-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, GviJR1no1l0UGdwGU1ES8+EpckFD2hrrd5FZlJWNs6Qwlg2066xfc/3p0lV7AFLP fcqXRowVJMvHcH6KbxgWMg== 0000950129-94-000437.txt : 19940520 0000950129-94-000437.hdr.sgml : 19940520 ACCESSION NUMBER: 0000950129-94-000437 CONFORMED SUBMISSION TYPE: 424B4 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19940519 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SANTA FE ENERGY RESOURCES INC CENTRAL INDEX KEY: 0000086772 STANDARD INDUSTRIAL CLASSIFICATION: 1311 IRS NUMBER: 362722169 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: 1933 Act SEC FILE NUMBER: 033-52849 FILM NUMBER: 94529470 BUSINESS ADDRESS: STREET 1: 1616 S VOSS RD STE 1000 CITY: HOUSTON STATE: TX ZIP: 77057 BUSINESS PHONE: 7137832401 MAIL ADDRESS: STREET 1: 1616 S VOSS ROAD STE 1000 CITY: HOUSTON STATE: TX ZIP: 77057 FORMER COMPANY: FORMER CONFORMED NAME: SANTA FE NATURAL RESOURCES INC DATE OF NAME CHANGE: 19900111 424B4 1 FINAL PROS FOR SANTA FE 424B4 1 Filed pursuant to Rule 424b4 Registration No. 033-52849 PROSPECTUS 10,700,000 DECSSM (DIVIDEND ENHANCED CONVERTIBLE STOCKSM--DECSSM) SANTA FE ENERGY RESOURCES, INC. $.732 SERIES A CONVERTIBLE PREFERRED STOCK (PAR VALUE $.01 PER SHARE) (SUBJECT TO CONVERSION INTO OR REDEMPTION FOR SHARES OF COMMON STOCK, PAR VALUE $.01 PER SHARE) The DECS offered hereby (the "Offering") are 10,700,000 shares of $.732 Series A Convertible Preferred Stock of Santa Fe Energy Resources, Inc., a Delaware corporation (the "Company"), and are referred to herein as Dividend Enhanced Convertible Stock (the "DECS"). On May 15, 1998 (the "Mandatory Conversion Date"), each of the outstanding DECS will automatically convert into one share of the Company's common stock, par value $.01 per share (the "Common Stock"), subject to adjustment in certain events, if not previously redeemed by the Company or converted at the option of the holder. The DECS are redeemable, at the option of the Company, in whole or in part, on or after May 15, 1997 (the "Initial Redemption Date"), at a call price payable in shares of Common Stock, and are convertible at the option of the holder at any time into .8474 shares of Common Stock, in each case as described below. The number of shares of Common Stock a holder will receive upon redemption, and the value of the shares received upon conversion, will vary depending on the market price of the Common Stock at the time of redemption or conversion, all as described herein. Dividends on the DECS are cumulative at the annual rate of $.732 per share and are payable quarterly in arrears on the fifteenth day of February, May, August and November, commencing August 15, 1994. Each DECS has a liquidation preference equal to the sum of (i) the per share price to public shown below and (ii) the amount of accrued and unpaid dividends thereon to the date of liquidation, dissolution or winding up. The DECS are not redeemable by the Company prior to the Initial Redemption Date. At any time and from time to time on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, the Company may redeem the outstanding DECS, in whole or in part. Upon any such redemption, each holder of DECS will receive, in exchange for each DECS so redeemed, shares of Common Stock having a Current Market Price equal to the sum of (i) beginning on the Initial Redemption Date, $9.058, and declining thereafter on the schedule set forth herein to $8.875 per share on April 15, 1998 and (ii) all accrued and unpaid dividends thereon (the "Call Price"). See "Description of the DECS." The DECS are convertible at the option of the holder, at any time prior to the Mandatory Conversion Date, into .8474 shares of Common Stock for each DECS (equivalent to a conversion price of $10.473 per share of Common Stock (the "Conversion Price")), subject to adjustment upon certain events. The opportunity for equity appreciation afforded by an investment in the DECS is less than the opportunity for equity appreciation afforded by an investment in the Common Stock because the Company may, at its option, redeem the DECS at any time on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, and may be expected to do so if, prior to the Mandatory Conversion Date, the current market price of the Common Stock exceeds the Conversion Price. In such event, holders of the DECS will receive less than one share of Common Stock for each DECS. However, because holders of DECS called for redemption will have the option to surrender DECS for conversion at the Conversion Price up to the close of business on the redemption date (and may be expected to do so if the market price of the Common Stock exceeds the Conversion Price), a holder that elects to convert will receive .8474 shares of Common Stock for each DECS. Because the price of Common Stock is subject to market fluctuations, the value of the Common Stock received by an owner of DECS upon mandatory conversion of the DECS may be more or less than the amount paid for the DECS offered hereby. The offering made hereby is part of a refinancing by the Company (the "Refinancing"), consisting of this Offering and a concurrent offering (the "Concurrent Debenture Offering") of $100 million of 11% Senior Subordinated Debentures Due 2004 (the "Debentures"). This Offering is not conditioned on the Concurrent Debenture Offering, and the Concurrent Debenture Offering is not conditioned on this Offering. The Common Stock is listed on the New York Stock Exchange ("NYSE") under the symbol SFR. On May 17, 1994, the last reported sale price of the Common Stock on the NYSE was $8.875 per share. See "Price Range of Common Stock and Dividends." The DECS have been approved for listing on the NYSE under the symbol SFRPRA. SEE "INVESTMENT CONSIDERATIONS" FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS BEFORE DECIDING TO INVEST IN THE DECS. 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 UNDERWRITING PROCEEDS TO PUBLIC(1) DISCOUNT COMPANY(1)(2) Per DECS............................................. $8.875 $.270 $8.605 Total................................................ $94,962,500 $2,889,000 $92,073,500
- -------------------------------------------------------------------------------- (1) Plus accrued dividends, if any, from the date of original issuance. (2) Before deducting expenses payable by the Company estimated to be $500,000. The DECS are offered subject to receipt and acceptance by the Underwriters, to prior sale and to the Underwriters' right to reject any order in whole or in part and to withdraw, cancel or modify the offer without notice. It is expected that delivery of the DECS will be made at the office of Salomon Brothers Inc, Seven World Trade Center, New York, New York, or through the facilities of The Depository Trust Company, on or about May 25, 1994. SALOMON BROTHERS INC LAZARD FRERES & CO. PAINEWEBBER INCORPORATED The date of this Prospectus is May 18, 1994. 2 IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS THAT STABILIZE OR MAINTAIN THE MARKET PRICE OF THE DECS AND THE COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE OR OTHERWISE. SUCH TRANSACTIONS, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. AVAILABLE INFORMATION The Company is subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder (the "Exchange Act") and, in accordance therewith, files reports, proxy statements and other information with the Securities and Exchange Commission (the "Commission"). Reports, proxy statements and other information filed by the Company with the Commission may be inspected and copied at the public reference facilities maintained by the Commission at Room 1024, 450 Fifth Street, N.W., Judiciary Plaza, Washington, D.C. 20549-1004, and at the following Regional Offices of the Commission: Chicago Regional Office, CitiCorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60621 2511; and New York Regional Office, 7 World Trade Center, 13th Floor, New York, New York 10048. Copies of such material may also be obtained at prescribed rates from the Public Reference Section of the Commission at its principal office at 450 Fifth Street, N.W., Judiciary Plaza, Washington, D.C. 20549-1004. The Company's Common Stock and its Convertible Preferred Stock, Series 7%, are listed for trading on the NYSE. The Company's registration statements, reports, proxy statements and other information may also be inspected at the offices of the NYSE, 20 Broad Street, New York, New York 10005. DOCUMENTS INCORPORATED BY REFERENCE The following documents heretofore filed by the Company with the Commission pursuant to Section 13 of the Exchange Act are incorporated herein by reference: (i) the Company's Annual Report on Form 10-K for the year ended December 31, 1993; (ii) the Company's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 1994; (iii) the Company's Current Report on Form 8-K dated February 8, 1994; and (iv) the description of the Common Stock contained in the Company's Registration Statement on Form 8-A (File No. 1-7667) filed on February 21, 1990. All documents 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 the Debentures shall be deemed to be incorporated by reference into this Prospectus and to be a part hereof from the date of filing of such documents. Any statement contained in a document 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 other subsequently filed document which also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. Any such statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. Any person receiving a copy of this Prospectus may obtain without charge, upon written or oral request, a copy of any of the documents incorporated by reference herein, except for the exhibits to such documents (unless such exhibits are specifically incorporated by reference into such documents). Requests should be addressed to Mark A. Older, Senior Counsel and Secretary, Santa Fe Energy Resources, Inc., 1616 South Voss Road, Suite 1000, Houston, Texas 77057 (telephone (713) 783 2401). CERTAIN DEFINITIONS As used herein, the following terms have the specific meanings set out: "Bbl" means barrel, "MBbl" means thousand barrels, "MMBbl" means million barrels, "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "BOE" means barrel of oil equivalent, "MBOE" means thousand barrels of oil equivalent and "MMBOE" means million barrels of oil equivalent. Natural gas volumes are converted to barrels of oil equivalent using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil. Unless otherwise indicated in this Prospectus, natural gas volumes are stated at the official temperature and pressure bases of the area in which the reserves are located. "Finding cost" refers to a fraction, of which the numerator is equal to the costs incurred by the Company for property acquisition, exploration and development and of which the denominator is equal to proved reserve additions from extensions, discoveries, improved recovery, acquisitions and revisions of previous estimates. "Improved recovery," "enhanced oil recovery" and "EOR" include all methods of supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, such as waterfloods, cyclic steam, steam drive and CO2 (carbon dioxide) injection and fireflood projects. "Heavy oil" is low gravity, high viscosity crude oil. 2 3 PROSPECTUS SUMMARY The following information is a summary of the more detailed information and financial statements appearing elsewhere or incorporated by reference in this Prospectus and is qualified in its entirety by reference thereto. Unless otherwise indicated or required by the context, references to "Santa Fe" and the "Company" include its consolidated subsidiaries. THE COMPANY GENERAL Santa Fe Energy Resources, Inc. ("Santa Fe" or the "Company") is engaged in the exploration, development and production of oil and natural gas in the continental United States and in certain foreign areas. At December 31, 1993, the Company had estimated worldwide proved reserves of oil and natural gas totaling 292.0 MMBOE (consisting of approximately 248.2 MMBbls of oil and approximately 263.0 Bcf of natural gas), of which approximately 93% were domestic reserves and approximately 7% were foreign reserves. During 1993, the Company's worldwide production aggregated approximately 94.3 MBOE per day, of which approximately 71% was crude oil and approximately 29% was natural gas. A substantial portion of the Company's domestic oil production is in long-lived fields with well-established production histories. Pursuant to the Company's corporate restructuring program, the Company has focused its activities on its three domestic core areas--the Permian Basin in Texas and New Mexico, the offshore Gulf of Mexico and the San Joaquin Valley of California--as well as in Argentina and Indonesia. For the five years ended December 31, 1993, the Company has replaced 172% of its production at an average finding cost of $4.80 per BOE. Over the last four years, the Company has increased overall production by increasing production from existing properties and through acquisitions. In addition, the Company has reduced its overall cost structure. For example, over the four-year period ended December 31, 1993, Santa Fe has increased its average daily production from 69.1 MBOE to 94.3 MBOE (including 7.7 MBOE per day in 1993 attributable to production from non-core assets sold pursuant to the corporate restructuring program) and has reduced its average production costs (including related production, severance and ad valorem taxes) from $6.22 per BOE in 1990 to $5.39 per BOE in 1993. CORPORATE RESTRUCTURING PROGRAM In October 1993, the Company's Board of Directors adopted a broad corporate restructuring program designed to improve its earnings and cash flow while increasing production and replacing reserves in the long-term. The restructuring program is the result of an intensive review of the Company's operations and cost structure and focuses on the concentration of capital spending in the Company's core operating areas and the disposition of non-core assets. The restructuring program also includes an evaluation of the Company's capital and cost structures in an effort to identify and implement ways to increase flexibility and strengthen the Company's financial performance. The Company's capital program will be concentrated in its three domestic core areas, as well as in its productive areas in Argentina and Indonesia. In October 1993, Sante Fe announced that its 1994 capital expenditures could increase to up to $240 million. However, as a result of the depressed crude oil prices that have prevailed since November 1993, the Company, consistent with industry practice, has determined to defer certain of its capital projects in order to prudently manage available cash flow in the near term. Based on current market conditions, the Company has authorized up to $130 million of capital expenditures during 1994, a level which should allow the Company to replace its estimated 1994 production, although no assurance can be given regarding such replacement. The Company intends to continue to monitor its capital expenditure program throughout the balance of 1994 and may, in response to industry conditions, including, without limitation, prevailing oil and natural gas prices and the outlook therefor, revise such program. The non-core asset dispositions identified by the Company's restructuring program included the sale of its natural gas gathering and processing assets for securities as well as the sales of non-core oil and 3 4 gas properties consisting of approximately 16.7 MMBOE of estimated proved reserves and undeveloped leasehold acreage for approximately $89.3 million. In addition, during the first quarter of 1994, the Company sold its remaining interest in the Santa Fe Energy Trust for $11.3 million and its interest in certain oil and gas properties for $8.3 million. As a result of these transactions, the Company has disposed of substantially all of its inventory of non-core assets. Based on a review of its capital structure, the Company determined to proceed with a refinancing of certain of the Company's indebtedness (the "Refinancing") in the belief that it would increase the Company's financial flexibility, strengthen the Company's financial position and permit the Company to pursue aggressively its operating strategy. See "--Financial Strategy." The evaluation of the Company's cost structure resulted in the announcement on April 25, 1994 of the implementation of a cost reduction program designed to reduce the Company's expenses by approximately $30.0 million from the 1993 level (which reduction includes approximately $5.0 million of non-recurring costs). Substantially all of this cost reduction program is expected to be implemented by year end 1994. As part of its restructuring program the Company adopted the following operating, financial and cost reduction strategies that should position it to continue to efficiently replace its production and increase its reserves even in a low oil price environment. OPERATING STRATEGY Santa Fe's operating strategy is designed to replace reserves and increase its production in a cost effective manner by (i) exploiting its inventory of lower risk, higher return projects in its domestic core areas, (ii) increasing its light crude oil and natural gas reserves and production, and (iii) increasing its international operations. Develop Domestic Properties in Core Areas. A principal focus of the Company's corporate restructuring program is the concentration of capital spending in the Company's core domestic areas-- the Permian Basin of Texas and New Mexico, the offshore Gulf of Mexico and the San Joaquin Valley of California. In these areas, the Company has identified a significant number of attractive development opportunities. Selection and timing of projects will depend upon factors such as oil and natural gas prices and availability of funds. In southeastern New Mexico, the Company has targeted for accelerated development a light oil prospect in the Delaware formation and a light oil and gas project in the Cisco-Canyon zone. The Company has conducted extensive operations in these areas and has identified in excess of 150 development well locations and 20 exploratory prospects to be drilled over the next several years. During 1993, several new fields or