus and part of the Notes offered hereby to certain dealers at a price which represents a concession not in excess of 0.5% of the principal amount per Note under the price to public. The Underwriters may allow, and such dealers may reallow, a concession not in excess of 0.25% of the principal amount per Note to certain other dealers. After the Offering, the public offering price and such concessions may be changed by the Underwriters. In connection with the Offering and in compliance with applicable law, the Underwriters may engage in transactions which stabilize or maintain the market price of the Notes at levels above those which might otherwise prevail in the open market. For the purposes of covering a syndicate short position or stabilizing the price of the Notes, the Underwriters may place bids for the Notes or effect purchases of the Notes in the open market. Finally, the Underwriters may impose a penalty bid on certain Underwriters and dealers. This means that the underwriting syndicate may reclaim selling concessions allowed to an Underwriter or a dealer for distributing the Notes in the Offering if the syndicate repurchases previously distributed Notes in transactions 82 83 to cover syndicate short positions, in stabilization transactions or otherwise. The Underwriters are not required to engage in any of these activities and any such activities, if commenced, may be discontinued at any time. The Company and the Underwriters have agreed to indemnify each other against certain liabilities, including liabilities under the Securities Act. The Notes have been approved for listing on the NYSE, subject to official notice of issuance. The Company has been advised by the Underwriters that they currently intend to make a market in the Notes. However, the Underwriters are not obligated to do so, and any market making may be discontinued at any time without any notice. There can be no assurance as to whether an active trading market for the Notes will develop. Canadian Imperial Bank of Commerce ("CIBC"), a lender to the Company under the Bank Credit Facilities, will receive its proportionate share of any repayment by the Company of amounts outstanding under the Bank Credit Facilities from the proceeds of the Offering. See "Use of Proceeds" and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Debt Financing." CIBC is an affiliate of CIBC Oppenheimer Corp., a member of the National Association of Securities Dealers, Inc. ("NASD"), who is participating in the distribution of the Offering. The Offering is therefore being conducted in accordance with Rule 2710(c)(8) of the NASD's Conduct Rules, and the price at which the Notes will be distributed to the public will be established pursuant to Rule 2720(c)(3) of the Conduct Rules. Salomon Brothers Inc is acting as a "qualified independent underwriter" within the meaning of such rules and is assuming the responsibilities of acting as such in pricing the Offering and conducting due diligence. Salomon Brothers Inc will receive no separate fee for its services as qualified independent underwriter. Certain of the Underwriters acted as representatives of the underwriters for the Company's public offering of Common Stock in January 1997 for which they received customary fees. CERTAIN LEGAL MATTERS The validity of the Notes offered hereby will be passed upon for the Company by Mayor, Day, Caldwell & Keeton, L.L.P., Houston, Texas. Certain legal matters relating to the sale of the Notes will be passed upon for the Underwriters by Vinson & Elkins L.L.P., Houston, Texas. EXPERTS The audited Consolidated Financial Statements and schedules of the Company included or incorporated by reference in this Prospectus and elsewhere in the Registration Statement have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto, and are included herein in reliance upon said firm as experts in giving said reports. Information set forth in this Prospectus relating to the Company's estimated proved oil and gas reserves at December 31, 1996, the related calculations of future net production revenues and the net present value thereof have been derived from independent reserve engineering reports prepared for the Company by Ryder Scott Company, H.J. Gruy and Associates, Inc., R.A. Lenser and Associates, Inc. and Netherland, Sewell and Associates, Inc. and all such information has been included in reliance on the authority of such firms as experts regarding the matters contained in their reports. Although reserve engineers' reports with respect to reserves underlying the Company's VPP program are utilized by the Company to support its own analysis of such reserves, the proved reserves, related future net revenues and PV-10 that the Company reports with respect to volumetric production payments are not derived from independent reserve engineers' report, but rather are taken directly from the amounts contracted for, pursuant to the agreements relating to each volumetric production payment (which amounts are less than the net interest production reflected in the reserve reports). A report prepared for the Company by Ryder Scott Company (covering the VPP program properties owned by the Company in the offshore Gulf Coast region) includes all the reserves of each field from which the Company's VPP interest is taken. 83 84 AVAILABLE INFORMATION The Company is subject to the information requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and, in accordance therewith, files reports, proxy statements and other information with the Securities and Exchange Commission (the "SEC" or "Commission"). The reports, proxy statements and other information may be inspected and copied at the offices of the Commission as stated above or at its regional offices located in The Citicorp Center, Suite 1400, 500 West Madison Street, Chicago, Illinois 60661 and Seven World Trade Center, Suite 1300, New York, New York 10048. Copies of such material also can be obtained from the Public Reference Section of the Commission, 450 Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates. In addition, the Commission maintains a web site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the Commission at ,http://www.sec.gov.. The Notes have been approved for listing (subject to official notice of issuance) on, and the Common Stock, par value $.01 per share, of the Company is traded on, the New York Stock Exchange, and as a result the reports, proxy statements and other information concerning the Company may be inspected at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005. The Company has filed a Registration Statement on Form S-3, including amendments thereto, relating to the Notes offered hereby (the "Registration Statement") with the Commission. This Prospectus does not contain all of the information set forth in the Registration Statement and the exhibits and schedules thereto, certain parts of which are omitted in accordance with rules and regulations of the Commission. Statements contained in this Prospectus as to the contents of any contract or other document referred to are not necessarily complete, and in each instance reference is made to the copy of such contract or other document filed as an exhibit to the Registration Statement or as previously filed with the Commission and incorporated herein by reference. For further information with respect to the Company and the Notes offered hereby, reference is made to such Registration Statement, exhibits and schedules. A copy of the Registration Statement may be inspected by anyone without charge at the Commission's principal office at 450 Fifth Street, N.W., Washington, D.C. 20549, and copies of all or any part thereof may be obtained from the Commission upon payment of certain fees prescribed by the Commission. INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The Company's (i) Annual Report on Form 10-K for the year ended December 31, 1996, (ii) Quarterly Report on Form 10-Q for the three months ended March 31, 1997, (iii) Quarterly Report on Form 10-Q for the three months ended June 30, 1997 and (iv) Quarterly Report on Form 10-Q for the three months ended September 30, 1997 are incorporated into this Prospectus by reference. Each document filed by the Company pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act, subsequent to the date of this Prospectus and prior to the termination of the offering of Notes made hereby shall be deemed to be incorporated herein by reference and to be a part hereof from the date of filing of such document. Any statement contained herein or in a document all or a portion of which is incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained herein or in any subsequently filed document which also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. The Company will provide without charge to each person to whom a copy of this Prospectus is delivered, on the request of any such person, a copy of any or all of the foregoing documents incorporated herein by reference (other than exhibits to such documents, unless such exhibits are specifically incorporated by reference into such documents). Requests should be directed to the Company at 379 Thornall Street, Edison, New Jersey 08837, Attention: Corporate Secretary (telephone: (732) 632-1770). 