field additions in the Offshore Gulf of Mexico area were placed on production, and the Company expects to further develop identified prospects in 1994. In the San Joaquin Valley, reservoir engineering studies prepared on behalf of the Company indicate that significant additions to proved reserves can be made through additional EOR and development projects in several of the Company's long-lived fields with well-established production histories. Increase Light Crude Oil and Natural Gas. A substantial part of the Company's domestic oil reserves consists of "heavy" oil, which is generally more expensive to produce than, and sells at a significant discount to, lighter crude oils such as the benchmark West Texas Intermediate. See "Investment Considerations--Effects of Heavy Oil Production" and "Management's Discussion and Analysis of Financial Condition and Results of Operations--General." One of the principal components of the Company's strategy is to reduce the proportion of heavy oil in its reserves by increasing its lighter crude oil and natural gas reserves, primarily through development drilling of its existing project inventory (such as the Permian Basin and offshore Gulf of Mexico, as discussed above) and selective acquisitions. The acquisition of Adobe Resources Corporation ("Adobe")in May 1992 added significantly to the Company's lighter crude oil and natural gas reserves. Increase International Operations. The Company is actively engaged in exploration and development activities in two foreign areas, Argentina and Indonesia. The Company believes that it can continue to identify and pursue other projects with the potential for increased reserves and production in these and possibly other foreign areas. Revenues from sales of oil and gas production in these areas have increased from approximately $3.7 million in 1991 to $35.6 million in 1993, with average daily production volumes 4 5 from these areas increasing from 0.6 MBOE per day in 1991 to 6.5 MBOE per day in 1993. The Company made a significant exploration discovery in 1993--the Sierra Chata natural gas discovery in Argentina. To date, six gross (1.3 net) wells have been drilled with no dry holes. In 1994, the Company plans additional development drilling to further define the limits of the field, and to construct a gas processing plant and a 40-mile pipeline. First sales of production from this discovery are expected in early 1995. FINANCIAL STRATEGY The Company's financial strategy is to provide additional flexibility in the current low oil price environment thereby allowing the Company to further implement its operating strategy. This Offering is part of the Refinancing, consisting of this Offering and the Concurrent Debenture Offering. The net proceeds from the Refinancing will be utilized to repay a portion of the Company's senior indebtedness (on a pro forma basis at March 31, 1994, an aggregate of approximately $179.3 million of senior indebtedness would be repaid with such net proceeds). See "Use of Proceeds." Completion of the Refinancing will extend the average life of the Company's debt from approximately 4.5 years to approximately 7.5 years, reduce the Company's overall leverage and reduce required debt amortization in 1994, 1995 and 1996 to $3.7 million, $5.3 million and $6.1 million, respectively (on a pro forma basis at March 31, 1994). The Refinancing will also provide additional liquidity by increasing the total amount available for borrowing under the Company's existing bank credit facilities and by increasing cash flow in the near term. COST REDUCTION STRATEGY On April 25, 1994, the Company announced the implementation of a major cost reduction program aimed at reducing its expenses by approximately $30.0 million from the 1993 level (which reduction includes approximately $5.0 million of non-recurring costs). The Company intends to reduce its field expenses by approximately $10.0 million, reduce its salaried work force by approximately 20%, significantly improve the efficiency of its information systems activities and substantially reduce other general and administrative costs. Substantially all of this cost reduction program is expected to be implemented by year end 1994. The Company recorded a $7.0 million charge during the quarter ended March 31, 1994 in connection with implementation of the cost reduction program. THE DECS OFFERING Securities Offered............ 10,700,000 shares of Series A Convertible Preferred Stock, referred to as Dividend Enhanced Convertible Stock (the "DECS"). Securities.................... The DECS are shares of convertible preferred stock and rank prior to the Common Stock both as to payment of dividends and distribution of assets upon liquidation. Each outstanding DECS mandatorily converts into one share of Common Stock on May 15, 1998 (the "Mandatory Conversion Date"), and the Company has the option to redeem the shares of DECS, in whole or in part, at any time and from time to time on or after May 15, 1997 (the "Initial Redemption Date") and prior to the Mandatory Conversion Date at the Call Price (as defined herein), payable in shares of Common Stock. In addition, each DECS is convertible into 0.8474 shares of Common Stock at the option of the holder at any time prior to the Mandatory Conversion Date as set forth below. Dividends..................... The holders of DECS are entitled to receive, when, as and if dividends are declared by the Board of Directors of the Company out of funds legally available therefor, cumulative preferential dividends from the issue date of the DECS, accruing at the rate per share of $0.732 per annum ($0.183 per quarter) for each DECS, payable quarterly in arrears on the fifteenth day of each February, May, August and November or, if any such date is not a business day, on the next succeeding business day. The first dividend payment will be for the period from the issue date of the DECS to and including August 14, 1994 and will be payable on August 15, 1994. Dividends
5 6 are payable in cash except in connection with certain redemptions by the Company. Accumulated and unpaid dividends will not bear interest. See "Description of the DECS--Dividends." Mandatory Conversion of DECS.......................... On the Mandatory Conversion Date, each outstanding DECS will convert (the "Mandatory Conversion") automatically into shares of Common Stock at the Common Equivalent Rate and the right to receive an amount of cash equal to all accrued and unpaid dividends on such DECS (other than dividends payable to a holder of record on a prior date). The "Common Equivalent Rate" is initially one share of Common Stock for each DECS, subject to adjustment in the event of certain stock dividends or distributions, subdivisions, splits, combinations, issuances of certain rights or warrants or distributions of certain assets with respect to the Common Stock. The Mandatory Conversion is, however, subject to the Company's right to redeem all or a portion of the outstanding DECS on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, and to the conversion of the DECS at the option of the holder at any time prior to the Mandatory Conversion Date. See "--Description of the DECS--Right to Redeem DECS" and "Description of the DECS-- Mandatory Conversion of DECS." Because the price of the Common Stock is subject to market fluctuations, the value of the Common Stock received upon Mandatory Conversion of the DECS may be more or less than the amount paid for the DECS offered hereby. Right to Redeem DECS.......... The DECS are not redeemable by the Company prior to the Initial Redemption Date. At any time or from time to time on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, the Company may redeem the outstanding DECS, in whole or in part. Upon any such redemption, each holder of DECS will receive, in exchange for each DECS so called, a number of shares of Common Stock equal to the Call Price of the DECS in effect on the date of redemption divided by the Current Market Price of the Common Stock determined as of the date which is one trading day prior to the public announcement of the call for redemption. The "Call Price" of each DECS is the sum of (i) $9.058 on and after the Initial Redemption Date through August 14, 1997, $9.012 on and after August 15, 1997 through November 14, 1997, $8.967 on and after November 15, 1997 through February 14, 1998, $8.921 on and after February 15, 1998 through April 14, 1998, and $8.875 on and after April 15, 1998 until the Mandatory Conversion Date, and (ii) all accrued and unpaid dividends thereon to the date fixed for redemption (other than dividends payable to a holder of record as of a prior date). The number of shares of Common Stock to be delivered in payment of the applicable Call Price will be based upon the current market price of the Common Stock prior to the announcement of the redemption, and the market price of the Common Stock may vary between the date of such determination and the subsequent delivery of such shares. See "Description of the DECS--Right to Redeem DECS." Conversion at Option of Holder........................ The DECS are convertible, in whole or in part, at the option of the holder at any time prior to the Mandatory Conversion Date, unless previously redeemed, into 0.8474 shares of Common Stock for each DECS (equivalent to a Conversion Price of $10.473 per share of Common Stock), subject to adjustment in the event of certain stock dividends or distributions, subdivisions, splits, combinations, issuances of certain rights or warrants or distributions of certain assets with respect to the Common Stock. The right of holders to convert DECS called for redemption will terminate immediately prior to the close of business on the redemption date. See "Description of the DECS--Conversion at Option of Holder."
6 7 Enhanced Dividend Yield; Less Equity Appreciation Than Common Stock.................. No dividends are currently paid on the Common Stock. The opportunity for equity appreciation afforded by an investment in the DECS is less than that afforded by an investment in the Common Stock because the Conversion Price is higher than the per share price to public of the DECS and the Company may, at its option, redeem the DECS at any time on or after the Initial Redemption Date, and prior to the Mandatory Conversion Date, and may be expected to do so, if, among other circumstances, the applicable Current Market Price of the Common Stock exceeds the Call Price. In such event, a holder of a DECS will receive less than one share of Common Stock, but in no event less than 0.8474 shares of Common Stock. A holder may also surrender for conversion any DECS called for redemption up to the close of business on the redemption date, and a holder that so elects to convert will receive 0.8474 shares of Common Stock per DECS. The value of Common Stock received by a holder of a DECS may be more or less than the per share amount paid for the DECS offered hereby, due to market fluctuations in the price of Common Stock. See "Description of the DECS--Mandatory Conversion of DECS" and "--Right to Redeem DECS." Liquidation Preference........ The DECS rank senior to the Common Stock upon liquidation and pari passu with the Company's outstanding shares of Convertible Preferred Stock, Series 7% (of which 5,000,000 shares are outstanding with a liquidation preference of $20.00 per share plus accrued and unpaid dividends thereon). The liquidation preference of each of the DECS will be in an amount equal to the sum of (i) the per share price to the public shown on the cover page hereof and (ii) all accrued and unpaid dividends thereon to the date of liquidation, dissolution or winding up. Voting Rights................. The holders of DECS shall have the right with the holders of Common Stock to vote in the election of directors and upon each other matter coming before any meeting of the stockholders on the basis of 4/5 votes for each DECS held; the holders of DECS and the holders of Common Stock will vote together as one class. In addition, (i) whenever dividends on the DECS shall be in arrears and unpaid in an aggregate amount of dividends payable thereon for four quarterly dividend periods, the holders of the DECS (voting separately as a class with holders of shares of Convertible Preferred Stock, Series 7%, and shares of all other series of Preferred Stock, if any, upon which like voting rights have been conferred and are exercisable) will be entitled to vote for the election of two directors of the Company, such directors to be in addition to the number of directors constituting the Board of Directors immediately prior to the accrual of such right, and (ii) the holders of the DECS will have voting rights with respect to certain alterations of the Company's Restated Certificate of Incorporation. See "Description of the DECS --Voting Rights." Use of Proceeds............... The net proceeds to the Company from the sale of the DECS offered hereby are estimated to be $91.6 million. Such net proceeds will be used to repay certain of the Company's senior indebtedness. See "Use of Proceeds." Listing....................... The DECS have been approved for listing on the NYSE under the symbol SFRPRA.
7 8 SUMMARY FINANCIAL INFORMATION The following table presents summary historical financial information for the periods presented and should be read in conjunction with the historical consolidated financial statements, including the notes thereto, and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table also presents summary pro forma financial information as of and for the year ended December 31, 1993 and the three months ended March 31, 1994 after giving effect to the consummation of this Offering and the Concurrent Debenture Offering and the application of the estimated net proceeds therefrom as described in "Use of Proceeds." The summary pro forma financial information and the summary historical financial information as of and for the three months ended March 31, 1993 and 1994 is unaudited.
PRO FORMA(A) THREE MONTHS --------------------- ENDED MARCH 31, YEAR ENDED DECEMBER 31, 1ST QTR 1993 ------------------- -------------------------------------------------- 1994 YEAR 1994 1993 1993 1992 1991 1990 1989 -------- -------- -------- -------- -------- -------- ------- ------- ------- (IN MILLIONS, EXCEPT PER SHARE DATA) INCOME STATEMENT DATA: Revenues.................... $ 90.3 $ 436.9 $ 90.3 $ 115.3 $ 436.9 $ 427.5 $ 379.8 $ 382.9 $ 322.9 Production and operating expenses.................. 40.6 163.8 40.6 42.7 163.8 153.4 134.6 135.5 107.1 Exploration expenses........ 5.0 31.0 5.0 7.1 31.0 25.5 18.7 21.0 19.4 General and administrative............ 7.6 32.3 7.6 7.0 32.3 30.9 27.8 25.6 28.6 Depreciation, depletion and amortization.............. 32.1 152.7 32.1 37.6 152.7 146.3 106.6 105.2 99.4 Impairment of oil and gas properties................ -- 99.3(b) -- -- 99.3(b) -- -- 1.4 1.1 Restructuring charges....... 7.0(c) 38.6(c) 7.0(c) -- 38.6(c) -- -- -- -- Income (loss) from operations................ -- (113.0) -- 12.0 (113.0) 57.5 64.4 69.4 45.5 Interest expense(d)......... 9.3 41.2 10.3 13.7 45.8 55.6 47.3 57.1 30.5 Net income (loss)........... (1.9) (74.2) (2.5) (0.4) (77.1) (1.4) 18.5 17.0 49.8 Earnings (Loss) to Common Stock..................... (5.7) (89.0) (4.3) (2.2) (84.1) (5.7) 18.5 17.0 49.8 Earnings (loss) per share of Common Stock.............. $ (0.06) $ (0.99) $ (0.05) $ (0.02) $ (0.94) $ (0.07) $ 0.29 $ 0.28 -- CASH FLOW DATA: Net cash provided by operating activities...... $ 4.4 $ 153.8 $ 14.3 $ 41.6 $ 160.2 $ 141.5 $ 128.4 $ 144.1 $ 173.1 Capital expenditures........ 30.5 127.0 30.5 30.0 127.0 76.8 108.1 117.0 93.7 Preferred dividends......... 3.8 14.8 1.8 1.8 7.0 2.6 -- -- -- Common stock dividends(e)... -- 14.3 -- 3.5 14.3 12.3 10.2 5.1 --
BALANCE SHEET DATA (AT END OF PERIOD): Properties and equipment, net....................... $ 818.2 $ 832.7 $ 818.2 $1,076.5 $ 832.7 $1,101.8 $ 797.4 $ 745.0 $ 747.6 Total assets................ 1,044.5 1,079.2 1,042.2 1,278.9 1,076.9 1,337.2 911.9 911.1 881.8 Long-term debt.............. 362.7 365.9 403.5 459.0 405.4 492.8 440.8 417.2 124.7 Convertible Preferred Stock, Series 7%................. 80.0 80.0 80.0 80.0 80.0 80.0 -- -- -- Shareholders' equity........ 411.9 414.8 320.7 412.8 323.6 416.6 225.1 215.8 228.1 OTHER DATA: EBITDA (in millions)(f)..... $ 24.4 $ 174.9 $ 24.4 $ 51.7 $ 174.9 $ 183.6 $ 173.3 $ 186.1 $ 153.8 EBITDA/Interest expense..... 2.6x 4.2x 2.4x 3.8x 3.8x 3.3x 3.7x 3.3x 5.0x EBITDA/Preferred dividends and interest expense...... 1.9x 3.1x 2.0x 3.3x 3.3x 3.1x 3.7x 3.3x 5.0x Ratio of earnings to combined fixed charges and preferred dividends(g).... (h) (h) (h) (h) (h) (h) 1.5x 1.3x 2.1x
(See notes on following page) 8 9 - --------------- (a) Pro forma for the consummation of this Offering and the Concurrent Debenture Offering and the application of the net proceeds therefrom as described under "Use of Proceeds." (b) Reflects a non-cash charge of $99.3 million for the impairment of oil and gas properties recorded as of December 31, 1993. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 of the Notes to the Company's Consolidated Financial Statements included elsewhere in this Prospectus. (c) Reflects non-cash, non-recurring charges relating to implementation of the Company's restructuring program of (a) $38.6 million recorded in 1993, comprised of (i) losses on property dispositions of $27.8 million; (ii) long-term debt prepayment penalties of $8.6 million; and (iii) accruals for certain personnel benefits and related costs of $2.2 million and (b) $7.0 million recorded in the first quarter of 1994 comprised of severance, benefits and relocation expenses. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 2 of the Notes to the Company's Consolidated Financial Statements included elsewhere in this Prospectus. (d) Includes capitalized interest of $4.3 million, $4.9 million, $7.7 million, $10.6 million and $13.8 million for the years 1993, 1992, 1991, 1990 and 1989, respectively, and $0.9 million and $1.1 million for the three months ended March 31, 1994 and 1993, respectively. (e) Represents dividends paid subsequent to the Company's initial public offering in March 1990. Prior to such time, the Company was a wholly owned subsidiary of the Santa Fe Pacific Corporation, and dividends paid to its parent are not considered relevant in the context of its dividend policy subsequent to the initial public offering. As part of the Company's 1993 restructuring program, in October 1993, the Company eliminated its $0.04 per share quarterly dividend on Common Stock. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." (f) EBITDA is presented because it is a widely accepted financial indication of a company's ability to service and incur debt and preferred stock dividends. EBITDA is defined as income before taxes, interest expense (including capitalized interest but excluding long-term debt prepayment penalties), depletion, depreciation, amortization and other non-cash charges. EBITDA should not be considered by an investor as an alternative to earnings (loss) as an indicator of the Company's operating performance or to cash flows as a measure of liquidity. EBITDA for the Company largely results from sales of oil and gas produced from the Company's properties, which production, if not replaced, will result in depletion of the Company's assets and a reduction of the Company's ability to service and incur debt at constant or reducing prices. The calculation of EBITDA for 1993 reflects an average sales price (unhedged) by the Company of $12.93 per barrel of oil. For the three months ended March 31, 1994, the average sales price (unhedged) for the Company's 1994 oil production was $10.00 per barrel. If such lower oil prices prevail throughout 1994, the Company's EBITDA for 1994 will be significantly lower than that for 1993. (g) For the purpose of calculating such ratios, (i) earnings consist of income (loss) before income taxes plus fixed charges and (ii) fixed charges consist of interest expense (including amortization of deferred debt issuance costs) and the amount of pre-tax earnings required to cover preferred stock dividend requirements. (h) Earnings for the three months ended March 31, 1994 and 1993 and the years ended December 31, 1993 and 1992 were insufficient to cover combined fixed charges and preferred dividends by $12.2 million, $4.0 million, $166.7 million and $13.6 million, respectively. Pro forma earnings for the three months ended March 31, 1994 and the year ended December 31, 1993, after giving effect to the consummation of this Offering and the Concurrent DECS Offering and the application of the estimated net proceeds therefrom as described in "Use of Proceeds," would have been insufficient to cover fixed charges by $14.4 million and $174.9 million, respectively. 9 10 SUMMARY OPERATING DATA
THREE MONTHS ENDED MARCH 31, YEAR ENDED DECEMBER 31, ------------------ ---------------------------------------------------- 1994 1993 1993 1992 1991 1990 1989 ------- ------- ------- ------- ------- ------- ------- Production of oil (MBbls per day)(a)............................ 66.0(d) 67.3(d) 66.7(d) 62.5 55.5 52.0 50.7 Production of natural gas (MMcf per day)(a)............................ 155.5(d) 177.8(d) 165.4(d) 126.3 95.2 102.5 81.6 Production of oil equivalent (MBOE per day)(a).................. 91.9(d) 96.9(d) 94.3(d) 83.6 71.4 69.1 64.3 Average sales price: Oil (per Bbl).................... $ 10.00 $ 13.73 $ 12.93 $ 14.54 $ 14.09 $ 17.90 $ 14.11 Natural gas (per Mcf)............ $ 2.10 $ 1.96 $ 2.03 $ 1.71 $ 1.49 $ 1.57 $ 1.72 Production costs (including related production, severance and ad valorem taxes) per BOE............. $ 5.59 $ 5.53 $ 5.39 $ 5.66 $ 6.06 $ 6.22 $ 5.69 Five-year average finding cost per BOE(b)............................. $ 4.80 $ 4.05 $ 3.66 $ 3.73 $ 4.31 Annual reserve replacement ratio(c)........................... 121% 262% 127% 108% 251% Estimated reserve life(in years)..... 8.5(d) 9.9 9.9 10.0 10.7
- --------------- (a) Includes production attributable to certain net profits interests sold by the Company to unaffiliated persons, which interests burden the Company's working or royalty interests held in certain properties. (b) Reflects the average finding cost per BOE during the five years ended December 31 as of the year reflected in the column. (c) The annual reserve replacement ratio is a fraction, of which the numerator is the estimated number of reserves added during a year through additions of estimated proved reserves from exploratory and development drilling, acquisitions of proved properties and revisions of previous estimates, excluding property sales, and of which the denominator is the oil and natural gas produced during that year. (d) Includes production attributable to the properties sold to Vintage Petroleum, Inc. ("Vintage") (closed in November 1993) and Bridge Oil (U.S.A.) Inc. ("Bridge") (closed in April 1994). Production attributable to such properties during the year ended December 31, 1993 totaled approximately 4.1 MBbls of oil and 21.7 MMcf of natural gas per day (7.7 MBOE per day). Production during the three months ended March 31, 1993 attributable to the properties sold to Vintage totaled approximately 3.2 MBbls of oil per day and approximately 7.0 MMcf of natural gas per day (4.4 MBOE per day). Production during the three months ended March 31, 1993 and 1994 attributable to the properties sold to Bridge totaled approximately 1.4 MBbls of oil per day and approximately 14.6 MMcf of natural gas per day (3.8 MBOE per day), and approximately 1.3 MBbls of oil per day and approximately 13.5 MMcf of natural gas per day (3.6 MBOE per day), respectively. 10 11 SUMMARY OIL AND GAS RESERVE INFORMATION The following table sets forth summary information with respect to the Company's proved oil and gas reserves as of the dates indicated. For additional information relating to reserves, see "Business and Properties--Reserves."
NET PROVED RESERVES AS OF DECEMBER 31,(A) ------------------------------------------------------------ 1993(B) 1992 1991 1990 1989 ---------- ------- ------- -------- -------- Crude oil, condensate and natural gas liquids (MMBbls).................... 248.2 255.1 229.2 222.3 219.8 Natural gas (Bcf)..................... 263.0 277.5 170.8 185.9 188.0 Proved reserves (MMBOE)............... 292.0 301.5 257.7 253.3 251.1 Proved developed reserves (MMBOE)..... 225.5 248.4 210.3 205.0 204.0 Present value pre-tax future net cash flows (in millions)(c).............. $ 567.8 $ 915.2 $ 602.6 $1,231.4 $1,090.1
- --------------- (a) Includes estimated proved reserves attributable to certain net profits interests sold by the Company to unaffiliated persons, which interests burden the Company's working or royalty interests held in certain properties. (b) The estimates set forth in this table for 1993 give effect to the sale by the Company of approximately 8.0 MMBOE of proved reserves to Bridge, which sale closed in April 1994. (c) Represents the present value (discounted at 10%) of the future net cash flows estimated to result from production of the Company's estimated proved reserves using estimated sales prices and estimates of production costs, ad valorem and production taxes and future development costs necessary to produce such reserves. The sales prices used in the determination of proved reserves and of estimated future net cash flows are based on the prices in effect at year end, and for 1993 averaged $9.27 per barrel for oil and $2.17 per Mcf for natural gas. The average sales prices (unhedged) realized by the Company for its production during 1993 was $12.93 per barrel for oil and $2.03 per Mcf for natural gas. The average sales prices (unhedged) realized by the Company for its production during the three months ended March 31, 1994 were $10.00 per barrel of oil and $2.10 per Mcf of natural gas. 11 12 INVESTMENT CONSIDERATIONS Before deciding to invest in the shares of DECS offered hereby, prospective investors should carefully consider all of the information contained in this Prospectus, and in particular the investment considerations described in the following paragraphs. LIMITED OPPORTUNITY FOR EQUITY APPRECIATION; RISK OF DECLINE IN EQUITY VALUE The opportunity for equity appreciation afforded by an investment in the DECS is less substantial than the opportunity for equity appreciation afforded by an investment in the Common Stock, in part because the Conversion Price exceeds the initial price to public per DECS. In addition, the Company may, at its option, redeem the DECS at any time on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, and may be expected to do so if the Current Market Price of the Common Stock exceeds the Call Price. In such event, holders of the DECS will receive less than one share of Common Stock for each DECS. However, because the holders of DECS called for redemption will have the option to surrender DECS for conversion prior to the close of business on the redemption date, a holder that elects to convert will receive 0.8474 of a share of Common Stock for each DECS. If the Company elects to redeem the DECS, in whole or in part, or the DECS are converted into Common Stock on the Mandatory Conversion Date, the equity appreciation, exclusive of accrued and unpaid dividends, realized on an investment in the DECS will, for any owner of DECS so redeemed or converted, be limited to the excess, if any, of (i) the value of the Common Stock received for the DECS so redeemed or converted, over (ii) the price paid by such owner for such DECS. Because the number of shares of Common Stock to be delivered in payment of the Call Price will be determined on the basis of the market price of the Common Stock prior to the announcement of the call, the value per share of the shares of Common Stock to be delivered may be more or less than the Call Price on the date of delivery. As a result of these provisions, holders of DECS would be expected to realize no equity appreciation if the market price of one share of Common Stock is equal to or below the Conversion Price, and less than all of such appreciation if the market price of one share of Common Stock is above the Conversion Price. Holders of DECS will realize the entire decline in equity value if the market price of the Common Stock at the time of conversion is less than the price paid for a DECS. EFFECTS OF REDEMPTION PRIOR TO MANDATORY CONVERSION At any time and from time to time on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, the Company may redeem the outstanding DECS, in whole or in part. Upon redemption, holders of DECS will receive a number of shares of Common Stock equal to the Call Price of the DECS in effect on the date of redemption divided by the Current Market Price of the Common Stock determined as of the date which is the trading day prior to the public announcement of the call for redemption. The Company may be expected to exercise such right at a time when the holders of DECS would receive less than one share of Common Stock per DECS (that is, when the market price of the Common Stock exceeds the Call Price), although the right of such holders to surrender DECS for conversion prior to the close of business on the redemption date serves to assure holders exercising such right that they will receive no less than 0.8474 of a share of Common Stock for each DECS. The Call Price of each DECS is the sum of (i) $9.058 on and after the Initial Redemption Date through August 14, 1997, $9.012 on and after August 15, 1997 through November 14, 1997, $8.967 on and after November 15, 1997 through February 14, 1998, $8.921 on and after February 15, 1998 through April 14, 1998 and $8.875 on and after April 15, 1998 until the Mandatory Conversion Date, and (ii) all accrued and unpaid dividends thereon to the date fixed for redemption (other than dividends payable to a holder of record as of a prior date). Dividends will cease to accrue on DECS on the date fixed for their redemption. SUBSTANTIAL LEVERAGE The Company is, and after the Refinancing will continue to be, highly leveraged. At March 31, 1994, the Company had total indebtedness of $446.4 million and shareholders' equity of $320.7 million. After 12 13 giving effect to the Offering, the Concurrent Debenture Offering and the application of the estimated net proceeds therefrom as described in "Use of Proceeds," the Company would have had, on a pro forma basis at March 31, 1994, total indebtedness of $366.4 million and shareholders' equity of $411.9 million. If this Offering is completed but the Concurrent Debenture Offering is not consummated, the Company's pro forma total indebtedness and shareholders' equity at March 31, 1994 would have been $357.3 million and $412.2 million, respectively. The Company's high degree of leverage will have important consequences to holders of the DECS, including the following: (i) the ability of the Company to obtain additional financing in the future for working capital, acquisitions, capital expenditures and other general corporate purposes may be impaired; (ii) a substantial portion of the Company's cash flow from operations will be required to be dedicated to the payment of the Company's interest expense and principal repayment obligations; (iii) the Company is more highly leveraged than many of its competitors, which may place it at a competitive disadvantage; and (iv) the Company's degree of leverage may make it more vulnerable to a downturn in its business or the economy generally. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." EFFECTS OF CHANGING PRODUCT PRICES The Company's profitability is determined in large part by the difference between the prices received for the oil and natural gas that it produces and the costs of finding and producing such resources. Prices for oil and gas have been subject to wide fluctuations, which continue to reflect imbalances in supply and demand as well as other market conditions and the world political situation as it affects OPEC, the Middle East (including the current embargo of Iraqi crude oil from worldwide markets) and other producing countries. Moreover, the price of oil and natural gas may be affected by the price and availability of alternative sources of energy, weather conditions and the general state of the economy. Even relatively modest changes in oil and gas prices may significantly change the Company's revenues, results of operations, cash flows and proved reserves. Since the Company is primarily an oil producer, a change in the price paid for its oil production more significantly affects its results of operations than a change in natural gas prices. For example, the Company estimates that a change of $1.00 per barrel in its average realized oil price would have resulted in a change of $21.6 million in its 1993 operating income and $16.2 million in its 1993 cash flow from operating activities, based on its 1993 operating results. The foregoing estimates do not give effect to changes in any other factors, such as the effect of the Company's hedging program or depreciation and depletion, that would result from a change in oil prices. In recent months, spot oil prices have reached their lowest levels in over five years, and no assurance can be given that oil prices will not remain at these levels for the foreseeable future or decline further. The Company's cash flow from operating activities is a function of the volumes of oil and gas produced from the Company's properties and the sales prices realized therefor. Crude oil and natural gas are depleting assets. Therefore, unless the Company replaces over the long term the oil and natural gas produced from the Company's properties, the Company's assets will be depleted over time and its ability to service and incur debt at constant or declining prices will be reduced. The Company's cash flow from operations for 1993 reflects an average sales price (unhedged) for the Company's 1993 oil production of $12.93 per barrel. For the three months ended March 31, 1994, the average sales price (unhedged) for the Company's 1994 oil production was $10.00 per barrel. If such lower oil prices prevail throughout 1994, the Company's cash flow from operating activities for 1994 will be significantly lower than that for 1993. EFFECTS OF HEAVY OIL PRODUCTION A substantial portion of the Company's oil production consists of heavy oil produced from the Midway-Sunset Field. The market for such heavy crude oil production differs substantially from the remainder of the domestic crude oil market, due principally to the higher transportation and refining costs associated with heavy crude. As a result, the profit margin realized from the sale of heavy oil is generally lower than that realized from the sale of light oil, because the costs to produce heavy oil are generally 13 14 higher, and the price paid for heavy crude oil is generally lower, than the price paid for light crudes. Furthermore, there is currently an oversupply of crude oil in the California market that has had an adverse effect on the prices paid for crude oil in that market. See "Business and Properties--Current Markets for Oil and Gas." DIVIDEND RIGHTS AND RESTRICTIONS ON PAYMENT OF DIVIDENDS Holders of the DECS will be entitled to receive cumulative preferential dividends in the amount specified on the cover page of this Prospectus when, as and if declared by the Board of Directors of the Company out of funds legally available therefor. Certain of the Company's credit agreements, however, restrict the payment of dividends to the holders of the Company's capital stock, including the DECS. For a description of the aggregate amount that the Company could pay as a dividend on its capital stock, see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." In addition, the terms of the Convertible Preferred Stock, Series 7%, restrict, and the terms of the DECS will restrict, any dividend payment by the Company to holders of Common Stock unless all dividends on the Convertible Preferred Stock, Series 7%, and the DECS for all past quarterly dividend periods shall have been paid, or declared and a sum sufficient for the payment thereof set apart. As discussed in "Business and Properties--Corporate Restructuring Program," the Company has eliminated the payment of its $0.04 per share quarterly dividend on its Common Stock. The determination of the amount of future cash dividends, if any, to be declared and paid is in the sole discretion of the Company's Board of Directors and will depend on dividend