84 85 GLOSSARY The following are abbreviations and definitions of oil and gas terms used throughout this Prospectus. Amine. An aqueous organic chemical compound that has the ability to absorb acid gases (i.e. CO(2) and H(2)S) entrained in a natural gas stream that may then be regenerated by heating to expel these gases. bbl. Barrel of 42 U.S. gallons of crude oil or other liquid hydrocarbons. Bcf. Billion cubic feet. Bcfe. Billion cubic feet of natural gas equivalent. Btu. British thermal unit, which is the quantity of heat required to raise the temperature of one pound of water from 58.5 to 59.5 degrees Fahrenheit. Completion. Installation of permanent equipment for the production of oil or gas. Condensate. Hydrocarbon mixture that becomes liquid and separates from natural gas when the natural gas is produced. Similar to crude oil. Development location. A location on which a development well can be drilled. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive in an attempt to recover proved undeveloped reserves. EBITDA. EBITDA represents income before depletion, depreciation, amortization, interest expense, interest and other income and income taxes. EBITDA is a financial measure commonly used in the Company's industry and should not be considered in isolation or as a substitute for net income, cash flow provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of a company's profitability or liquidity. Exploratory well. A well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field which contains other productive oil or gas reservoirs. Finding Cost. An amount per Mcfe equal to the sum of all costs incurred relating to oil and gas property acquisition, exploration and development activities, less changes in unevaluated costs, divided by the sum of all additions and revisions to estimated proved reserves, including reserve purchases. Mcf equivalent ("Mcfe"). Mcf of natural gas equivalent, determined using the ratio of one bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas. Gross acres or gross wells. An acre or well in which a working interest is owned. Mbbl. One thousand barrels of crude oil or other liquid hydrocarbons. MMbbl. One million barrels of crude oil or other liquid hydrocarbons. MBtu. One thousand Btus. MMBtu. One million Btus. Mcf. One thousand cubic feet. Mcfe. One thousand cubic feet of natural gas equivalent. MMcf. One million cubic feet. MMcfe. One million cubic feet of natural gas equivalent. Net Acquisition Cost. An amount per Mcfe equal to the total purchase price allocated to oil and gas properties divided by the estimated proved reserves acquired. Net acres or net wells. The sum of the fractional working interests net to the Company owned in gross acres or gross wells. 85 86 Net production. Production after royalties and production due others. Overriding royalty interest. An interest in an oil and gas property entitling the owner to a share of oil or gas production, free of costs of production. Pre-tax present value of estimated future net revenues ("PV-10"). Estimated future net revenues before income taxes with no price or cost escalation or deescalation, in accordance with guidelines promulgated by the SEC and discounted using an annual discount rate of 10%. Productive well. A well that is producing oil or gas or that is capable of production. Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves. Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Recompletion. The completion for production of an existing wellbore in another formation from that in which the well has previously been completed. Reserve life. Calculation derived by dividing year-end reserves by total production in that year. Reserve replacement. Calculation derived by dividing additions to reserves from acquisitions, extensions, discoveries and revisions of previous estimates in a year by total production in that year. Sour gas. A natural gas stream containing more than 1/4 grain of hydrogen sulfide per 100 cubic feet of natural gas. 1/4 grain = 0.0003975% or 3.975 ppm (parts per million). Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas. Working interest. The operating interest which gives the owner the right to drill, produce and conduct operating activities on the property and a share of the production. Workover. Operations on a producing well to restore or increase production. 86 87 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS KCS Energy, Inc. and Subsidiaries Report of Independent Public Accountants.................. F-2 Statements of Consolidated Income for the years ended December 31, 1994, 1995 and 1996 and for the nine months ended September 30, 1996 and 1997 (unaudited)... F-3 Consolidated Balance Sheets at December 31, 1995 and 1996 and September 30, 1997 (unaudited)..................... F-4 Statements of Consolidated Stockholders' Equity for the years ended December 31, 1994, 1995 and 1996 and for the nine months ended September 30, 1997 (unaudited)... F-5 Statements of Consolidated Cash Flows for the years ended December 31, 1994, 1995 and 1996 and for the nine months ended September 30, 1996 and 1997 (unaudited)... F-6 Notes to Consolidated Financial Statements................ F-7
F-1 88 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, 1996 and 1995, and the related statements of consolidated income, stockholders' equity and cash flows for each of the three years in the period ended December 31, 1996. 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, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP New York, New York February 26, 1997 F-2 89 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME (DOLLARS IN THOUSANDS EXCEPT PER SHARE DATA)
FOR THE NINE MONTHS ENDED FOR THE YEARS ENDED DECEMBER 31, SEPTEMBER 30, --------------------------------------- ------------------------- 1994 1995 1996 1996 1997 ----------- ----------- ----------- ----------- ----------- (UNAUDITED) Revenue: Oil and gas revenue........... $ 66,215 $ 86,629 $ 108,015 $ 79,051 $ 100,396 Other revenue, net............ 1,185 486 359 377 3,702 ----------- ----------- ----------- ----------- ----------- Total................. 67,400 87,115 108,374 79,428 104,098 Operating costs and expenses: Leasing operating expenses.... 6,218 6,156 9,167 6,582 20,470 Production taxes.............. 845 467 2,526 1,671 4,354 General and administrative expenses................... 4,853 4,704 7,825 5,411 7,302 Depreciation, depletion and amortization............... 18,783 38,231 45,460 33,128 42,486 ----------- ----------- ----------- ----------- ----------- Total................. 30,699 49,558 64,978 46,792 74,612 ----------- ----------- ----------- ----------- ----------- Operating income................ 36,701 37,557 43,396 32,636 29,486 Interest and other income, net........................... 1,175 4,472 5,086 4,820 388 Interest expense................ (2,004) (6,807) (14,085) (11,193) (15,146) ----------- ----------- ----------- ----------- ----------- Income from continuing operations before income taxes......................... 35,872 35,222 34,397 26,263 14,728 Federal and state income taxes......................... 12,269 11,817 12,680 9,483 5,452 ----------- ----------- ----------- ----------- ----------- Income from continuing operations.................... 23,603 23,405 21,717 16,780 9,276 Discontinued operations: Net income (loss) from operations................. 554 (2,099) (1,845) (1,974) (72) Net gain on disposition....... -- -- -- -- 5,461 ----------- ----------- ----------- ----------- ----------- Net income...................... $ 24,157 $ 21,306 $ 19,872 $ 14,806 $ 14,665 =========== =========== =========== =========== =========== Earnings per share: Continuing operations......... $ 1.00 $ 1.00 $ 0.91 $ 0.70 $ 0.32 Discontinued operations....... 0.02 (0.09) (0.08) (0.08) 0.18 ----------- ----------- ----------- ----------- ----------- Total................. $ 1.02 $ 0.91 $ 0.83 $ 0.62 $ 0.50 =========== =========== =========== =========== =========== Average shares of common stock and common stock equivalents outstanding................... 23,609,978 23,521,402 23,810,872 23,772,868 29,449,391 =========== =========== =========== =========== ===========
The accompanying notes are an integral part of these financial statements. F-3 90 KCS ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (DOLLARS IN THOUSANDS) ASSETS
DECEMBER 31, -------------------- SEPTEMBER 30, 1995 1996 1997 -------- -------- ------------- (UNAUDITED) Current assets Cash and cash equivalents............................... $ 5,846 $ 5,100 $ 3,858 Trade accounts receivable............................... 13,248 30,307 33,720 Receivable from Tennessee Gas........................... 56,437 -- -- Net assets of discontinued operations................... 14,980 26,658 5,110 Other current assets.................................... 1,798 8,392 7,925 -------- -------- -------- Current assets....................................... 92,309 70,457 50,613 -------- -------- -------- Property, plant and equipment Oil and gas properties, full cost method, less accumulated DD&A -- 1995, $86,936; 1996, $131,521 and September 30, 1997, $172,469......................... 204,958 415,870 540,896 Other property, plant and equipment, at cost less accumulated depreciation -- 1995, $1,485; 1996, $2,887 and September 30, 1997, $4,472................ 5,370 14,483 14,510 -------- -------- -------- Property, plant and equipment, net................... 210,328 430,353 555,406 -------- -------- -------- Investments and other assets.............................. 3,927 11,010 8,024 -------- -------- -------- $306,564 $511,820 $614,043 ======== ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable........................................ $ 6,869 $ 24,144 $ 32,953 Accrued liabilities..................................... 3,487 15,558 9,953 -------- -------- -------- Current liabilities.................................. 10,356 39,702 42,906 -------- -------- -------- Deferred credits and other liabilities Deferred federal and state income taxes................. 26,172 34,097 41,884 Other................................................... 2,931 2,052 1,540 -------- -------- -------- Deferred credits and other liabilities............... 29,103 36,149 43,424 -------- -------- -------- Long-term debt............................................ 165,529 310,347 275,723 -------- -------- -------- 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 24,759,770 and 24,976,340 at December 31, 1995 and 1996, respectively and 31,198,390 shares issued at September 30, 1997....... 248 249 312 Additional paid-in capital.............................. 24,786 30,463 143,718 Retained earnings....................................... 79,814 98,298 111,348 Less treasury stock, 1,785,496 and 1,801,496 shares, at December 31, 1995 and 1996, respectively, and 1,801,496 shares at September 30, 1997, respectively -- at cost.............................. (3,272) (3,388) (3,388) -------- -------- -------- Total stockholders' equity...................... 101,576 125,622 251,990 -------- -------- -------- $306,564 $511,820 $614,043 ======== ======== ========