requirements with respect to the Company's Convertible Preferred Stock, Series 7%, and, assuming consummation of this Offering, the DECS, the Company's financial condition, earnings and funds from operations, the level of its capital and exploration expenditures, dividend restrictions in its financing agreements, its future business prospects and other matters as the Company's Board of Directors deems relevant. Pro forma for this Offering and the Concurrent Debenture Offering, at March 31, 1994 the Company would have had the capacity to pay dividends of up to $110.0 million in the aggregate on capital stock, including its Convertible Preferred Stock, Series 7%, and the DECS. However, pursuant to the terms of the Debentures, and upon completion of this Offering and the Concurrent Debenture Offering, at March 31, 1994 the Company would have had the ability to pay only up to $50.0 million on its Common Stock. The amount permitted under the Debentures to be used to pay dividends will vary over time depending, among other things, on the Company's earnings and any issuances of capital stock. The Debentures will not restrict the Company from paying preferred dividends on the Convertible Preferred Stock, Series 7%, or the DECS; however, payment of such preferred dividends will reduce the Company's capacity under the Debentures to pay Common Stock dividends. POSSIBLE IMPAIRMENT OF OIL AND GAS PROPERTIES The Company follows the successful efforts method of accounting for its oil and gas exploration and production activities. Under this method, costs (both tangible and intangible) of productive wells and development dry holes, as well as the costs of prospective acreage, are capitalized. The costs of drilling and equipping exploratory wells which do not result in proved reserves are expensed upon the determination that the well does not justify commercial development. Other exploratory costs, including geological and geophysical costs and delay rentals, are charged to expense as incurred. The Company periodically reviews individual proved properties to determine if the carrying value of the field as reflected in its accounting records exceeds the estimated undiscounted future net revenues from proved oil and gas reserves attributable to the field. Based on this review and the continuing evaluation of development plans, economics and other factors, if appropriate, the Company records impairments (additional depletion and depreciation) to the extent that the carrying value exceeds the estimated undiscounted future net revenues. Such impairments constitute a charge to earnings which does not impact the Company's cash flow from operating activities. However, such writedowns impact the amount of the Company's stockholders' equity and, therefore, the ratio of debt-to-equity. The risk that the Company will be required to write down the carrying value of its oil and natural gas properties 14 15 increases when oil and natural gas prices are depressed. In 1993, the Company recorded impairments of $99.3 million. No assurance can be given that the Company will not experience additional impairments in the future. GOVERNMENTAL AND ENVIRONMENTAL REGULATION The Company's activities are subject to various federal, state and local laws and regulations covering the discharge of material into the environment or otherwise relating to protection of the environment. In particular, the Company's oil and gas exploration, development, production and EOR operations, its activities in connection with storage and transportation of liquid hydrocarbons and its use of facilities for treating, processing, recovering or otherwise handling hydrocarbons and waste therefrom are subject to stringent environmental regulation by governmental authorities. Such regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning the Company's oil and gas wells and other facilities. The Company has expended significant resources, both financial and managerial, to comply with environmental regulations and permitting requirements and anticipates that it will continue to do so in the future. Although the Company believes that its operations and facilities are in general compliance with applicable environmental regulations, risks of substantial costs and liabilities are inherent in oil and gas operations, and there can be no assurance that significant costs and liabilities will not be incurred in the future. Moreover, it is possible that other developments, such as increasingly strict environmental laws, regulations and enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company's operations, could result in substantial costs and liabilities in the future. See "Business and Properties--Other Business Matters--Environmental Regulation." UNCERTAINTIES IN ESTIMATES OF PROVED RESERVES Proved reserves of crude oil and natural gas are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be economically producible under existing conditions. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures. All reserve estimates are to some degree speculative and various classifications of reserves only constitute attempts to define the degree of speculation involved. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment and the assumptions used regarding prices for crude oil, natural gas liquids and natural gas. Results of drilling, testing and production and changes in crude oil, natural gas liquids and natural gas prices after the date of the estimate may require substantial upward or downward revisions. Although a substantial portion of the Company's proved oil reserves is in long-lived fields with well-established production histories where EOR and other development projects are employed to produce such reserves, the external factors discussed above will directly affect the Company's determination to proceed with any of such projects and, therefore, the quantity of reserves in these fields classified as proved. The reserve estimates included and incorporated by reference in this Prospectus were prepared as of December 31, 1993 and could be materially different from the quantities of crude oil, natural gas liquids and natural gas that ultimately will be recovered from the Company's properties. In addition, actual future net cash flows from production of the Company's reserves will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. The timing of actual future net revenue from proved reserves, and thus their actual present value, can be affected by the timing of the incurrence of expenditures in connection with development of oil and gas properties. The 10% discount factor, which is required by the Commission to be used to calculate present value for reporting purposes, is not necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the oil and gas industry. Discounted present value, no matter what discount rate is used, is materially 15 16 affected by assumptions as to the amount and timing of future production, which may and often do prove to be inaccurate. INDUSTRY CONSIDERATIONS The Company's business is the exploration for, and the development and production of, oil and natural gas. Exploration for oil and natural gas involves many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. In addition, there is strong competition relating to all aspects of the oil and gas industry, and in particular in the exploration and development of new oil and gas reserves. The Company must compete with a substantial number of other oil and natural gas companies, many of which have significantly greater financial resources. All of the Company's oil and gas activities are subject to the risks normally incident to exploration for and production of oil and gas, including blowouts, cratering, spillage and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, the Company carries insurance against some, but not all, of the risks associated with the Company's business. Losses and liabilities arising from such events would reduce revenues and increase costs to the Company to the extent not covered by insurance. Another risk inherent in the oil and gas industry is the risk that a well will be a dry hole or a marginal producer that will not, in either case, repay the entire cost of drilling, testing, completing and equipping the well. There can be no assurance, therefore, that the Company's future exploration and development wells will be financially successful. INTERNATIONAL OPERATIONS Foreign properties, operations or investment may be adversely affected by local political and economic developments, exchange controls, currency fluctuations, royalty and tax increases, retroactive tax claims, expropriation, import and export regulations and other foreign laws or policies as well as by laws and policies of the United States affecting foreign trade, taxation and investment. In addition, in the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of courts in the United States. The Company may also be hindered or prevented from enforcing its rights with respect to a governmental instrumentality because of the doctrine of sovereign immunity. ABSENCE OF A PREVIOUS MARKET FOR THE DECS The DECS are a new issue of securities with no established trading market. The DECS have been approved for listing on the NYSE, but no assurance can be given as to the development or liquidity of any trading market in the DECS. If an active market does not develop, the market price and liquidity of the DECS may be adversely affected. 16 17 RATIOS OF EARNINGS TO FIXED CHARGES The following table sets forth the historical ratios of earnings to fixed charges and earnings to combined fixed charges and preferred stock dividends of the Company for the periods indicated:
THREE MONTHS ENDED MARCH 31, YEAR ENDED DECEMBER 31, ---------------- -------------------------------------------- 1994 1993 1993 1992 1991 1990 1989 ---- ---- ---- ---- ---- ---- ---- Earnings to Fixed Charges......... (a) (a) (a) (a) 1.5x 1.3x 2.1x Earnings to Combined Fixed Charges and Preferred Stock Dividends... (b) (b) (b) (b) 1.5x 1.3x 2.1x
- --------------- (a) Earnings during the three months ended March 31, 1994 and 1993 and the years 1993 and 1992 were insufficient to cover fixed charges (excluding dividends on preferred stock) by $9.2 million, $1.0 million, $155.2 million and $6.6 million, respectively. (b) Earnings during the three months ended March 31, 1994 and 1993 and the years 1993 and 1992 were insufficient to cover combined fixed charges and preferred stock dividends by $12.2 million, $4.0 million, $166.7 million and $13.6 million, respectively. USE OF PROCEEDS The net proceeds to the Company from the sale of the DECS offered hereby are estimated to be approximately $91.6 million. Such net proceeds will be used (i) to repay the floating rate debt borrowed under the Company's Amended and Restated Revolving Credit Agreement ("Bank Facility"), the balance of which was $25.0 million at May 17, 1994 and which currently bears interest at 5.5% per year; (ii) to repay approximately $30.0 million principal amount of debt previously incurred by Santa Fe Energy Operating Partners, L.P. (the "Operating Partnership") (plus a prepayment penalty equal to approximately $2.5 million), with a current interest rate of 8.3% per year, $6.0 million of which matures in 1994 and $8.0 million of which is scheduled to mature during each of the succeeding three years; (iii) to repay approximately $12.3 million principal amount of debt of Mission Resources, Inc. assumed by the Company in connection with a property acquisition, with a current interest rate of 9.0% and a scheduled maturity in 1995; and (iv) the balance, if any, will be used for working capital purposes. The net proceeds from the Concurrent Debenture Offering (estimated to be approximately $96.3 million) will be used (i) to prepay $65.0 million principal amount of the Company's Senior Notes with scheduled maturities in 1995 (Series C, $30.0 million) and 1996 (Series D, $35.0 million), together with prepayment penalties aggregating approximately $6.1 million; (ii) to repay any additional debt under the Bank Facility; and (iii) the balance, if any, will be used for working capital purposes. The Senior Notes (Series C) bear interest at 10.04% per year and the Senior Notes (Series D) bear interest at 10.14% per year. After the application of the net proceeds from this Offering and the Concurrent Debenture Offering, the Company will have approximately $245.0 million principal amount of Senior Notes outstanding, none of which matures before 1996. 17 18 CAPITALIZATION The following table sets forth the Company's consolidated capitalization at March 31, 1994 on an historical basis and as adjusted as indicated below. See "Use of Proceeds."
MARCH 31, 1994 --------------------------------------------- AS ADJUSTED ------------------------------- DECS AND ACTUAL DECS ONLY(A) DEBENTURES(B) -------- ------------ ------------- (IN MILLIONS) SHORT-TERM DEBT: Current portion of long-term debt............. $ 42.9 $ 33.7 $ 3.7 -------- ------------ ------------- -------- ------------ ------------- LONG-TERM DEBT: Senior notes.................................. 280.0 280.0 245.0 Revolving and term credit agreement........... 79.0 32.2 7.0 Notes payable to bank......................... 11.4 11.4 11.4 Term loan..................................... 11.1 -- -- Partnership credit agreement.................. 22.0 -- -- Senior subordinated debentures................ -- -- 99.3 -------- ------------ ------------- Total long-term debt....................... 403.5 323.6 362.7 -------- ------------ ------------- CONVERTIBLE PREFERRED STOCK, SERIES 7%:......... 80.0 80.0 80.0 -------- ------------ ------------- SHAREHOLDERS' EQUITY: DECS.......................................... -- 91.6 91.6 Common stock.................................. 0.9 0.9 0.9 Paid-in capital............................... 498.3 498.3 498.3 Accumulated deficit........................... (178.1) (178.2) (178.5) Other......................................... (0.4) (0.4) (0.4) -------- ------------ ------------- Total shareholders' equity................. 320.7 412.2 411.9 -------- ------------ ------------- Total capitalization..................... $ 804.2 $ 815.8 $ 854.6 -------- ------------ ------------- -------- ------------ -------------
- --------------- (a) Pro forma for the issuance of the DECS only. Net proceeds from the Offering will be applied to prepay approximately $46.8 million of floating rate debt borrowed under the Bank Facility, approximately $30.0 million of debt incurred by the Operating Partnership and approximately $12.3 million of debt assumed by the Company in connection with a property acquisition, in each case on a pro forma basis at March 31, 1994. (b) Pro forma for the issuance of both the DECS and the Debentures and the application of the net proceeds therefrom (estimated to be $187.9 million) as described in "Use of Proceeds." 18 19 PRICE RANGE OF COMMON STOCK AND DIVIDENDS The Company's Common Stock is listed on the NYSE and trades under the symbol SFR. The following table sets forth information as to the high and low closing prices per share of the Common Stock as reported by the NYSE and cash dividends paid per share for each calendar quarter in 1992 and 1993 and the first quarter and second quarter of 1994.
CASH LOW HIGH DIVIDENDS ---- ------ --------- 1992 1st Quarter................................................. $7 $ 9 3/8 $ 0.04 2nd Quarter................................................. 7 7/8 9 3/4 0.04 3rd Quarter................................................. 7 7/8 9 7/8 0.04 4th Quarter................................................. 7 3/4 9 7/8 0.04 1993 1st Quarter................................................. $7 3/4 $11 $ 0.04 2nd Quarter................................................. 9 5/8 11 1/8 0.04 3rd Quarter................................................. 9 1/8 10 5/8 0.04 4th Quarter................................................. 8 3/8 10 7/8 (a) 1994 1st Quarter................................................. $8 1/2 $ 9 7/8 (a) 2nd Quarter (through May 17)(b)............................. $7 5/8 $ 9 1/8 (a)
- --------------- (a) As discussed in "Business and Properties--Corporate Restructuring Program," the Company has eliminated the payment of its $0.04 per share quarterly dividend on its Common Stock. The determination of the amount of future cash dividends, if any, to be declared and paid is in the sole discretion of the Company's Board of Directors and will depend on dividend requirements with respect to the Company's Convertible Preferred Stock, Series 7%, and, assuming consummation of this Offering, the DECS, the Company's financial condition, earnings and funds from operations, the level of its capital and exploration expenditures, dividend restrictions in its financing agreements, its future business prospects and other matters as the Company's Board of Directors deems relevant. For a discussion of certain restrictions on the Company's ability to pay dividends, see "Description of Capital Stock--Common Stock." (b) See the cover page of this Prospectus for a recent closing price of the Common Stock on the NYSE. At March 14, 1994, there were 89,936,650 shares of Common Stock issued and outstanding held by approximately 57,755 shareholders of record. 19 20 SELECTED FINANCIAL AND OPERATING DATA The following data for the years ended December 31, 1989, 1990, 1991, 1992 and 1993 has been derived from the Company's consolidated financial statements audited by Price Waterhouse, independent accountants. This selected historical financial data should be read in conjunction with the consolidated financial statements of the Company, including the notes thereto. The Company's consolidated balance sheets at December 31, 1992 and 1993 and the related consolidated statements of operations, of cash flows and of shareholders' equity for the three years ended December 31, 1993 are included elsewhere in this Prospectus. The data for the three months ended March 31, 1993 and 1994 has been derived from the unaudited financial statements also appearing herein and which, in the opinion of management, include all adjustments, consisting only of normal recurring adjustments, necessary for a fair statement of the results for the unaudited interim periods.
THREE MONTHS ENDED MARCH 31, YEAR ENDED DECEMBER 31, -------------------- ----------------------------------------------------- 1994 1993 1993 1992(a) 1991 1990 1989 -------- -------- -------- -------- ------- ------- ------- (IN MILLIONS, EXCEPT AS NOTED) INCOME STATEMENT DATA: Revenues...................................... $ 90.3 $ 115.3 $ 436.9 $ 427.5 $ 379.8 $ 382.9 $ 322.9 -------- -------- -------- -------- ------- ------- ------- Operating expenses Production and operating.................... 40.6 42.7 163.8 153.4 134.6 135.5 107.1 Oil and gas system and pipelines............ -- 1.1 4.2 3.2 -- -- -- Exploration, including dry hole costs....... 5.0 7.1 31.0 25.5 18.7 21.0 19.4 Depletion, depreciation and amortization.... 32.1 37.6 152.7 146.3 106.6 105.2 99.4 Impairment of oil and gas properties(b)..... -- -- 99.3 -- -- 1.4 1.1 General and administrative.................. 7.6 7.0 32.3 30.9 27.8 25.6 28.6 Taxes (other than income)................... 7.4 7.1 27.3 24.3 27.2 22.0 22.3 Restructuring charges (c)................... 7.0 -- 38.6 -- -- -- -- Loss (gain) on disposition of oil and gas properties................................ (9.4) 0.7 0.7 (13.6) 0.5 2.8 (0.5) -------- -------- -------- -------- ------- ------- ------- Total operating expenses...................... 90.3 103.3 549.9 370.0 315.4 313.5 277.4 -------- -------- -------- -------- ------- ------- ------- Operating income (loss)....................... -- 12.0 (113.0) 57.5 64.4 69.4 45.5 Other income (expense)........................ 0.9 (0.2) (4.8) (10.0) 5.6 (0.3) 18.2 Interest income............................... 0.2 1.2 9.1 2.3 2.3 5.2 4.3 Interest expense.............................. (10.3) (13.7) (45.8) (55.6) (47.3) (57.1) (30.5) Interest capitalized.......................... 0.9 1.1 4.3 4.9 7.7 10.6 13.8 -------- -------- -------- -------- ------- ------- ------- Income (loss) before income taxes and cumulative effect of accounting charge...... (8.3) 0.4 (150.2) (0.9) 32.7 27.8 51.3 Income taxes benefit (expense)................ 5.8 (0.8) 73.1 (0.5) (14.2) (10.8) (26.0) -------- -------- -------- -------- ------- ------- ------- Income (loss) before cumulative effect of accounting change........................... (2.5) (0.4) (77.1) (1.4) 18.5 17.0 25.3 Cumulative effect of accounting change........ -- -- -- -- -- -- 24.5 -------- -------- -------- -------- ------- ------- ------- Net income (loss)............................. (2.5) (0.4) (77.1) (1.4) 18.5 17.0 49.8 Preferred dividend requirement................ (1.8) (1.8) (7.0) (4.3) -- -- -- -------- -------- -------- -------- ------- ------- ------- Earnings (loss) attributable to Common Stock....................................... $ (4.3) $ (2.2) $ (84.1) $ (5.7) $ 18.5 $ 17.0 $ 49.8 -------- -------- -------- -------- ------- ------- ------- -------- -------- -------- -------- ------- ------- ------- Per share data (in dollars): Income (loss) before cumulative effect of accounting change......................... $ (0.05) $ (0.2) $ (0.94) $ (0.07) $ 0.29 $ 0.28 $ 0.48 Cumulative effect of change in accounting for income taxes.......................... -- -- -- -- -- -- 0.47 Earnings (loss) to Common Stock............. (0.05) (0.02) (0.94) (0.07) 0.29 0.28 0.95 Weighted average number of shares outstanding................................. 89.9 89.6 89.7 79.0 63.8 61.7 52.1 STATEMENT OF CASH FLOW DATA: Net cash provided by operating activities..... $ 14.3 $ 41.6 $ 160.2 $ 141.5 $ 128.4 $ 144.1 $ 173.1 Net cash used in investing activities......... 10.8 27.8 121.4 15.9 117.2 108.2 86.8
(Table continued on following page) 20 21
THREE MONTHS ENDED MARCH 31, YEAR ENDED DECEMBER 31, -------------------- ----------------------------------------------------- 1994 1993 1993 1992(a) 1991 1990 1989 -------- -------- -------- -------- ------- ------- ------- (IN MILLIONS, EXCEPT AS NOTED) BALANCE SHEET DATA (AT PERIOD END): Properties and equipment, net................. $ 818.2 $1,076.5 $ 832.7 $1,101.8 $ 797.4 $ 745.0 $ 747.6 Total assets.................................. 1,042.2 1,278.9 1,076.9 1,337.2 911.9 911.1 881.8 Long-term debt................................ 403.5 459.0 405.4 492.8 440.8 417.2 124.7 Convertible Preferred Stock, Series 7%........ 80.0 80.0 80.0 80.0 -- -- -- Shareholders' equity.......................... 320.7 412.8 323.6 416.6 225.1 215.8 228.1 SELECTED OPERATING DATA: Daily average production(d): Crude oil and liquids (MBbls/day) Domestic.................................. 58.0 61.0 60.2 58.3 54.9 52.0 50.7 Argentina................................. 2.5 2.0 2.4 2.4 0.6 -- -- Indonesia................................. 5.5 4.3 4.1 1.8 -- -- -- -------- -------- -------- -------- ------- ------- ------- 66.0 67.3 66.7 62.5 55.5 52.0 50.7 -------- -------- -------- -------- ------- ------- ------- -------- -------- -------- -------- ------- ------- ------- Natural gas (MMcf/day)...................... 155.5 177.8 165.4 126.3 95.2 102.5 81.6 Total production (MBOE/day)................. 91.9 96.9 94.3 83.6 71.4 69.1 64.3 Average sales prices: Crude oil and liquids ($/Bbl) Unhedged Domestic................................ $ 9.64 $ 13.49 $ 12.70 $ 14.38 $ 14.07 $ 17.90 $ 14.11 Argentina............................... 10.27 15.45 14.07 15.99 16.24 -- -- Indonesia............................... 13.74 16.25 15.50 17.51 -- -- -- Total................................... 10.00 13.73 12.93 14.54 14.09 17.90 14.11 Hedged.................................... 10.00 13.73 12.93 14.96 16.16 17.34 14.11 Natural Gas ($/Mcf) Unhedged.................................. $ 2.10 $ 1.96 $ 2.03 $ 1.71 $ 1.49 $ 1.57 $ 1.72 Hedged.................................... 2.07 1.91 1.89 1.70 1.49 1.57 1.72 Proved reserves at year end(e): Crude oil, condensate and natural gas liquids (MMBbls).......................... 248.2 255.1 229.2 222.3 219.8 Natural gas (Bcf)........................... 263.0 277.5 170.8 185.9 188.0 Proved reserves (MMBOE)..................... 292.0 301.5 257.7 253.3 251.1 Proved developed reserves (MMBOE)........... 225.5 248.4 210.3 205.0 204.0 Production costs (included related production, severance and ad valorem taxes) per BOE (in dollars).................................... $ 5.59 $ 5.53 $ 5.39 $ 5.66 $ 6.06 $ 6.22 $ 5.69
- --------------- (a) On May 19, 1992, Adobe was merged with and into the Company. (b) Reflects a non-cash charge of $99.3 million for the impairment of oil and gas properties recorded as of December 31, 1993. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 1 of the Notes to the Company's Consolidated Financial Statements included elsewhere in this Prospectus. (c) Includes losses on property dispositions of $27.8 million, long-term debt repayment penalties of $8.6 million and accruals of certain personnel benefits and related costs of $2.2 million in 1993 and $7.0 million of severance, benefits and relocation costs in 1994. (d) Includes production attributable to the properties sold to Vintage (closed in November 1993) and Bridge (closed in April 1994). Production attributable to such properties during the year ended December 31, 1993 totaled approximately 4.1 MBbls of oil per day and 21.7 MMcf of natural gas per day (7.7 MBOE per day). Production during the three months ended March 31, 1993 attributable to the properties sold to Vintage totaled approximately 3.2 MBbls of oil per day and approximately 7.0 MMcf of natural gas per day (4.4 MBOE per day). Production during the three months ended March 31, 1993 and 1994 attributable to the properties sold to Bridge totaled approximately 1.4 MBbls of oil per day and approximately 14.6 MMcf of natural gas per day (3.8 MBOE per day), and approximately 1.3 MBbls of oil per day and approximately 13.5 MMcf of natural gas per day (3.6 MBOE per day), respectively. (e) The estimates set forth in this table for 1993 give effect to the sale by the Company of approximately 8.0 MMBOE of proved reserves to Bridge, which sale closed in April 1994. 21 22 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL As an independent oil and gas producer, the Company's results of operations are dependent upon the difference between the prices received for oil and gas and the costs of finding and producing such resources. A substantial portion of the Company's crude oil production is from long-lived fields where EOR methods are being utilized. The market price of the heavy (i.e., low gravity, high viscosity) and sour (i.e., high sulfur content) crude oils produced in these fields is lower than sweeter, light (i.e., low sulfur and low viscosity) crude oils, reflecting higher transportation and refining costs. The lower price received for the Company's domestic heavy and sour crude oil is reflected in the average sales price of the Company's domestic crude oil and liquids (excluding the effect of hedging transactions) for 1993 of $12.70 per barrel, compared to $16.94 per barrel for West Texas Intermediate ("WTI") crude oil (an industry posted price generally indicative of spot prices for sweeter light crude oil). In addition, the lifting costs of heavy crude oils are generally higher than the lifting costs of light crude oils. As a result of these narrower margins, even relatively modest changes in crude oil prices may significantly affect the Company's revenues, results of operations, cash flows and proved reserves. In addition, prolonged periods of high or low oil prices may have a material effect on the Company's financial position. Crude oil prices are subject to significant changes in response to fluctuations in the domestic and world supply and demand and other market conditions as well as the world political situation as it affects OPEC, the Middle East and other producing countries. See "Business and Properties--Current Markets for Oil and Gas." The period since mid-1990 has included some of the largest fluctuations in oil prices in recent times, primarily due to the political unrest in the Middle East. The actual average sales price (unhedged) received by the Company ranged from a high of $23.92 per barrel in the fourth quarter of 1990 to a low of $10.00 per barrel during the three months ended March 31, 1994. The Company's average sales price for its 1993 oil production was $12.93 per barrel. Based on operating results of 1993, the Company estimates that a $1.00 per barrel increase or decrease in average oil sales prices would have resulted in a corresponding $21.6 million change in 1993 income from operations and a $16.2 million change in 1993 cash flow from operating activities. The Company also estimates that a $0.10 per Mcf increase or decrease in average natural gas sales prices would have resulted in a corresponding $5.8 million change in 1993 income from operations and a $4.4 million change in 1993 cash flow from operating activities. The foregoing estimates do not give effect to changes in any other factors, such as the effect of the Company's hedging program or depreciation and depletion, that would result from a change in oil and natural gas prices. During 1992 and 1993, certain significant events occurred which affect the comparability of prior periods, including the merger of Adobe with and into the Company in May 1992, the formation of the Santa Fe Energy Trust (the "Trust") in November 1992 and implementation of the corporate restructuring program adopted in October 1993. The corporate restructuring program includes (i) the concentration of capital spending in the Company's core operating areas, (ii) the disposition of non-core assets, (iii) the elimination of the $0.04 per share quarterly Common Stock dividend and (iv) the recognition of $38.6 million of restructuring charges. See Note 2 of the Notes to the Company's Consolidated Financial Statements included elsewhere in this Prospectus and "Business and Properties--Corporate Restructuring Program." In addition, the Company's results of operations for 1993 include a charge of $99.3 million for the impairment of oil and gas properties. The Company's capital program will be concentrated in three domestic core areas--the Permian Basin in Texas and New Mexico, the offshore Gulf of Mexico and the San Joaquin Valley of California--as well as its productive areas in Argentina and Indonesia. The domestic program includes development activities in the Delaware and Cisco-Canyon formations in west Texas and southeast New Mexico, a development drilling program for the offshore Gulf of Mexico natural gas properties and relatively low risk infill drilling in the San Joaquin Valley of California. Internationally, the program includes development of the Company's Sierra Chata discovery in Argentina with gas sales expected to commence in early 1995 22 23 and the Salawati Basin Joint Venture in Indonesia. See "Business and Properties--Domestic Development Activities" and "--International Development Activities." The Company's non-core asset disposition program includes the sale of its natural gas gathering and processing assets to Hadson Corporation ("Hadson") (completed in December 1993), the sale to Vintage of certain southern California and Gulf Coast oil and gas producing properties (completed in November 1993) and the sale to Bridge of certain Mid-Continent and Rocky Mountain oil and gas producing properties and undeveloped acreage (completed in April 1994). See "Business and Properties--Corporate Restructuring Program" for a description of the transactions with Hadson, Vintage and Bridge. In the first quarter of 1994, the Company sold the remaining 575,000 Depositary Units which it held in the Trust for $11.3 million and its interest in certain other oil and gas properties for $8.3 million. As a result of the Vintage and Bridge dispositions described above, the Company has sold properties having combined production during 1993 of 4.1 MBbls of oil per day and 21.7 MMcf of natural gas per day and estimated proved reserves of approximately 16.7 MMBOE. The restructuring program also includes an evaluation of the Company's capital and cost structures to examine ways to increase flexibility and strengthen the Company's financial performance. Based upon the review of its capital structure, the Company determined to proceed with the Refinancing to accomplish its financial strategy. Based upon the review of its cost structure, the Company has implemented a cost reduction program that includes the reduction of its salaried work force by approximately 20%, an improvement in the efficiency of its information systems and reductions in other general and administrative costs. These measures, together with the Company's on-going efforts to reduce production costs and the recent sales of its higher cost, non-core properties, are designed to reduce costs and expenses by approximately $30.0 million from the 1993 level (which reduction includes approximately $5.0 million of non-recurring costs). Approximately $10.0 million of the estimated cost reduction is expected to be in production and operating costs. Substantially all of this cost reduction program is expected to be implemented by year end 1994. During the quarter ended March 31, 1994, the Company recorded $7.0 million in restructuring charges reflecting the estimated costs of such cost reduction program. See "--Liquidity and Capital Resources." In May 1992, Adobe, an oil and gas exploration and production company, was merged with and into the Company (the "Adobe Merger"). The acquisition was accounted for as a purchase and the results of operations of the properties acquired (the "Adobe Properties") are included in the Company's results of operations effective June 1, 1992. Pursuant to the Adobe Merger, the Company issued approximately 25.0 million shares of Common Stock and 5,000,000 shares of its Convertible Preferred Stock, Series 7%, and assumed approximately $175.0 million of long-term debt and other liabilities. Pursuant to the Adobe Merger, the Company also acquired Adobe's proved reserves and inventory of undeveloped acreage. As of December 31, 1991, Adobe's estimated proved reserves totaled approximately 53.2 MMBOE (net of 6.9 MMBOE attributable to Adobe's ownership in certain gas plants), of which approximately 58% was natural gas (approximately 66% of Adobe's estimated domestic proved reserves were natural gas). Approximately 72% of the discounted future net cash flow of Adobe's estimated domestic proved reserves was concentrated in three areas of operation--offshore Gulf of Mexico, onshore Louisiana and in the Spraberry Trend in west Texas. In addition, Adobe's international operations consisted of certain production sharing arrangements in Indonesia, in respect of which approximately 6.0 MMBOE of estimated proved reserves had been attributed to Adobe's interest as of December 31, 1991. The location of the Adobe Properties enhanced the Company's existing domestic operations and added significant operations to the Company's international program. In November 1992, 5,725,000 Depositary Units ("Depositary Units") consisting of interests in the Trust were sold in a public offering. After payment of certain costs and expenses, the Company received net proceeds of $70.1 million and 575,000 Depositary Units. For any calendar quarter ending on or prior to December 31, 2002, the Trust will receive additional royalty payments to the extent necessary to distribute $0.40 per Depositary Unit per quarter. The source of such payments, if needed, will be limited to the Company's remaining royalty interest in certain of the properties conveyed to the Trust. The aggregate amount of such payments are limited to $20.0 million on a revolving basis. The Company was 23 24 required to make additional royalty payments of $362,000 and $505,700 with respect to the distributions made by the Trust for operations during the quarters ended December 31, 1993 and March 31, 1994, respectively. See "Business and Properties--Santa Fe Energy Trust." RESULTS OF OPERATIONS The following table sets forth, on the basis of the BOE produced by the Company during the applicable period, certain of the Company's costs and expenses for each of the periods indicated.