The accompanying notes are an integral part of these financial statements. F-4 91 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, 1993............. $246 $ 23,163 $ 36,761 $(1,326) $ 58,844 Stock issuances -- option and benefit plans............................... -- 380 -- -- 380 Tax benefit on stock option exercises........................... -- 229 -- -- 229 Net income............................. -- -- 24,157 -- 24,157 Dividends ($0.045 per share)........... -- -- (1,033) -- (1,033) Purchase of treasury stock............. -- -- -- (1,909) (1,909) ---- -------- -------- ------- -------- 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...... 60 110,572 -- -- 110,632 Stock issuances -- option and benefit plans............................... 3 1,757 -- -- 1,760 Tax benefit on stock option exercises........................... -- 926 -- -- 926 Net income............................. -- -- 14,665 -- 14,665 Dividends ($0.05 per share)............ -- -- (1,615) -- (1,615) ---- -------- -------- ------- -------- Balance at September 30, 1997 (unaudited)............................ $312 $143,718 $111,348 $(3,388) $251,990 ==== ======== ======== ======= ========
The accompanying notes are an integral part of these financial statements. F-5 92 KCS ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (DOLLARS IN THOUSANDS)
FOR THE NINE MONTHS ENDED FOR THE YEARS ENDED DECEMBER 31, SEPTEMBER 30, -------------------------------- ------------------------- 1994 1995 1996 1996 1997 -------- --------- --------- ----------- ----------- (UNAUDITED) Cash flows from operating activities: Net income.................................. $ 24,157 $ 21,306 $ 19,872 $ 14,806 $ 14,665 Non-cash charges (credits): Depreciation, depletion and amortization........................... 19,740 39,209 46,611 33,933 42,486 Deferred income taxes.................... 10,896 9,756 7,925 4,195 4,581 Gain on sale of discontinued operations............................. -- -- -- -- (5,461) Other non-cash charges and credits, net.................................... (65) 820 1,440 1,248 1,320 -------- --------- --------- --------- --------- 54,728 71,091 75,848 54,182 57,591 Net changes in assets and liabilities: Trade accounts receivable................ 19,107 (11,672) (33,887) 18,906 58,054 Receivable from Tennessee Gas............ (13,569) (42,868) 56,437 56,437 -- Fuel inventories......................... (1,126) 1,727 (238) (102) (398) Other current assets..................... (1,299) 490 (6,822) (1,681) (511) Accounts payable and accrued liabilities............................ (10,724) 14,163 34,732 (22,689) (54,579) Federal and state income taxes........... (119) 178 (2,572) (1,419) 800 Other, net............................... 3,118 (2,999) (2,150) 1,493 938 -------- --------- --------- --------- --------- Net cash provided by operating activities..... 50,116 30,110 121,348 105,127 61,895 -------- --------- --------- --------- --------- Cash flows from investing activities: Investment in oil and gas properties(1)..... (73,682) (121,265) (267,133) (50,552) (169,773) Proceeds from the sale of oil and gas properties............................... -- 4,069 16,634 16,384 3,800 Investment in natural gas transportation systems.................................. (700) (5,969) (6,059) (843) (171) Proceeds from the sale of pipeline assets... -- -- -- -- 27,907 Investment in other property, plant and equipment, net........................... (571) (1,465) (4,026) (1,340) (1,940) -------- --------- --------- --------- --------- Net cash used in investing activities......... (74,953) (124,630) (260,584) (36,351) (140,177) -------- --------- --------- --------- --------- Cash flows from financing activities: Proceeds from long-term debt................ 49,431 141,298 325,636 165,145 117,300 Repayments of long-term debt................ (26,247) (38,774) (180,900) (180,900) (151,991) Issuance of common stock.................... 380 189 683 521 112,492 Issuance of stock warrants.................. -- 626 -- -- -- Repurchase of stock warrants................ -- -- (668) -- -- Tax benefit on stock option exercises....... 229 201 665 567 926 Purchase of treasury stock.................. (1,909) (37) (116) (116) -- Dividends paid.............................. (919) (1,377) (1,388) (1,042) (1,374) Deferred financing costs and other, net..... (509) (2,748) (5,422) (5,200) (313) -------- --------- --------- --------- --------- Net cash provided by (used in) financing activities.................................. 20,456 99,378 138,490 (21,025) 77,040 -------- --------- --------- --------- --------- Increase (decrease) in cash and cash equivalents................................. (4,381) 4,858 (746) 47,751 (1,242) Cash and cash equivalents at beginning of year........................................ 5,369 988 5,846 5,846 5,100 -------- --------- --------- --------- --------- Cash and cash equivalents at end of year...... $ 988 $ 5,846 $ 5,100 $ 53,597 $ 3,858 ======== ========= ========= ========= =========
- --------------- (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. F-6 93 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 8 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 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 F-7 94 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 Securities and Exchange Commission ("SEC"), capitalized oil and gas property costs are limited to the present value of future net income from estimated production of proved oil and gas reserves discounted at 10%, plus the value of unproved properties. 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. Significant declines in oil and gas prices, like those experienced in early 1997, if not offset by increases in proved oil and gas reserves, could cause the Company's capitalized oil and gas property costs to exceed the limitation on such costs, as described above. Unevaluated properties and associated costs not currently being amortized and included in oil and gas properties were $7.3 million and $10.6 million at December 31, 1995 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 $229,000, $201,000 and $665,000 in 1994, 1995 and 1996, respectively. Earnings Per Share Earnings per share have been computed by dividing net earnings by the weighted average number of common shares outstanding during the periods, adjusted for the dilutive effects of stock options and warrants. Impact of Recently Issued Accounting Standards The Financial Accounting Standard Board issued Statements of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" and No. 123, "Accounting for Stock-Based Compensation." SFAS Nos. 121 and 123 are effective for financial statements for fiscal years beginning after December 15, 1995. SFAS 121 was adopted as of January 1, 1996 and had no impact on the financial position or results of operations of the Company. As permitted under SFAS 123, the Company will continue to account for such compensation under the provisions of APB Opinion No. 25. F-8 95 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In October 1996, the American Institute of Certified Public Accountants issued Statement of Position 96-1, "Environmental Remediation Liabilities" (the SOP), which was adopted by the Company in the first quarter of 1997. The SOP provided guidance concerning the recognition, measurement and disclosure of environmental remediation liabilities. The adoption of the SOP did not have a material effect on the Company's financial position or results of operations. In February, 1997, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 128, "Earnings per Share" (FAS 128). This statement simplifies the computation of earnings per share (EPS). Basic EPS includes no dilution and is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the period. FAS 128 is effective for periods ending after December 15, 1997. Pro-forma EPS under the methodology required by FAS 128 is as follows:
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, --------------------------- ----------------- 1994 1995 1996 1996 1997 ------- ------- ------- ------- ------- DOLLARS IN THOUSANDS (EXCEPT PER SHARE DATA) (UNAUDITED) Income from continuing operations........................... $23,603 $23,405 $21,717 $16,780 $ 9,276 Income (loss) from discontinued operations.................. 554 (2,099) (1,845) (1,974) 5,389 ------- ------- ------- ------- ------- Net income.................................................. $24,157 $21,306 $19,872 $14,806 $14,665 ======= ======= ======= ======= ======= Average shares of common stock outstanding.................. 22,970 22,960 23,114 23,094 28,670 Pro-forma basic EPS Continuing operations..................................... $ 1.03 $ 1.02 $ 0.94 $ 0.73 $ 0.32 Discontinued operations................................... 0.02 (0.09) (0.08) (0.09) 0.19 ------- ------- ------- ------- ------- $ 1.05 $ 0.93 $ 0.86 $ 0.64 $ 0.51 ======= ======= ======= ======= =======