THREE MONTHS ENDED MARCH 31, YEAR ENDED DECEMBER 31, ----------------- ---------------------------- 1994 1993 1993 1992 1991 ------ ------ ------ ------ ------ Production and operating costs per BOE (a)....... $ 4.91 $ 4.90 $ 4.76 $ 5.02 $ 5.17 Exploration, including dry hole costs per BOE.... 0.61 0.82 0.90 0.84 0.72 Depletion, depreciation and amortization per BOE........................................... 3.88 4.31 4.44 4.79 4.09 General and administrative costs per BOE......... 0.92 0.80 0.94 1.01 1.07 Taxes other than income per BOE (b).............. 0.90 0.82 0.79 0.80 1.05 Interest, net, per BOE (c)....................... 1.11 1.31 0.94 1.58 1.43
- --------------- (a) Excluding related production, severance and ad valorem taxes. (b) Includes production, severance and ad valorem taxes. (c) Reflects interest expense less amounts capitalized and interest income. First Quarter 1994 Compared with First Quarter 1993 Total revenues declined 22% from $115.3 million in the first quarter of 1993 to $90.3 million in the first quarter of 1994 primarily due to lower oil prices in 1994. The average price realized per barrel of oil in 1994 was $10.00, a 27% decrease from the $13.73 realized in 1993. Daily average oil production decreased 1.3 MBbls per day during the first quarter of 1994 primarily reflecting the sale to Vintage in the fourth quarter of 1993 of properties which produced approximately 3.2 MBbls per day, partially offset by increased production in Indonesia and Argentina. Natural gas production declined to an average of 155.5 MMcf per day in the first quarter of 1994 compared to 177.8 MMcf per day in the first quarter of 1993. However, production for the 1993 period included a positive adjustment of approximately 16.2 MMcf per day related to production in prior periods from certain nonoperated properties. In addition, the 1993 volumes include approximately 7.0 MMcf per day attributable to the properties sold to Vintage. Natural gas sales prices (hedged) for 1994 averaged $2.07 per Mcf, approximately 8% higher than the $1.91 realized in 1993. Natural gas revenues for 1994 and 1993 were reduced by $0.3 million ($0.03 per Mcf) and $0.8 million ($0.05 per Mcf), respectively, by losses on hedging transactions. Total costs and expenses for the first quarter of 1994 of $90.3 million were 13% lower than the $103.3 million reported for the first quarter of 1993. Exploration expenses were down $2.1 million primarily reflecting lower geological and geophysical costs with respect to foreign operations and lower dry hole costs. Depletion, depreciation and amortization ("DD&A") decreased $5.5 million primarily reflecting the effect of property impairments taken in the fourth quarter of 1993 and the sale of properties to Vintage. On a BOE basis, DD&A decreased by 10% from $4.31 per barrel to $3.88 per barrel. Costs and expenses for the first quarter of 1994 include $7.0 million in restructuring charges (see "--Liquidity and Capital Resources") and a $9.4 million gain on the sale of certain oil and gas properties and the 575,000 Depositary Units. Interest expense for the first quarter of 1994 includes a credit of $2.4 million reflecting adjustments to provisions made in prior periods with respect to interest on certain federal income tax audit adjustments. Other income (expense) for the first quarter of 1994 includes $1.4 million in dividend 24 25 income on Hadson preferred stock (paid in-kind) and a $0.6 million loss on the Company's equity in Hadson common stock. Income tax expense for the first quarter of 1994 includes a $3.0 million benefit of adjustments to provisions made in prior periods with respect to certain federal income tax audit adjustments. 1993 Compared with 1992 Total revenues increased approximately 2% from $427.5 million in 1992 to $436.9 million in 1993, principally due to an increase in oil and natural gas production offset by a decline in average oil prices. Average daily oil production increased 7% from 62.5 MBbls in 1992 to 66.7 MBbls in 1993, principally due to increased domestic and Indonesian production. The average price realized per barrel of oil during 1993 was $12.93, a decrease of 14% versus the average price of $14.96 in 1992. Natural gas production increased 31% from 126.3 MMcf per day in 1992 to 165.4 MMcf per day in 1993, primarily reflecting the effect of a full year's production from the Adobe Properties. Average natural gas prices realized increased approximately 11% from $1.70 per Mcf in 1992 to $1.89 per Mcf in 1993. Production and operating costs increased $10.4 million in 1993, primarily reflecting the effect of a full year's costs for the Adobe Properties; however, on a BOE basis such costs declined from $5.02 per barrel in 1992 to $4.76 per barrel in 1993. Exploration costs were $5.5 million higher than in 1992 primarily reflecting higher geological and geophysical costs and higher dry hole costs. DD&A increased $6.4 million in 1993 primarily reflecting a full year's expense on Adobe Properties partially offset by reduced amortization rates with respect to certain unproved properties. DD&A for 1993 includes $12.1 million with respect to the properties sold to Vintage and Bridge. On a BOE basis, DD&A decreased by $0.35 per barrel, from $4.79 to $4.44 per barrel. General and administrative costs increased $1.4 million principally due to a $1.8 million charge related to the adoption of Statement of Financial Standards No. 112--"Employer's Accounting for Postemployment Benefits." Taxes (other than income) increased by $3.0 million in 1993 primarily reflecting the effect of the Adobe Properties. Costs and expenses for 1993 also include $99.3 million in impairments of oil and gas properties and $38.6 million in restructuring charges. The Company estimates that the impairments taken in 1993 will result in a $20.0 million reduction in DD&A in 1994. The restructuring charges include losses on property dispositions of $27.8 million, long-term debt repayment penalties of $8.6 million and accruals of certain personnel benefits and related costs of $2.2 million. In connection with the property dispositions effected during 1993 (see "--Liquidity and Capital Resources"), the Company sold properties having combined production during 1993 of 4.1 MBbls of oil per day and 21.7 MMcf of natural gas per day and combined estimated proved reserves of approximately 16.7 MMBOE. The Company's income from operations for 1993 includes $8.5 million with respect to such properties. Interest income in 1993 includes $6.8 million related to a $10 million refund received as a result of the completion of the audit of the Company's federal income tax returns for 1971 through 1980. The decrease in interest expenses during 1993 reflects a decrease in the Company's debt outstanding and a $5.7 million credit related to a revision to a tax sharing agreement with the Company's former parent. Other income and expenses of 1993 includes a $4.0 million charge related to the accrual of a contingent loss with respect to the operations of a former affiliate of Adobe. 1992 Compared with 1991 Total revenues increased approximately 13% from $379.8 million in 1991 to $427.5 million in 1992 principally due to an increase of approximately $53.2 million attributable to production from properties acquired in the Adobe Merger and an increase of approximately $10.7 million and $10.2 million in revenues from the Company's domestic and Argentine properties, respectively, offset in part by a decline of $32.0 million in crude oil hedging revenues. Oil production increased 13% from 55.5 MBbls per day in 1991 to 62.5 MBbls per day in 1992, reflecting a 3.4 MBbl per day increase in domestic oil production and a 3.6 MBbl per day increase in production in Argentina and Indonesia. The average price realized per barrel of oil during 1992 decreased to $14.96, a decrease of 7% versus the average price of $16.16 in 25 26 1991, primarily reflecting a $32.0 million decrease in hedging revenues. Natural gas production increased 33% from 95.2 MMcf per day in 1991 to 126.3 MMcf per day in 1992 as a result of properties acquired in the Adobe Merger. Average natural gas prices realized increased approximately 14% from $1.49 per Mcf in 1991 to $1.70 per Mcf in 1992. Total operating expenses of the Company increased $54.6 million from $315.4 million in 1991 to $370.0 million in 1992 primarily reflecting costs associated with the Adobe Merger. Production and operating costs in 1992 were $18.8 million higher than in 1991, primarily reflecting costs related to the Adobe Properties and increased fuel costs associated with the Company's EOR projects. On a BOE basis, production and operating costs declined from $5.17 per barrel in 1991 to $5.02 per barrel in 1992, primarily reflecting the lower cost structure of the Adobe Properties. Exploration costs were $6.8 million higher than in 1991 primarily reflecting higher geological and geophysical costs with respect to foreign projects. Depletion, depreciation and amortization costs were $39.7 million higher in 1992 due to the acquisition of the Adobe Properties and, to a lesser extent, adjustments to oil and gas reserves with respect to certain producing properties. General and administrative costs increased $3.1 million principally due to a $1.2 million charge related to certain stock awards which fully vested upon consummation of the Adobe Merger and certain other merger-related costs. Taxes (other than income) decreased by $2.9 million in 1992 as a result of lower accruals with respect to property taxes. The $13.6 million gain on the disposition of properties in 1992 primarily relates to the sale of certain royalty interest properties, in which the Company had no remaining financial basis. The increase in interest expense during 1992 reflects the increase in debt as a result of the Adobe Merger. Other income and expenses for 1992 includes a $10.9 million charge for costs incurred by Adobe in connection with the Adobe Merger and paid by Santa Fe. LIQUIDITY AND CAPITAL RESOURCES Historically, the Company has generally funded capital and exploration expenditures and working capital requirements from cash provided by operating activities. Depending upon the future levels of operating cash flows, which are significantly affected by oil and gas prices, the restrictions on additional borrowings included in certain of the Company's debt agreements, together with debt service requirements and dividends, may limit the cash available for future exploration, development and acquisition activities. Net cash provided by operating activities totaled $14.3 million in the first quarter of 1994 and $41.6 million in the first quarter of 1993; net cash used in investing activities (net of proceeds from the sales of properties) in such periods totaled $10.8 million and $27.8 million, respectively. Net cash provided by operating activities totaled $160.2 million, $141.5 million and $128.4 million for the years ended December 31, 1993, 1992 and 1991, respectively; net cash used in investing activities in such periods totaled $121.4 million, $15.9 million and $117.2 million, respectively. The Company's cash flow from operating activities is a function of the volumes of oil and gas produced from the Company's properties and the sales prices realized therefor. Crude oil and natural gas are depleting assets. Therefore, unless the Company replaces over the long term the oil and natural gas produced from the Company's properties, the Company's assets will be depleted over time and its ability to service and incur debt at constant or declining prices will be reduced. The Company's cash flow from operations for the first quarter of 1993 reflects an average sales price (unhedged) for the Company's 1993 oil production of $13.73 per barrel and the Company's average sales price for oil production for the full year 1993 (unhedged) was $12.93 per barrel. For the three months ended March 31, 1994, the average sales price (unhedged) for the Company's 1994 oil production was $10.00 per barrel. If such lower oil prices prevail throughout 1994, the Company's cash flow from operating activities for 1994 will be significantly lower than that for 1993. In October 1993, the Company's Board of Directors adopted a broad corporate restructuring program that focuses on the concentration of capital spending in core areas and the disposition of non-core assets. The Company's asset disposition program adopted in connection with the 1993 restructuring program has been substantially completed by the asset sales to Hadson, Vintage and Bridge, the sale 26 27 of the 575,000 Depositary Units in the Trust and the sale of its interest in certain other oil and gas properties. As a result of such sales, the Company sold a total of 16.7 MMBOE of proved reserves and undeveloped acreage for a total of approximately $108.9 million, and sold certain gas gathering and processing facilities for Hadson securities. In conjunction with the 1993 restructuring program, the Company also determined to undertake a review of its capital and cost structures. Based upon such review of its capital structure, the Company determined to proceed with the Refinancing in the belief that it will increase the Company's financial flexibility, strengthen the Company's financial condition and permit the Company to pursue aggressively its operating strategy. The net proceeds from the Refinancing will be used to repay existing indebtedness of the Company. See "Use of Proceeds." Based upon the review of its cost structure, the Company has implemented a cost reduction program that includes the reduction of its salaried work force by approximately 20%, an improvement in the efficiency of its information systems and reductions in other general and administrative costs. These measures, together with the Company's on-going efforts to reduce production costs and the recent sales of its higher cost, non-core properties, are designed to reduce costs and expenses by approximately $30.0 million from the 1993 level (which reduction includes approximately $5.0 million of non-recurring costs). Approximately $10.0 million of the estimated cost reduction is expected to be in production and operating costs. Substantially all of this cost reduction program is expected to be implemented by year end 1994. During the quarter ended March 31, 1994, the Company recorded $7.0 million in restructuring charges reflecting the estimated costs of such cost reduction program. Under the most restrictive covenant in the Company's existing credit agreements, as of March 31, 1994 the Company could incur up to $61.7 million of additional indebtedness. After giving effect as of March 31, 1994 to the consummation of this Offering and the Concurrent Debenture Offering and the application of the net proceeds therefrom, as described in "Use of Proceeds," the Company would have been able to incur up to $146.6 million of additional indebtedness under its most restrictive covenant. At March 31, 1994, under the Company's most restrictive covenant, the Company had the ability to pay $18.4 million in dividends on its capital stock. Pro forma for this Offering and the Concurrent Debenture Offering, the Company would have had the capacity to pay dividends of up to $110.0 million in the aggregate on its capital stock, including its Convertible Preferred Stock, Series 7%, and the DECS. However, pursuant to the terms of the Debentures, upon completion of this Offering and the Concurrent Debenture Offering, the Company would have the ability to pay only up to $50.0 million on its Common Stock. The amount permitted under these covenants to be used to pay dividends will vary over time depending, among other things, on the Company's earnings and any issuances of capital stock. The Indenture pursuant to which the Debentures will be issued does not restrict the Company from paying preferred dividends on the Convertible Preferred Stock, Series 7%, or the DECS; however, payment of such preferred dividends reduces the Company's capacity under the Indenture to pay Common Stock dividends. As a part of the 1993 restructuring program, the Company eliminated its $0.04 per share quarterly dividend on its Common Stock and announced that it might spend up to $240 million in 1994 on an accelerated capital program. However, as a result of the depressed crude oil prices that have prevailed since November 1993, the Company, consistent with industry practice, has determined to defer certain of its capital projects in order to prudently manage cash flow in the near term. Based on current market conditions, the Company has authorized up to $130 million of capital expenditures during 1994, a level which should allow the Company to replace its estimated 1994 production, although no assurance can be given regarding such replacement. The Company intends to continue to monitor its capital expenditure program throughout the balance of 1994 and may, in response to industry conditions, including, without limitation, prevailing oil and natural gas prices and the outlook therefor, revise such program. The Company is a party to several long-term and short-term credit agreements which restrict the Company's ability to take certain actions, including covenants that restrict the Company's ability to incur additional indebtedness and to pay dividends on its capital stock. For a description of such credit 27 28 agreements at December 31, 1993, see Note 7 of the Notes to the Company's Consolidated Financial Statements included elsewhere in this Prospectus. Effective March 16, 1994, the Company entered into the Bank Facility with a group of banks for which Texas Commerce Bank National Association ("Texas Commerce") and NationsBank of Texas act as co-agents. The Bank Facility consists of a five-year secured reducing revolving credit facility maturing December 31, 1998 ("Facility A") and a three-year unsecured reducing revolving credit facility maturing December 31, 1996 ("Facility B"). Assuming completion of this Offering and the Concurrent Debenture Offering and the application of the net proceeds therefrom as described in "Use of Proceeds," the initial aggregate borrowing limits under the Bank Facility would be $175.0 million (up to $90.0 million under Facility A and up to $85.0 million under Facility B) none of which would be outstanding. Interest