2. RECENT 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 the Medallion entities), 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 are proved oil and gas reserves of 187.5 Bcfe as of December 31, 1996, consisting of 140.3 Bcf of natural gas and 7.9 MMbbls of oil and liquids. The Company also acquired a natural gas gathering system as well as oil and gas equipment and supplies. The Medallion Acquisition more than doubled the Company's reserve and production base. 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. F-9 96 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Michigan Acquisition. On December 7, 1995, the Company acquired 24.6 Bcfe of proved reserves in the northern and southern Niagaran Reef trend in Michigan for $31 million, including a volumetric production payment covering certain reserves, escalating working interests in related properties and participation rights and an overriding royalty interest in an exploration program (collectively, the "Michigan Acquisition"). The volumetric production payment provides for the delivery to the Company of 13.7 Bcf of natural gas and 1.1 MMbbls of oil to be delivered (without any burden of development and lease operating expenses) from December 1995 through January 2006. Based on independent reserve reports as of September 30, 1995, the separately acquired working interests added 3.1 Bcf of natural gas and 219 Mbbls of oil to the Company's proved reserves. These 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. The following are the unaudited pro forma revenue, net income and earnings per share of the Company giving effect to the Medallion, Rocky Mountain and Michigan acquisitions and the January 1997 common stock offering for the years ended December 31, 1995 and 1996, as if such transactions had occurred at the beginning of such years. The unaudited pro forma financial data do not purport to be indicative of the financial position or results of operations that would actually have occurred if the transactions had occurred as presented or that may be obtained in the future.
PRO FORMA YEARS ENDED DECEMBER 31, ------------------------ 1995 1996 ---------- ---------- DOLLARS IN THOUSANDS (EXCEPT PER SHARE DATA) Revenue..................................................... $164,339 $180,112 -------- -------- Net income.................................................. $ 26,652 $ 35,120 -------- -------- Earnings per common share................................... $ 0.91 $ 1.18 -------- --------
3. RETIREMENT BENEFIT PLANS The Company had a trusteed, non-contributory Retirement Plan ("Plan"). The Plan was amended to freeze the accrual of future benefits as of October 31, 1991. Prior to October, 1991, the Plan covered substantially all full-time employees of KCS and its participating subsidiaries. The Company's funding policy for the Plan was to make annual contributions that met the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The Board of Directors took action to terminate the Plan effective September 30, 1995. The Company filed all required standard termination applications with both the Internal Revenue Service and the Pension Benefit Guaranty Corporation. In July, 1996, the Company completed the termination of the Plan and satisfied all obligations thereunder, recording a pre-tax expense of $262,000. 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 annual base compensation) since the inception of the Savings Plan in June 1988. 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 each eligible employee 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 F-10 97 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 $293,622 in 1994, $253,666 in 1995 and $102,455 in 1996. 4. STOCK OPTION AND INCENTIVE PLANS In October 1995, the Financial Accounting Standards Board issued SFAS 123, Accounting for Stock-Based Compensation ("SFAS 123"). As permitted under SFAS 123, the Company has elected to continue to account for such compensation under the provisions of APB Opinion No. 25. The Company has complied with the required disclosures under SFAS 123. Had compensation cost for the following plans been determined consistent with SFAS 123, the impact on the Company's net income and earnings per share would not be material. 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. At December 31, 1996, options for 779,812 shares were exercisable. Transactions during the last three years involving stock options under the above plans are summarized as follows:
NUMBER OF OPTION PRICE SHARES PER SHARE --------- ------------- Options outstanding, December 31, 1993.................... 959,400 $ 0.69-$11.44 1994 -- Granted........................................... 212,000 $ 7.25-$13.44 -- Exercised........................................ (64,400) $ 0.69-$ 3.13 1995 -- Granted........................................... 210,000 $ 6.50-$ 8.16 -- Exercised........................................ (45,200) $ 0.69-$ 0.99 -- Forfeited........................................ (6,200) $11.44-$13.44 1996 -- Granted........................................... 12,000 $ 11.44 -- Exercised........................................ (183,000) $ 0.75-$11.44 -- Forfeited........................................ (35,450) $ 6.50-$11.44 --------- ------------- Options outstanding, December 31, 1996.................... 1,059,150 $ 0.92-$13.44 ========= =============
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, 1996. Restricted stock totaling 8,000 shares was outstanding under the Employee Incentive Plans at December 31, 1996. Bonus stock awards under the 1992 Stock Plan convert to shares of restricted stock if certain three-year performance goals are met. The restricted stock then vests over a two-year period. The cost of the awards is F-11 98 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) expensed ratably based on the current market price of the Company's common stock and the extent to which the performance goals are being met. This cost was immaterial during the three years ended December 31, 1996. Bonus stock grants totaling 17,600 shares were outstanding at December 31, 1996. At December 31, 1996, 212,662 shares were available for future grants (including bonus stock awards) 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 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 14,876, 13,794 and 15,326 during 1994, 1995 and 1996, respectively. At December 31, 1996, there were 872,064 shares available for issuance under the Program. A summary of the status of the Employee Incentive Plans and the 1994 Directors' Stock Plan at December 31, 1996 and 1995 and changes during the years then ended is presented in the table and narrative below:
1995 1996 --------------------- --------------------- WTD. AVG. WTD. AVG. SHARES EX. PRICE SHARES EX. PRICE --------- --------- --------- --------- Outstanding at beginning of year........... 1,107,000 $ 4.50 1,265,600 $ 4.95 Grant...................................... 210,000 6.58 12,000 11.44 Exercised.................................. (45,200) 0.81 (183,000) 1.81 Forfeited.................................. (6,200) 12.09 (35,450) 7.85 --------- ------ --------- ------ Outstanding at end of year................. 1,265,600 4.95 1,059,150 5.46 --------- ------ --------- ------ Exercisable at end of year................. 777,600 $ 3.30 779,812 $ 4.68 --------- ------ --------- ------ Weighted average fair value of options granted.................................. $ 2.41 $ 4.36 ====== ======
The following table summarizes information about stock options outstanding at December 31, 1996:
NUMBER WEIGHTED NUMBER OUTSTANDING AT AVERAGE WEIGHTED EXERCISABLE AT WEIGHTED RANGE OF DECEMBER 31, REMAINING AVERAGE DECEMBER 31, AVERAGE EXERCISE PRICES 1996 CONTRACTUAL LIFE EXERCISE PRICE 1996 EXERCISE PRICE - --------------- -------------- ---------------- -------------- -------------- -------------- $ 0.92 - $ 3.12....... 360,000 4.01 $ 0.98 360,000 $ 0.98 3.12 - 4.68 104,800 5.92 3.13 104,800 3.13 4.69 - 7.01 185,000 8.91 6.50 46,250 6.50 7.02 - 10.52 195,000 7.92 7.74 102,500 7.33 10.53 - 13.44 214,350 7.04 11.53 166,262 11.56 - --------------- --------- ----- ------ ------- ------ $ 0.92 - $13.44 1,059,150 6.38 $ 5.46 779,812 $ 4.68 =============== ========= ===== ====== ======= ======
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 1995 and 1996, respectively: risk-free interest rates of 5.73% and 6.52%; expected dividend yield of .33%; expected lives of 5.1 years; expected stock price volatility of 30%. F-12 99 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 5. LONG-TERM DEBT Long-term debt consists of the following:
DECEMBER 31, -------------------- SEPTEMBER 30, 1995 1996 1997 -------- -------- ------------- (UNAUDITED) (DOLLARS IN THOUSANDS) Master Note Facility............................. $ 76,255 $ -- $ -- Receivables Facility............................. 26,900 -- -- VPP Facility..................................... 38,000 -- -- Note Financing................................... 24,374 -- -- Credit Facility.................................. -- 55,600 74,500 11% Senior Notes Due 2003........................ -- 149,456 149,523 Revolving Credit Agreement....................... -- 105,000 51,700 Other............................................ -- 291 -- -------- -------- -------- 165,529 310,347 275,723 Less current maturities.......................... -- -- -- -------- -------- -------- Long-term debt................................... $165,529 $310,347 $275,723 ======== ======== ========