rates under the Bank Facility are tied to LIBOR or Texas Commerce's prime rate, with the actual interest rate reflecting certain ratios based upon the Company's ability to repay its outstanding debt and the value and projected timing of production of the Company's oil and gas reserves. These and other similar ratios will also affect the Company's ability to borrow under the Bank Facility and the timing and amount of any required repayments and corresponding commitment reductions. Marc J. Shapiro, a director of the Company, is the Chairman and Chief Executive Officer of Texas Commerce. EFFECTS OF INFLATION Inflation during the three years ended December 31, 1993 has had little effect on the Company's capital costs and results of operations. ENVIRONMENTAL MATTERS Almost all phases of the Company's oil and gas operations are subject to stringent environmental regulation by governmental authorities. Such regulation has increased the costs of planning, designing, drilling, installing, operating and abandoning oil and gas wells and other facilities. The Company has expended significant financial and managerial resources to comply with such regulations. Although the Company believes its operations and facilities are in general compliance with applicable environmental regulations, risks of substantial costs and liabilities are inherent in oil and gas operations. It is possible that other developments, such as increasingly strict environmental laws, regulations and enforcement policies or claims for damages to property, employees, other persons and the environment resulting from the Company's operations, could result in significant costs and liabilities in the future. As it has done in the past, the Company intends to fund its cost of environmental compliance from operating cash flows. See also, "Business--Other Business Matters--Environmental Regulation" and Note 12 of the Notes to the Company's Consolidated Financial Statements included elsewhere in this Prospectus. DIVIDENDS Dividends on the Company's Convertible Preferred Stock, Series 7%, are cumulative at an annual rate of $1.40 per share. No dividends may be declared or paid with respect to the Common Stock if any dividends with respect to the Convertible Preferred Stock, Series 7%, or the DECS are in arrears. As described elsewhere in this Prospectus, the Company has eliminated the payment of its $0.04 per share quarterly dividend on its Common Stock. The determination of the amount of future cash dividends, if any, to be declared and paid on the Company's Common Stock is in the sole discretion of the Company's Board of Directors and will depend on dividend requirements with respect to the Convertible Preferred Stock, Series 7%, and the DECS, the Company's financial condition, earnings and funds from operations, the level of capital and exploration expenditures, dividend restrictions in financing agreements, future business prospects and other matters the Board of Directors deems relevant. 28 29 BUSINESS AND PROPERTIES GENERAL The Company is engaged in the exploration, development and production of oil and natural gas in the continental United States and in certain foreign areas. At December 31, 1993, the Company had worldwide proved reserves totaling 292.0 MMBOE (consisting of approximately 248.2 MMBbls of oil and approximately 263.0 Bcf of natural gas), of which approximately 93% were domestic reserves and approximately 7% were foreign reserves. During 1993, the Company's worldwide production aggregated approximately 94.3 MBOE per day, of which approximately 71% was crude oil and approximately 29% was natural gas. A substantial portion of the Company's domestic oil production is in long-lived fields with well-established production histories. Pursuant to the Company's corporate restructuring program (see "--Corporate Restructuring Program" below), the Company has focused its activities on its three domestic core areas--the Permian Basin in Texas and New Mexico, the offshore Gulf of Mexico and the San Joaquin Valley of California--as well as in Argentina and Indonesia. For the five years ended December 31, 1993, the Company has replaced approximately 172% of its production at an average finding cost of $4.80 per BOE. Over the last four years, the Company has increased overall production by increasing production from existing properties and through acquisitions. In addition, the Company has reduced its overall cost structure. For example, over the four-year period ended December 31, 1993, Santa Fe has increased its average daily production from 69.1 MBOE to 94.3 MBOE (including 7.7 MBOE per day in 1993 attributable to production from non-core assets sold pursuant to the corporate restructuring program) and has reduced its average production costs (including related production, severance and ad valorem taxes) from $6.22 per BOE in 1990 to $5.39 per BOE in 1993. Most of the Company's domestic crude oil production is located in California and Texas, while its domestic natural gas production comes primarily from the Gulf of Mexico, New Mexico and Texas. During 1993, the Company's domestic daily production averaged approximately 60.2 MBbls of crude oil and 165.0 MMcf of natural gas. Substantially all of the Company's oil and gas production is sold at market responsive prices. Pursuant to the corporate restructuring program, the Company sold properties having 1993 combined production of 4.1 MBbls per day and 21.7 MMcf per day and estimated proved reserves of approximately 16.7 MMBOE. The domestic crude oil marketing activities of the Company are conducted through its Santa Fe Energy Products Division ("Energy Products"), which is also engaged in crude oil trading. Substantially all of the Company's domestic natural gas production is currently marketed under the terms of a sales contract with Hadson. See "--Current Markets for Oil and Gas." A substantial portion of the Company's domestic oil production is in long-lived fields with well-established production histories and where EOR methods are employed. As of December 31, 1993, approximately 69% of the Company's domestic proved crude oil and liquids reserves and 50% of its 1993 average daily domestic production of crude oil and liquids were attributable to the Midway-Sunset field in the San Joaquin Valley of California, where the Company first began production in 1905. Nearly all of the reserves in this field are heavy oil, the production of which depends primarily on steam injection. As of December 31, 1993, an additional 21% of the Company's domestic proved crude oil and liquids reserves and approximately 25% of its 1993 average daily domestic production of crude oil and liquids were attributable to five other oil producing properties: the Wasson and Reeves fields in the Permian Basin of west Texas and the South Belridge, Kern River and Coalinga fields in the San Joaquin Valley. The Company's foreign production is located in the El Tordillo field in Argentina and in the Salawati Basin and Salawati Island area of Indonesia. Production from the El Tordillo field averaged 2.4 MBbls of oil per day in 1993 and production from the Indonesian operations averaged 4.1 MBbls of oil per day in 1993. The Company maintains an active exploration and development program, a significant portion of which consists of EOR projects on the producing fields discussed above. During 1993, Santa Fe spent a 29 30 total of $128.6 million on exploration and development programs and $32.6 million on proved property acquisitions. In October 1993, the Company announced that its 1994 capital expenditures could increase to up to $240 million. However, as a result of depressed oil prices that have prevailed since November 1993, the Company, consistent with industry practice, has determined to defer certain of its capital projects in order to prudently manage cash flow in the near term. Based upon current market conditions, the Company has authorized up to $130 million of capital expenditures during 1994, a level which should allow the Company to replace its estimated 1994 production, although no assurance can be given regarding such replacement. The Company intends to continue to monitor its capital expenditure program throughout the balance of 1994 and may, in response to industry conditions, including, without limitation, prevailing oil and natural gas prices and the outlook therefor, revise such program. In the United States, at December 31, 1993, the Company held oil and gas rights to approximately 0.8 million net undeveloped leasehold and fee acres in 14 states, excluding approximately 1.1 million net undeveloped acres sold to Bridge in April 1994 and 0.1 million net undeveloped fee acres sold to another company in January 1994. See "--Corporate Restructuring Program." Outside the United States, at December 31, 1993, the Company held exploration rights with respect to an aggregate of approximately 3.5 million net undeveloped acres in Argentina, Bolivia, Canada, Gabon, Indonesia, Morocco, Myanmar and Papua New Guinea. CORPORATE RESTRUCTURING PROGRAM In October 1993, the Company's Board of Directors adopted a broad corporate restructuring program designed to improve earnings and cash flow while increasing production and replacing reserves in the long-term. The restructuring program is the result of an intensive review of the Company's operations and cash flows and focuses on the concentration of capital spending in the Company's core operating areas and the disposition of non-core assets. To provide additional funding for the capital program, the Company also announced the elimination of the payment of its $0.04 per share quarterly dividend on the Common Stock, which will make available approximately $14 million annually. The dividend on the Company's Convertible Preferred Stock, Series 7%, will remain at its current level and dividends on the DECS are expected to be approximately $7.8 million per year. As a part of the Company's restructuring program, the Company intends to concentrate its capital spending on its three domestic core areas--the Permian Basin in Texas and New Mexico, the offshore Gulf Coast and the San Joaquin Valley of California--as well as its productive areas in Indonesia and Argentina. The domestic program includes development activities in the Delaware formation in southeast New Mexico, a development drilling program for the offshore Gulf of Mexico natural gas properties and infill drilling in the San Joaquin Valley of California. Internationally, the program includes development of the Company's Sierra Chata discovery in Argentina with gas sales expected to commence in early 1995. The restructuring program includes an evaluation of the Company's capital and cost structures to examine ways to increase flexibility and strengthen the Company's financial performance. In this respect, in 1994 the Company determined to proceed with the Refinancing, of which this Offering and the Concurrent Debenture Offering are a part, pursuant to which approximately $179.3 million of the Company's long-term indebtedness will be refinanced, assuming consummation of such offerings. As a result of the dispositions described below, the Company has sold undeveloped leasehold acreage and properties having combined production during 1993 of 4.1 MBbls of oil per day and 21.7 MMcf of natural gas per day and estimated proved reserves of approximately 16.7 MMBOE for total proceeds of approximately $89.3 million, has sold its natural gas gathering and processing assets for Hadson securities and has realized approximately $11.3 million from the sale of its remaining Depositary Units in the Trust. In addition, during the first quarter of 1994 the Company sold its interest in certain oil and gas properties for $8.3 million. As a result of these transactions, the Company has disposed of substantially all of its inventory of non-core properties. Sale to Hadson. In December 1993, the Company completed a transaction with Hadson under the terms of which the Company sold the common stock of Adobe Gas Pipeline Company ("AGPC"), a 30 31 wholly owned subsidiary, to Hadson in exchange for Hadson 11.25% preferred stock with a face value of $52.0 million and 40% of Hadson's common stock. In addition, the Company signed a seven-year gas sales contract under the terms of which Hadson will market substantially all of the Company's domestic natural gas production from specified existing wells and certain domestic development and exploration wells. Pursuant to such contract, Hadson will be required to pay the Company for all production delivered at a price for such gas equal to stipulated published monthly index prices. See "--Current Markets for Oil and Gas." The Company also designated one-half of the members of the Hadson Board of Directors. AGPC's assets include approximately 630 miles of gathering and transportation lines in Oklahoma, Texas and New Mexico with three processing plants in west Texas and New Mexico and an intrastate pipeline system supplying gas to commercial customers in Lubbock, Texas. Hadson's natural gas assets are predominantly located in southeastern New Mexico and include two gas processing facilities, a 12 Bcf natural gas storage facility and the 650-mile Llano intrastate pipeline which has six connections to various interstate pipelines serving strategic markets in the Midwest, on the East Coast and in southern California. Sale to Vintage. In November 1993, the Company completed the sale to Vintage of certain southern California and Gulf Coast producing properties for net proceeds totaling $42.0 million in cash. The transaction included most of the Company's California interests outside its core area in the San Joaquin Valley as well as certain offshore Gulf Coast properties in Texas, Louisiana and Mississippi. Production from the properties sold to Vintage averaged approximately 2.8 MBbls of oil per day and 6.5 MMcf of natural gas per day during 1993. During 1993 such properties contributed $2.7 million to the Company's income from operations. Sale to Bridge. On April 8, 1994, the Company completed the sale to Bridge of certain Mid-Continent and Rocky Mountain producing and nonproducing oil and gas properties. The purchase agreement was originally signed in December 1993. Bridge paid the Company approximately $47.3 million in cash, reflecting the net effect of estimated closing adjustments to the original $51 million sales price. The transaction included substantially all of the Company's assets in the Anadarko Basin of Oklahoma and Texas as well as its interests in the Rocky Mountain states, excluding its interests in the Canyon Creek natural gas field in Wyoming. The undeveloped acreage includes approximately 1.7 million mineral and leasehold acres and exploratory options on an additional 8.1 million acres. Production from the properties sold to Bridge averaged approximately 1.3 MBbls of oil per day and 15.2 MMcf of natural gas per day during 1993. During 1993, such properties contributed $5.8 million to the Company's income from operations. 31 32 RESERVES The following table sets forth information regarding changes in the Company's estimates of proved net reserves from January 1, 1991 to December 31, 1993 and the balance of the Company's estimated proved developed reserves at December 31 of each of the years 1990 through 1993.
INCREASES (DECREASES) ------------------------------------------------------------------------------ BALANCE NET CHANGES AT REVISION EXTENSIONS, PURCHASES IN BALANCE BEGINNING OF DISCOVERIES (SALES) OF OWNERSHIP- AT END OF PREVIOUS IMPROVED AND MINERALS PARTNER- OF PERIOD ESTIMATES RECOVERY ADDITIONS IN PLACE PRODUCTION SHIP(a) PERIOD --------- --------- -------- ----------- ---------- ---------- ---------- ------- Proved Reserves at December 31, 1991: Oil and Condensate (MMBbls)............ 222.3 (1.9) 15.9 1.8 10.9 (20.2) 0.4 229.2 Gas (Bcf)............. 185.9 0.4 0.5 19.6 (3.0) (34.8) 2.2 170.8 Oil Equivalent (MMBOE)............. 253.3 (1.8) 16.0 5.1 10.4 (26.0) 0.7 257.7 Proved Reserves at December 31, 1992: Oil and Condensate (MMBbls)............ 229.2 14.1 17.0 2.6 15.0 (23.0) 0.2 255.1 Gas (Bcf)............. 170.8 7.3 1.3 5.6 137.1 (46.2) 1.6 277.5 Oil Equivalent (MMBOE)............. 257.7 15.3 17.2 3.6 37.9 (30.6) 0.4 301.5 Proved Reserves at December 31, 1993: Oil and Condensate (MMBbls)............ 255.1 (10.8) 26.7 6.2 (4.8) (24.3) 0.1 248.2 Gas (Bcf)............. 277.5 26.7 -- 55.9 (37.5) (60.4) 0.8 263.0 Oil Equivalent (MMBOE)............. 301.5 (6.3) 26.7 15.4 (11.1) (34.4) 0.2 292.0 (b)
DECEMBER 31, ------------------------------------------ 1993 1992 1991 1990 ------ ------ ------ ------ Proved Developed Reserves (MMBOE)........................................... 225.5 248.4 210.3 205.0
- --------------- (a) The information set forth under the column headed "Changes in Ownership--Partnership" reflects reserve additions attributable to the Company's increased ownership interest in Santa Fe Energy Partners, L.P. (the "Partnership") caused by the reinvestment of distributions received by the Company in respect of its interest in the Partnership. At December 31, 1993, the Company (through its subsidiaries) owned an aggregate 100% interest in the Partnership. (b) At December 31, 1993, 5.2 MMBOE were subject to a 90% net profits interest held by the Trust. See "--Santa Fe Energy Trust." Historically, the Company has utilized active development and exploration programs as well as selected acquisitions to replace its reserves depleted by production. The Company has increased its proved reserves (net of production) by approximately 35% over the five years ended December 31, 1993. Most of such increases are attributable to proved reserve additions from the Company's producing oil properties in the San Joaquin Valley of California and the Permian Basin in west Texas, proved reserves acquired in the Adobe Merger and other purchases of oil and gas reserves. At December 31, 1993, the Company's reserves were 9.5 MMBOE lower than at December 31, 1992, primarily reflecting the sale during 1993 of properties with reserves totaling 16.7 MMBOE partially offset by additions. 32 33 The following table sets forth as of December 31, 1993 the Company's estimated proved reserves and the discounted net present value thereof in each of the Company's principal operating areas.