SENIOR NOTES On January 25, 1996, KCS Energy, Inc. (the "Parent") completed a Rule 144A private offering of $150 million 11% senior notes due January 15, 2003 (the "Senior Notes"). The Senior Notes are noncallable for four years and are unsecured obligations of the Parent. 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 net proceeds of approximately $145 million were used to reduce the amounts outstanding under certain of the agreements discussed below. 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 during the period beginning October 1, 1995. On June 6, 1996, the Parent completed an offer to exchange the $150 million outstanding Senior Notes for registered notes of the same tenor (the "Registered Notes") pursuant to a registration statement declared effective by the Securities and Exchange Commission on May 7. The Registered Notes are identical in all material respects to the form and terms of the Senior Notes except for certain transfer restrictions and registration rights applicable to the Senior Notes. The Registered Notes evidenced the same debt, and were issued under and entitled to the benefits of the same Indenture, as the Senior Notes. CREDIT FACILITY On September 25, 1996, the Company assigned the collateral pledged under both the Master Note Facility and VPP Facility, described below, and effectively amended these facilities to create one consolidated revolving credit facility ("Credit Facility") which matures on September 30, 2000. The Credit Facility is used for general corporate purposes, including working capital and to support the Company's capital expenditure program. The borrowing base, or actual availability under the Credit Facility, is currently 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. F-13 100 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 for 1996 was 8.71%. As of December 31, 1996, the weighted average effective interest rate on the outstanding borrowings was 8.25%. Immediately following the Medallion Acquisition, $55.6 million was outstanding under the Credit Facility. REVOLVING CREDIT AGREEMENT Simultaneous with the completion of the Medallion Acquisition, the Company entered into a revolving credit agreement ("Revolving Credit Agreement") with a group of banks. The Revolving Credit Agreement is used for general corporate purposes, including working capital and to support the Company's capital expenditure program. The Revolving Credit Agreement had an initial borrowing base of $105 million and matures on September 30, 2000. The obligations under the Revolving Credit Agreement are secured by substantially all of the oil and gas reserves of the Medallion entities and a pledge of the Medallion entities' common stock. 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 Revolving Credit Agreement permits KCS to borrow at interest rates 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. Immediately following the Medallion Acquisition, $105 million was outstanding under the Revolving Credit Agreement at a weighted average effective interest rate of 7.8%. Following the completion of the common stock offering (see Note 12), the amount outstanding under the Revolving Credit Agreement was reduced to $0.2 million. The Revolving Credit Agreement also included a $30 million term loan component which was never utilized and was terminated on February 18, 1997. TERMINATED FACILITIES The Master Note Facility was used primarily to support the oil and gas exploration and production and natural gas transportation businesses. On September 25, 1996, the primary collateral pledged to secure the Master Note Facility was assigned to the Credit Facility described above. Simultaneous with the collateral assignment, the Company's obligations under the Master Note Facility were fully satisfied. The weighted average effective interest rate was 7.98% in 1995 and 8.86% in 1996. The VPP Facility was used primarily to support the natural gas marketing subsidiary's volumetric production payment program. On September 25, 1996, the collateral pledged to secure the VPP Facility was assigned to the Credit Facility described above. Simultaneous with the collateral assignment, the Company's obligations under the VPP Facility were fully satisfied. The weighted average effective interest rate was 8.17% in 1995 and 7.94% in 1996. The Receivable Facility was used primarily to support the natural gas marketing subsidiary's working capital requirements. In July 1996, the Company paid all outstanding obligations and terminated the Receivable Facility. The weighted average effective interest rate was 7.64% in 1995 and 7.69% in 1996. The Note Financing was used primarily to fund the Company's oil and gas property acquisitions and for general corporate purposes. In January 1996, the Company paid all outstanding obligations and terminated the F-14 101 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Note Financing. The Company also had issued to the purchaser under the Note Financing a warrant to purchase 229,366 shares of the Company's common stock. In October 1996, the Company exercised its option to buy back the warrant at a cost of $668,000. 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 contain certain restrictive covenants which, among other things, require the Company to maintain minimum levels of working capital, cash flow and tangible net worth, as defined in the agreements. In addition, the Company is restricted from incurring secured indebtedness under designated credit facilities 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, $162 million, is estimated based upon the December 31, 1996 quoted market price of $108.00 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. Interest payments were $2.1 million in 1994, $6.8 million in 1995 and $10.9 million in 1996. Scheduled maturities of long-term debt during the next five years are as follows:
PRO ACTUAL FORMA(1) ------ -------- (DOLLARS IN THOUSANDS) 1997................................................. -- -- 1998................................................. -- -- 1999................................................. -- -- 2000................................................. $160,600 $49,900 2001................................................. -- --
- --------------- (1) Reflects the issuance of common stock in January 1997 and the repayment of amounts outstanding under the Credit Facility and the Revolving Credit Agreement. 6. LEASES Future minimum lease payments under non-cancelable operating leases are as follows: $825,000 in 1997, $752,000 in 1998, $578,000 in 1999, $535,000 in 2000 and $484,000 in 2001. Lease payments charged to operating expenses amounted to $598,000, $466,000 and $564,000 during 1994, 1995 and 1996, respectively. F-15 102 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 7. INCOME TAXES Federal and state income tax expense includes the following components:
FOR THE YEARS ENDED DECEMBER 31, --------------------------- 1994 1995 1996 ------- ------- ------- (DOLLARS IN THOUSANDS) Currently payable....................................... $ 1,121 $ 2,545 $ 3,800 Deferred provision, net................................. 10,342 8,096 7,028 ------- ------- ------- Federal income tax expense.............................. 11,463 10,641 10,828 State income taxes (deferred provision $204 in 1994, $1,460 in 1995 and $578 in 1996)...................... 806 1,176 1,852 ------- ------- ------- $12,269 $11,817 $12,680 ======= ======= ======= Sources of deferred federal and state income taxes: Intangible drilling costs............................. $10,278 $12,619 $16,529 Revenue recognition deferred.......................... 2,343 1,854 1,348 Depreciation, depletion and amortization.............. (2,233) (5,779) (5,134) Tax credit carry forwards and other, net.............. 158 862 (5,137) ------- ------- ------- $10,546 $ 9,556 $ 7,606 ======= ======= ======= Reconciliation of federal income tax expense at statutory rate to provision for income taxes: Income before income taxes.............................. $35,872 $35,222 $34,397 ------- ------- ------- Tax provision at 35% statutory rate..................... 12,555 12,328 12,039 State income tax, net of federal income tax benefit..... 523 764 1,204 Statutory depletion..................................... (696) (676) (475) Section 29 credits...................................... (388) (425) -- Other, net.............................................. 275 (174) (88) ------- ------- ------- $12,269 $11,817 $12,680 ======= ======= =======
The primary differences giving rise to the Company's deferred tax assets and liabilities are as follows:
DECEMBER 31, 1996 ----------------------- ASSETS LIABILITIES ------- ------------ (DOLLARS IN THOUSANDS) Income tax effects of: Accelerated DD&A and other property related items......... $37,340 Deferred revenue.......................................... 6,183 Alternative minimum tax credit carry forwards............. $1,923 Net operating loss carry forward.......................... 6,500 Other, net................................................ 1,003 ------ ------- $9,426 $43,523 ====== =======
Income tax payments were $1.3 million in 1994 and $5.6 million in 1996. No income tax payments were made in 1995. The Company had tax net operating losses ("NOL") of approximately $18.6 million at December 31, 1996. This NOL expires in 2011. The Company believes it will generate future taxable income to realize the entire deferred tax asset prior to the expiration of the NOL. F-16 103 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 8. 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 and marketing activities. 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 oil and gas revenue in the period in which the underlying natural gas is produced. These agreements do not impose cash margin requirements on the Company. As a result of the Medallion Acquisition at December 31, 1996, the Company was party to commodity price swap agreements covering approximately 8.5 million MMBtu, 4.8 million MMBtu and 17.8 million MMBtu of natural gas for the years 1997 and 1998 and for the period 1999 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 oil and 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, 1996, the Company's hedging activities consisted of 1,500 long contracts at an average price of $2.25 per Mcf and 635 short contracts at an average price of $2.53 per Mcf maturing through 1999, covering 21,350 MMcf of natural gas. At December 31, 1995, the Company's hedging activities consisted of 700 long contracts at an average price of $1.82 per Mcf and 587 short contracts at an average price of $1.95 per Mcf maturing through 1996 covering 12,870 MMcf 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 $1.0 million at December 31, 1996. Deferred losses, net of deferred gains, were $0.1 million at December 31, 1995. Basis Swaps. Basis swap agreements require KCS to make payments to (or entitle it to receive payments from) the counterparties based upon the differential between the variable costs associated with the delivery of natural gas production to specific delivery points and a contractually specified fixed cost. As a result of the Medallion Acquisition at December 31, 1996, the Company had basis swap arrangements relating to a total of approximately 2.2 million MMBtu during 1997. 9. 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. The first such suit was filed by Tennessee Gas in the 57th District Court of Bexar County, Texas, in August, 1990, and two subsequent suits were filed in the 49th District Court of Zapata County, Texas, in November, 1994, and April, 1995. In the suit in the District Court of Bexar County, Texas ("District Court") against the Company and its co-sellers, Tennessee Gas claimed among other things, that the price of natural gas under the Tennessee Gas Contract should be determined under Section 101 of the NGPA rather than Section 102(b)(2), that certain leases were no longer subject to the contract, that for purposes of the contract the acreage subject to the contract could not be pooled with other properties and that the contract was governed by Section 2.306 of the F-17 104 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Texas Uniform Commercial Code ("Section 2.306"). In July 1992, the District Court ruled in favor of the Company on all of these issues and awarded damages for past underpayments and legal fees. The District Court's judgment was partially affirmed by the Court of Appeals, which held that the price of natural gas under the contract was to be determined in accordance with Section 102(b)(2), that all leases were subject to the contract, and that pooling of the property with a pro rata acreage allocation of production to the contract was in accordance with the contract. However, the Court of Appeals reversed the District Court's summary judgment holding that the Tennessee Gas Contract was not an output contract subject to Section 2.306. Under the Court of Appeals decision, new wells could be drilled and production increased , but any production increase had to have complied with certain good faith and reasonableness standards mandated by Section 2.306. The Court of Appeals also set aside the District Court's awards to the Company of legal fees and past underpayments pending the outcome of the trial on the Section 2.306 issue. On August 1, 1995, the Texas Supreme Court affirmed the ruling of the Court of Appeals, including its decision that Section 2.306 was applicable to the Tennessee Gas Contract. The Texas Supreme Court remanded to the District Court for plenary trial the question of whether, as required by Section 2.306, natural gas volumes taken by Tennessee Gas under the contract were produced and delivered in good faith and were not unreasonably disproportionate to a normal or otherwise comparable prior output or the expectation of the parties. On September 15, 1995, the Company filed a request for a rehearing in the Texas Supreme Court of the Section 2.306 issue. On April 18, 1996, the Texas Supreme Court granted the petitioners' request for a rehearing, withdrew its August 1, 1995 opinion and issued a new opinion. In its April 18, 1996 opinion, the Texas Supreme Court affirmed the Company's position on all issues, stating that the price payable by Tennessee Gas escalates monthly in accordance with Section 102(b)(2) of the Natural Gas Policy Act of 1978 ("NGPA"); that KCS has the right to pool the leases; that Tennessee Gas has no legal or contractual right to question or determine whether certain leases are no longer committed to the Tennessee Gas Contract; and the Tennessee Gas Contract is not an output contract governed by Section 2.306 of the Texas Uniform Commercial Code. On June 3, 1996 Tennessee Gas filed a motion requesting another rehearing and on August 16, 1996 the Texas Supreme Court denied Tennessee Gas' motion. On September 30, 1996, the Company recovered approximately $70 million that Tennessee Gas previously withheld under a series of interim agreements, which was the balance of the purchase price for production taken by Tennessee Gas from September 17, 1994 through April 30, 1996, plus interest. The terms of the Tennessee Gas Contract, in accordance with judicial rulings in the case, governed performance by each of the parties through the termination of the contract effective January 1, 1997. On December 23, 1996, the Company and Tennessee Gas entered into a 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 pending Zapata County, Texas, lawsuits including the contract dispute that resulted in a November 1996 jury award to Tennessee Gas of $143.2 million (including $114 million in punitive damages). The early termination of the Tennessee Gas Contract with its above-market pricing provisions resulted in downward revisions of $37.1 million for estimated future net revenues before income taxes (based upon a natural gas price of $3.69 per Mcf, the assumed realized spot market price on December 31, 1996) and $34.7 million for PV-10 as compared to prior reserve reports prepared as of June 30, 1996. The December 1996 settlement did not affect the Company's successful conclusion of litigation earlier in the year relating to the validity and pricing provisions of the Tennessee Gas Contract and its 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 contract. F-18 105 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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 judgements 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. The aggregate amount at issue in the Royalty Basis 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 December 31, 1996, 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 at December 31, 1996. On March 4, 1997, the holder of an overriding royalty interest filed a claim against the Company and its co-lessees alleging breach of duties arising from the termination of the Tennessee Gas Contract and for certain tortious acts yet to be discovered. The allegations are for joint and several liability, damages exceeding $25 million, return of the 1/64th overriding royalty interest acquired by the Company in 1990 under allegedly fraudulent circumstances and unspecified punitive damages. The Company intends to vigorously contest these claims. Discovery in this matter has not yet begun. Initially, there were three Royalty Basis Suits, one in Dallas County, Texas, in which the Company is a co-plaintiff and two subsequently filed suits in Zapata County, Texas, in which the Company is a co-defendant. The Dallas suit has been subsequently split into four separate lawsuits, based on issues concerning (1) the dedicated acreage in the Guerra "A" and Guerra "B" Units, (2) the non-dedicated acreage in those Units, (3) the Jesus Yzaguirre Unit, which consists entirely of dedicated acreage owned only by the Company, and (4) the overriding royalty interest in the dedicated acreage. The Dallas Royalty Basis Suits involving the dedicated acreage in the Guerra "A" and Guerra "B" Units and the Jesus Yzaguirre Unit 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. The summary judgment has been appealed to the Fifth Court of Appeals in Dallas by the royalty holders in the dedicated leases in the Guerra "A" and Guerra "B" Units, 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. 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 this appeal from the summary judgments and evidentiary rulings, inasmuch as the Appellants can obtain a reversal and remand for plenary trial upon showing that summary judgment was F-19 106 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) improper because there exists an issue of material fact. Because of other issues (discussed below) in the Royalty Basis Suit involving the Jesus Yzaguirre Unit, the summary judgment in favor of the Company in that suit is not yet ripe for appeal. In the Jesus Yzaguirre Royalty Basis 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. The Company and these royalty owners have moved for summary judgment on the issues of lease termination, lease ratification and the effect of division orders. The trial judge has not yet ruled on these motions. The royalty owners who have asserted these claims seek a declaratory judgment of their rights and have not yet specified the amount or basis of the damages being sought. However, the amount at issue could include the aggregate of the Company's capital costs in the lease, the lease operating costs and the working interest revenues of the lease (at market value of the gas production) since 1976. Royalty Basis Suits -- Recent Events (unaudited) The claim asserted by certain of the royalty owners in the Jesus Yzaguirre Royalty Basis suit that the largest lease contained therein had terminated in December 1975 has been settled, and on June 2, 1997, the trial judge signed an Order of Dismissal with Prejudice as to that claim. On May 30, 1997, the Zapata County suit brought by these same royalty owners was dismissed in connection with this settlement. On October 22, 1997, the other Zapata County suit was dismissed by the court on its own motion, inasmuch as the suit had been abated since September 15, 1995 in favor of the earlier-filed suit in Dallas County. On the issue of the effect of the 1992 division orders raised in the Jesus Yzaguirre Royalty Basis suit, the trial judge on August 12, 1997 signed an order granting the Company's motion for summary judgment and denying the royalty owners' motion. At a hearing on October 29, 1997, the trial court entered a final judgment in favor of the Company based upon the prior separate summary judgments in favor of the Company's position on the issues and counterclaims involved with this lawsuit. In addition to the appeal filed by the royalty owners in Guerra "A" and Guerra "B" Units, the royalty owners in the Jesus Yzaguirre Unit have indicated that they will appeal the trial court's final judgment in that matter in due course to the Fifth District Court of Appeals in Dallas, Texas. 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 of the Company. F-20 107 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 10. QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERS -------------------------------------------- FIRST SECOND THIRD FOURTH -------- -------- -------- -------- DOLLARS IN THOUSANDS (EXCEPT PER SHARE DATA) 1995 Revenue................................... $21,475 $21,496 $20,849 $23,295 Operating Income.......................... 9,916 9,520 8,224 9,897 Income From Continuing Operations......... 6,213 5,676 6,366 5,150 Income (Loss) From Discontinued Operations............................. 7 (299) (2,280) 473 Net Income................................ 6,220 5,377 4,086 5,623 Earnings Per Common Share: Continuing Operations.................. $ 0.27 $ 0.24 $ 0.27 $ 0.22 Discontinued Operations................ -- (0.01) (0.10) 0.02 ------- ------- ------- ------- Earnings Per Common Share................. $ 0.27 $ 0.23 $ 0.17 $ 0.24 ======= ======= ======= ======= 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 Earnings Per Common Share: Continuing Operations.................. $ 0.26 $ 0.23 $ 0.22 $ 0.20 Discontinued Operations................ (0.01) (0.02) (0.05) -- ------- ------- ------- ------- Earnings Per Common Share................. $ 0.25 $ 0.21 $ 0.17 $ 0.20 ======= ======= ======= ======= 1997 Revenue................................... $39,879 $32,551 $31,668 Operating Income.......................... 13,717 8,025 7,744 Income From Continuing Operations......... 5,405 2,292 1,579 Discontinued Operations Net loss from operations............... (72) -- -- Net gain on disposition................ 5,461 -- -- Net Income................................ 10,794 2,292 1,579 Earnings Per Common Share: Continuing Operations.................. $ 0.19 $ 0.08 $ 0.05 Discontinued Operations................ 0.18 -- -- ------- ------- ------- Earnings Per Common Share................. $ 0.37 $ 0.08 $ 0.05 ======= ======= =======
11. 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. As discussed in Note 2, as of December 31, 1996 the Company completed the arrangements for the Medallion Acquisition. As such, the associated reserves are included in the following tables. F-21 108 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Except where otherwise provided by contractual agreement, future cash inflows are estimated using year-end prices. Oil and gas prices at December 31, 1996 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 $3.54 and $2.03 at December 31, 1996 and 1995, respectively. Volumetric production payment volumes represent oil and gas reserves purchased from third parties which 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 are stated at year-end prices. The Company does not bear any development or lease operating expenses associated with the volumetric production payments. PRODUCTION REVENUES AND COSTS Information with respect to production revenues and costs related to oil and gas producing activities is as follows:
FOR THE YEARS ENDED DECEMBER 31, --------------------------------- 1994 1995 1996 -------- -------- --------- (DOLLARS IN THOUSANDS) Revenue........................................... $ 65,773 $ 85,424 $ 107,959 Production (lifting) costs........................ 7,063 6,623 11,693 Technical support and other....................... 2,671 2,373 4,401 Depreciation, depletion and amortization.......... 18,538 37,859 44,565 -------- -------- --------- Total expenses.......................... 28,272 46,855 60,659 -------- -------- --------- Pretax income from producing activities........... 37,501 38,569 47,300 Income taxes...................................... 12,041 12,549 17,381 -------- -------- --------- Results of oil and gas producing activities (excluding corporate overhead and interest)..... $ 25,460 $ 26,020 $ 29,919 ======== ======== ========= Capitalized costs incurred: Property acquisition............................ $ 27,772 $ 77,515 $ 198,927 Exploration..................................... 12,599 16,891 18,315 Development..................................... 33,311 26,859 54,889 -------- -------- --------- Total capitalized costs incurred........ $ 73,682 $121,265 $ 272,131 Capitalized costs at year-end: Proved properties............................... $169,624 $284,597 $ 536,817 Unproved properties............................. 5,074 7,297 10,574 -------- -------- --------- 174,698 291,894 547,391 Less accumulated depreciation, depletion and amortization.................................... (49,077) (86,936) (131,521) -------- -------- --------- Net investment in oil and gas producing properties...................................... $125,621 $204,958 $ 415,870 ======== ======== =========
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. F-22 109 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL AND GAS RESERVES
DECEMBER 31, ----------------------- 1995 1996 --------- ---------- (DOLLARS IN THOUSANDS) Future cash inflows......................................... $ 521,914 $1,213,604 Future costs: Production................................................ (94,880) (320,457) Development............................................... (21,985) (43,882) Discount -- 10% annually.................................. (113,964) (291,653) --------- ---------- Present value of future net revenues...................... 291,085 557,612 Future income taxes, discounted at 10%.................... (59,322) (120,013) --------- ---------- Standardized measure of discounted future net cash flows.... $ 231,763 $ 437,599 ========= ==========
CHANGES IN DISCOUNTED FUTURE NET CASH FLOWS FROM PROVED RESERVE QUANTITIES
FOR THE YEARS ENDED DECEMBER 31, -------------------------------- 1994 1995 1996 -------- -------- -------- Balance, beginning of year......................... $160,884 $179,660 $231,763 Increases (decreases) Sales, net of production costs................... (58,710) (78,801) (96,266) Net change in prices, net of production costs.... (11,180) 9,593 50,328 Discoveries and extensions, net of future production and development costs.............. 26,930 22,417 67,791 Changes in estimated future development costs.... (9,622) (862) 2,005 Change due to acquisition of reserves in place... 26,038 108,798 292,557 Development costs incurred during the period..... 13,924 9,672 10,411 Revisions of quantity estimates.................. 1,532 (19,256) (45,003) Accretion of discount............................ 21,017 24,033 29,108 Net change in income taxes....................... (12,060) 2,021 (60,691) Sales of reserves in place....................... -- (1,931) (11,507) Changes in production rates (timing) and other... 20,907 (23,581) (32,897) -------- -------- -------- Net increase..................................... 18,776 52,103 205,836 -------- -------- -------- Balance, end of year............................... $179,660 $231,763 $437,599 ======== ======== ========
F-23 110 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) RESERVE INFORMATION (UNAUDITED) The following information with respect to the Company's net proved oil and gas reserves are estimates based on reports prepared by independent petroleum engineers (principally Ryder Scott Company, R.A. Lenser and Associates, Inc. and H. J. Gruy and Associates, Inc.). Proved developed reserves represent only those reserves expected to be recovered through existing wells using equipment currently in place. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells or from existing wells after material recompletion expenditures. All of the Company's reserves are located within the United States.
1994 1995 1996 --------------- --------------- ---------------- GAS OIL GAS OIL GAS OIL MMCF MBBL MMCF MBBL MMCF MBBL ------- ----- ------- ----- ------- ------ Proved developed and undeveloped reserves Balance, beginning of year....... 69,740 2,578 89,184 2,319 140,963 7,517 Production....................... (11,304) (211) (19,129) (196) (25,581) (758) Discoveries, extensions, etc..... 10,924 33 10,399 202 21,998 2,196 Acquisition of reserves in place.......................... 18,206 148 71,560 5,449 157,051 7,245 Sales of reserves in place....... -- -- (3,751) (3) (9,224) (492) Revisions of estimates........... 1,618 (229) (7,300) (254) (17,182) (1,077) ------- ----- ------- ----- ------- ------ Balance, end of year............. 89,184 2,319 140,963 7,517 268,025 14,631 ======= ===== ======= ===== ======= ====== Proved developed reserves Balance, beginning of year..... 61,016 1,579 74,215 1,336 121,987 3,808 ------- ----- ------- ----- ------- ------ Balance, end of year........... 74,215 1,336 121,987 3,808 236,454 12,133 ======= ===== ======= ===== ======= ======
12. SUBSEQUENT EVENTS (UNAUDITED) In January 1997, the Company completed a public offering of 6,000,000 shares (giving effect to the two-for-one stock split effective June 30, 1997) of its common stock. The net proceeds to the Company of approximately $110.6 million were used to reduce outstanding indebtedness under the bank credit facilities. 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. As of March 31, 1997, the Company sold its Texas intrastate natural gas pipeline system together with related marketing assets and a joint venture gathering system for a net sales price of $27.9 million, resulting in an after tax gain of approximately $5.9 million. The proceeds from the sale were used to fund a portion of the Company's 1997 capital budget. F-24 111 KCS ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) During the third quarter of 1997, the Company sold its natural gas marketing operations for a net sale price of $0.5 million and realized an after-tax gain of $0.3 million. The results for the transportation and marketing operations have been classified as discontinued operations for all periods presented in the Statements of Consolidated Income. The assets and liabilities of discontinued operations have been classified in the Consolidated Balance Sheets as "Net assets of discontinued operations." Net assets of the Company's discontinued operations at September 30, 1997 and December 31, 1996 and 1995 are as follows:
DECEMBER 31, DECEMBER 31, SEPTEMBER 30, 1995 1996 1997 ------------ ------------ ------------- (THOUSANDS OF DOLLARS) Assets Current Assets Accounts receivable, net.......................... $44,804 $61,632 $ 816 Other............................................. 2,361 2,995 4,200 ------- ------- ------ Total current assets......................... 47,165 64,627 5,016 Net property, plant and equipment.................... 18,987 17,977 600 Other noncurrent assets.............................. 2,877 1,964 1,384 ------- ------- ------ Total........................................ 69,029 84,568 7,000 Liabilities Current liabilities.................................. 54,049 55,701 1,890 Noncurrent liabilities............................... -- 2,209 -- ------- ------- ------ Total........................................ 54,049 57,910 1,890 ------- ------- ------ Net assets of discontinued operations.................. $14,980 $26,658 $5,110 ======= ======= ======
Summarized results of operations of the discontinued transportation and marketing operations are as follows:
FOR NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------------ ---------------------- 1994 1995 1996 1996 1997 -------- -------- -------- ---------- --------- (THOUSANDS OF DOLLARS) Revenues................................ $278,590 $360,627 $274,323 $225,438 $22,015 Costs and expenses*..................... 277,748 363,968 277,237 228,528 22,129 -------- -------- -------- -------- ------- Income (loss) before income taxes....... 842 (3,341) (2,914) (3,090) (114) Provision (benefit) for income taxes.... 288 (1,242) (1,069) (1,116) (42) -------- -------- -------- -------- ------- Income (loss) from discontinued operations............................ 554 (2,099) (1,845) (1,974) (72) ======== ======== ======== ======== ======= Gain on disposal before income taxes**............................... -- -- -- -- 8,668 Provision for income taxes.............. -- -- -- -- 3,207 -------- -------- -------- -------- ------- Net gain on disposal.................... $ -- $ -- $ -- $ -- $ 5,461 ======== ======== ======== ======== =======
- --------------- * Includes allocated net interest expense of $0.7 million, $1.1 million and $3.8 million for the years ended December 31, 1994, 1995 and 1996, respectively and $2.6 million and $0.1 million for the nine-month periods ended September 30, 1996 and 1997, respectively. ** The nine-month period ended September 30, 1997 includes a $1.1 million provision for estimated losses during the wind-down period. 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 the financial statements and notes thereto included in this Prospectus to the number of common shares and earnings per share reflect the stock split. F-25 112 ====================================================== NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS NOT CONTAINED IN THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY OF THE UNDERWRITERS. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THAT DATE. ------------------ TABLE OF CONTENTS
PAGE ---- Prospectus Summary..................... 3 Risk Factors........................... 10 Special Note on Forward-Looking Statements........................... 16 Use of Proceeds........................ 17 Capitalization......................... 17 Selected Historical Financial Information.......................... 18 Management's Discussion and Analysis of Financial Condition and Results of Operations........................... 19 Business and Properties................ 27 Management............................. 48 Security Ownership by Certain Beneficial Owners and Management..... 50 Description of Existing Indebtedness... 51 Description of the Notes............... 54 Underwriting........................... 82 Certain Legal Matters.................. 83 Experts................................ 83 Available Information.................. 84 Incorporation of Certain Documents by Reference............................ 84 Glossary............................... 85 Index to Consolidated Financial Statements........................... F-1
====================================================== ====================================================== $125,000,000 LOGO KCS ENERGY, INC. 8 7/8% SENIOR SUBORDINATED NOTES DUE 2008 ------------ PROSPECTUS JANUARY 15, 1998 ------------ SALOMON SMITH BARNEY PRUDENTIAL SECURITIES INCORPORATED CIBC OPPENHEIMER JEFFERIES AND COMPANY, INC. MORGAN KEEGAN & COMPANY, INC. ====================================================== -----END PRIVACY-ENHANCED MESSAGE-----