NATURAL OIL PRE-TAX OIL GAS EQUIVALENT PV1O(a) OPERATING REGION (MMBBLS) (MMCF) (MMBOE) (IN MILLIONS) - ------------------------------------------- -------- ------- ---------- ------------- Permian Basin.............................. 41.6 45.8 49.2 $ 128.1 Offshore Gulf of Mexico.................... 3.8 103.8 21.1 169.8 San Joaquin Valley......................... 183.6 11.8 185.6 167.1 Other Domestic............................. 1.9 74.5 14.3 78.2 International.............................. 17.3 27.1 21.8 24.6 -------- ------- ---------- ------------- Total.................................... 248.2 263.0 292.0 $ 567.8 -------- ------- ---------- ------------- -------- ------- ---------- -------------
- --------------- (a) Represents the net present value (discounted at 10%) of the pre-tax future net cash flows estimated to result from production of the Company's estimated proved reserves using estimated sales prices and estimates of production costs, ad valorem and production taxes and future development costs necessary to produce such reserves. The sales prices used in the determination of proved reserves and of estimated future net cash flows are based on the prices in effect at year end, and for 1993 averaged $9.27 per barrel for oil and $2.17 per Mcf for natural gas. The average sales price (unhedged) realized by the Company for its production during 1993 was $12.93 per barrel for oil and $2.03 per Mcf for natural gas. Ryder Scott Company ("Ryder Scott"), a firm of independent petroleum engineers, prepared the above estimates of the Company's total proved reserves as of December 31, 1990 through 1993. During 1993 the Company filed Energy Information Administration Form 23 which reported natural gas and oil reserves for the year 1992. On an equivalent barrel basis, the reserve estimates for the year 1992 contained in such report and those reported herein for the year 1992 do not differ by more than five percent. DOMESTIC DEVELOPMENT ACTIVITIES The Company is engaged in development activities primarily through the application of thermal enhanced recovery techniques to its heavy oil properties in the San Joaquin Valley, the use of secondary waterfloods and tertiary CO2 floods on its properties in other mature fields and the development of producing properties acquired by the Company through its exploration successes and its acquisition program. Thermal EOR operations involve the injection of steam into a reservoir to raise the temperature and reduce the viscosity of the heavy oil, facilitating the flow of the oil into producing wellbores. The Company has operated thermal EOR projects in the San Joaquin Valley since the mid-1960s. Similarly, the Company has extensive experience in the use of waterfloods, which involve the injection of water into a reservoir to drive hydrocarbons into producing wellbores. The Company has an interest in more than 50 waterflood projects, and additional projects are planned for the future. Following the waterflood phase, certain fields may continue to produce in response to tertiary EOR projects, such as the injection of CO2 which mixes miscibly with the oil and improves the displacement efficiency of the water injection. The Company's principal CO2 floods are in the Wasson field and are operated by affiliates of Shell Oil Company, ARCO and Amoco. Set forth below is a discussion of some of the Company's principal development projects. The Company has operated in the Midway-Sunset and Wasson fields since 1905 and 1939, respectively. The Company acquired interests in the South Belridge field from Petro-Lewis in 1987 and in January 1991 expanded its holdings in the field with the purchase of certain properties from Mission Operating Partnership, L.P. The Company's interests in the Kern River and Coalinga fields were acquired in 1905 and 1977, respectively. The Gulf of Mexico fields were discovered on leases held by the Company or 33 34 acquired in the Adobe Merger, while the Delaware and Cisco-Canyon properties were acquired as undeveloped properties. SAN JOAQUIN VALLEY Midway-Sunset. The Company owns a 100% working interest (92% average net revenue interest) in over 10,000 gross acres and 2,200 active wells in the Midway-Sunset field. Substantially all the oil produced from the Midway-Sunset field is heavy crude oil produced principally by cyclic steam and steamflood operations from Pleistocene and Miocene reservoirs at depths less than 2,000 feet. These steam stimulation operations were initiated in the field in the mid-1960s. During 1993 the Midway-Sunset field accounted for approximately 50% of the Company's domestic crude oil and liquids production. At December 31, 1993 the Midway-Sunset field accounted for approximately 69% of the Company's domestic proved crude oil and liquid reserves. Reservoir engineering studies prepared on behalf of the Company indicate significant additions to its proved reserves in this field can continue to be made through additional EOR and development projects. The Company has identified a substantial number of locations that could be drilled in the field, depending in part on future prices and economic conditions. The Company is pursuing electrical cogeneration opportunities which could lower Midway-Sunset operating costs. South Belridge. The South Belridge field is located approximately 15 miles north of the Midway-Sunset field. The Company operates three leases in the field which produce heavy oil from the shallow Tulare sands and lighter low viscosity oil from the deeper Diatomite reservoirs. Steamflood operations in the lower Tulare sands are in progress on one of these leases and plans call for flooding the remaining Tulare sands on this lease and all Tulare sands on another lease in the coming years. Waterflood operations in the Diatomite reservoir have been initiated on two leases and the Company expects to expand these operations to include the rest of the developed area. Coalinga. The Coalinga field is located 55 miles southwest of Fresno, California. Successful steamfloods and a pilot steamflood project have been conducted in the Lower Temblor Sands on three of the six leases in which the Company owns interests in the field. During the next several years, the Company plans to expand the pilot steamflood project in the lower sands to cover the remaining producing area and expand steamfloods on the Upper Temblor Sands on all leases after depletion of the lower zones. Most of the facilities required for these projects are already in place as a result of the prior steamfloods. Kern River. The Kern River field is located near Bakersfield, California. The Lower Kern River Series sands have been successfully steamflooded on three of the leases in which the Company owns an interest. Over the next several years steamflood operations will be sequentially redeployed in the upper sands of the Kern River Series. Eventually the Company plans to flood all sands on its remaining leases in several stages. The Company has installed and operates a large steam generation plant on these properties. PERMIAN BASIN Wasson. The Company's interests in the Wasson field principally consist of royalty and working interests in three units which are presently under CO2 flood. Most of the expenditures for plant, facilities, wells and equipment necessary for such tertiary recovery projects have been made. In addition, while expenditures relating to the purchase of CO2 for the Wasson field are expected to continue, CO2 can be recycled and, therefore, such expenditures should decline in the future. During 1993, the Wasson field accounted for approximately 9% of the Company's domestic crude oil and liquids production and at December 31, 1993 the field accounted for approximately 8% of the Company's domestic proved crude oil and liquids reserves. Since initiation of CO2 flooding operations in 1984, the field's previous production decline has been reversed. Reservoir engineering studies prepared 34 35 on behalf of the Company indicate significant additions to proved reserves can be made through additional EOR and development projects. Reeves. The Company owns a 72% net interest in the Reeves field, seven miles east of the large Wasson field in west Texas. The field has been under waterflood since 1965. During 1993, six wells were drilled and 16 wells were worked over as part of a program to delineate the extended productive limits of the field, to evaluate the potential for infill drilling and to enhance current waterflood operations. Based on the successes of the prior year's program, the Company plans to initiate an infill drilling and workover program in this field in the near future. New Mexico. During 1993, the Company increased its activity in the light-oil Delaware prospect in Lea and Eddy Counties of southeast New Mexico. A total of 51 gross (18.1 net) development wells were completed in 1993 with a 100% success rate and during December 1993 such wells produced approximately 1.4 MBbls of oil per day and 3.1 MMcf of natural gas per day. Net production from this area during December 1993 totaled approximately 1.5 MBbls of oil per day and 4.0 MMcf of natural gas per day. The Company has plans to drill additional development wells in 1994. Also in southeastern New Mexico, the Company participated in five gross (2.8 net) wells in 1993 in the light oil and gas Cisco-Canyon project. Four wells were completed as producers from the Cisco-Canyon zone by year-end and a fifth continued production testing. The Company plans to continue delineation of this play which contains some 75 identified potential development locations. OFFSHORE GULF OF MEXICO At December 31, 1993, offshore Gulf of Mexico properties accounted for 39% of the Company's proved natural gas reserves and during 1993 these properties accounted for approximately 56% of the Company's natural gas production. In the Gulf Division, several new fields or field additions were placed on production during 1993. Net production from these fields at year-end averaged approximately 29.0 MMcf of gas per day. Further development in these fields is either planned or under study for 1994 and 1995. The Company's activities in the offshore Gulf of Mexico are conducted in shallow water (less than 300 feet), where the costs of drilling, completion and production are not as uncertain as are the costs in the Flextrend and Deepwater areas of the Gulf of Mexico. During 1993, the Company participated in the drilling of four gross (1.3 net) exploratory wells and one gross (0.3 net) well was drilling at year-end (which well resulted in a discovery and a multi-well development program is expected to commence in 1994). For a description of the Company's leasehold position in the offshore Gulf of Mexico, see "--Domestic Exploration Activities." DOMESTIC EXPLORATION ACTIVITIES The Company's domestic exploration focus continues to be in the Permian Basin and the offshore Gulf of Mexico. Overall the Company participated in 22 gross (9.0 net) exploratory wells in 1993. A total of ten gross (3.6 net) were completed as producers for a 40% net well success. At year end there were nine gross (4.3 net) wells in some stage of drilling or completion. As of December 31, 1993, the Company held approximately 0.3 million net undeveloped leasehold acres in 14 states and offshore areas, excluding approximately 0.5 million net undeveloped leasehold acres sold to Bridge in April 1994. The primary terms of lease expire with respect to 24% of such acreage in 1994, 25% in 1995, 15% in 1996, 10% in 1997 and the remainder thereafter. In addition, the Company owns approximately 0.5 million net acres of undeveloped fee minerals in Louisiana, Texas and California. The Company also controls the oil and gas rights on approximately 8.1 million net undeveloped acres in the western United States through direct ownership and pursuant to lease option agreements from Santa Fe Pacific Railroad Company and other former affiliates. These lands are located in high risk exploration areas. Due to this risk, the Company has historically negotiated with third parties to explore this acreage with the Company to receive a royalty or carried interest in the exploration phase. An agreement relating to substantially all of these oil and gas rights has been entered into with Bridge. This 35 36 agreement is intended to provide incentive to Bridge to accelerate exploration activities on lands subject to these rights. The Company will receive a small revenue interest in the event such activities are successful. Set forth below is a brief discussion of some of the Company's principal exploration programs. Permian Basin. This area continues to be one of the Company's most active and successful exploration areas. During 1993, the Company participated in 18 gross (7.7 net) exploratory wells. Eight gross (3.3 net) of these were completed in 1993 as oil or gas discoveries. Additionally, eight gross (4.0 net) were in some phase of drilling or completing at year-end. Drilling objectives for the Company's exploratory program target oil and gas zones at depths of between 2,500 to 15,000 feet. The shallower targets such as the Delaware and Cisco-Canyon formations are providing successful results. The Delaware program in southeast New Mexico was the subject of seven gross (3.7 net) exploratory and 51 gross (18.1 net) development wells completed in 1993. A success rate of 58% of the net exploratory wells and 100% of the net development wells was achieved in this increasingly active light oil play. Currently, the Company has identified in excess of 150 development well locations and has 20 exploratory prospects in inventory to be drilled over the next several years. In the west Texas Permian Basin, the Company completed the shooting of 3-D seismic over its 250-square mile block near Midland last fall. The joint venture block contains over 100,000 net acres of lands owned or controlled by the Company and its partners. Almost all of the Company's 25% interest in the 3-D seismic was paid by a promoted partner. Drilling began in December 1993 on two prospects identified in this program. Additional drilling is planned on a variety of other prospects in 1994 at depths of 10,000 to 12,000 feet. Offshore Gulf of Mexico. The Company participated in four gross (1.3 net) exploratory wells in the offshore Gulf of Mexico in 1993 and one gross (0.3 net) was drilling at year-end. One gross (0.3 net) well resulted in a discovery on which a multi-well development program will commence in the first quarter of 1994. The Company acquired 3-D seismic coverage over 12 blocks during 1993 adding to its extensive Gulf of Mexico seismic database which includes 3-D coverage on 57 blocks. Currently, the Company has 35 exploratory prospects in inventory and some 30 development locations identified, a portion of which are exploratory and planned to be drilled in 1994. At year-end, the Company owned 179 blocks of acreage in the offshore Gulf of Mexico consisting of approximately 299,800 gross (147,400 net) undeveloped acres and 257,900 gross (79,000 net) developed acres. INTERNATIONAL DEVELOPMENT ACTIVITIES Indonesia. The Company, through a wholly owned subsidiary, is engaged in the production of crude oil in Indonesia through a joint venture (the "Salawati Basin Joint Venture") formed in 1970 to explore for and develop hydrocarbon reserves in the Salawati Basin area of Irian Jaya. At December 31, 1993, the Company held a 33 1/3% participation interest in, and acts as operator for, the Salawati Basin Joint Venture. The Salawati Basin Joint Venture operates under a production sharing contract (the "PSC") with the Indonesia state oil agency ("Pertamina"), which had an initial term of 30 years and expires in the year 2000. The Company is currently negotiating with such state oil agency to extend the contract for an additional 20 years. As of December 31, 1993, the contract covered an area of approximately 235,000 acres. Production occurs from seven oil and three gas condensate fields. The PSC entitles the Salawati Basin Joint Venture to recover all of its expenditures related to the operation (the "cost recovery amount") before any additional production is shared with the Indonesian state oil agency, which recovery is effected by allocating to the Salawati Basin Joint Venture a portion of the crude oil production sufficient, at the Indonesian government official crude oil price ("ICP"), to offset the cost recovery amount. The balance of production after the cost recovery amount is divided between 36 37 the parties, with approximately 66% allocated to Pertamina and 34% allocated to the Salawati Basin Joint Venture. However, 25% of the 34% pre-tax portion (8.5% of total production) must be sold into the Indonesian domestic market for $0.20 per barrel. The entire entitlement of the Salawati Basin Joint Venture under the PSC, including the domestic market obligation, averaged approximately 10.1 MBbls per day (approximately 3.4 MBbls per day net to the Company) for the year ended December 31, 1993. The Salawati Basin Joint Venture is required to pay Indonesian income taxes at the rate of 56%. The Company, through another subsidiary, has also entered into a joint venture with Pertamina to explore the Salawati Island Block of Irian Jaya. The effective date of this joint venture is April 23, 1990 with a term of 30 years. At December 31, 1993, the Company held a 16 2/3% participation interest in the block which covers 1.09 million acres. The Company and Pertamina (with its 50% interest) jointly operate the contract area. In 1991, a successful exploratory well tested at a combined rate of 3.6 MBbls of oil per day and was followed by two successful delineation wells. Pertamina declared the field commercial in January 1993 and designated it as the Matoa field. Sales of production began in January 1993. Development activities through 1993 have the Matoa field producing approximately 5.6 MBbls of oil per day from eight wells as of December 31, 1993. Under the terms of the PSC, the joint venture participants are allowed to recover the cost recovery amount, after an initial 20% portion (2.9% to the joint venture participants and 17.1% to Pertamina) has been deducted, by allocating to the joint venture participants a portion of the crude oil production ("cost oil") sufficient to offset the cost recovery amount. All unrecovered costs in any calendar year can be carried forward to future years. The balance of production after allocation of cost oil is allocated approximately 85.5% to Pertamina and 14.5% to the other Salawati Island Venture participants. However, 7.25% of the gross production allocated to the joint venture participants must be sold into the Indonesian domestic market for 10% of ICP. Argentina. In 1991, the Company, through a wholly owned subsidiary, acquired an 18% non-operated working interest (15.84% net interest) in the El Tordillo field in Chubut Province, Argentina. At that time, the field was producing approximately 10,500 barrels of oil per day. The Company has agreed to spend approximately $16.7 million net during the period from July 1, 1992 to July 1, 1996 on development and maintenance of the field which began with an extensive workover and recompletion program. As of December 31, 1993 the El Tordillo owners have completed 163 such workovers and drilled three new wells. During that time, production increased to approximately 16.0 MBbls of oil per day. The Company expects this program to continue through 1994 and anticipates an expansion of the existing waterflood facilities. Under the terms of the contract with the Argentine national oil company, the joint venture group is allowed to sell crude oil produced from this field into the open market. There is a 12% royalty on gross production and the joint venture is taxed at a 30% rate after deductions for capitalized costs and expenses. In April 1993, the Company's subsidiary completed the Sierra Chata X-1 as a successful exploratory test in Chihuidos Block, Neuquen Province, Argentina. The well produced at a combined rate of 22.2 MMcf per day and 109 barrels of condensate per day. Carbon dioxide content of the natural gas was 6%. Five successful delineation wells were drilled in 1993. Producing rates on these wells varied from 3.2 MMcf to 27.6 MMcf per day. Engineering and geological studies are presently being undertaken to develop the field through additional drilling, with 4.0 gross (1.0 net) additional wells currently planned for 1994. In addition, the Company and its partners intend to build a gas processing facility and a 40-mile gathering pipeline during 1994 that will transport production from the field and interconnect with a main transmission line owned by a third party that transports gas to Buenos Aires and other major markets. Construction of the gas processing facility and the pipeline and the drilling of the development wells are estimated to cost an aggregate of $76.0 million gross ($17.2 million net to the Company's interest). The Company expects that sales of production from the Sierra Chata discovery will commence in 1995. 37 38 INTERNATIONAL EXPLORATION ACTIVITIES In 1993, the Company had its most active year ever in the international arena. The Company participated in six gross (1.8 net) exploratory wells of which two gross (0.5 net) were completed as natural gas wells. Additionally, four gross (1.2 net) wells were either drilling or completing at year-end. The Company made one exploration discovery in 1993. The Sierra Chata natural gas discovery in the Neuquen Basin of Argentina is being developed from sandstone reservoirs at 6,000 feet. The Company has a 22.5% working interest (20% net revenue interest) and is operator of this field. To date a total of six gross (1.3 net) wells have been drilled with no dry holes. Combined gross flow rates from these six wells are in excess of 100 MMcf of gas and 500 barrels of condensate per day. Additional development drilling will continue during 1994 to increase production capacity and further define the limits of the field. See "--International Development Activities." The Company plans to drill eight gross (2.8 net) wells in 1994 in addition to the four gross (1.2 net) wells which carried over from 1993 in either a drilling or completing status. The 1994 drilling and exploratory activity will be centered principally in Indonesia and South America. Of the total wells to be completed in 1994, four gross (1.2 net) are in Indonesia, four gross (1.3 net) are in Argentina and Bolivia, one gross (0.2 net) is in Papua New Guinea, two gross (1.0 net) are in Canada and one gross (0.3 net) is in Gabon (West Africa). The Company holds exploration contracts totaling 3.5 million net acres in eight foreign countries. The majority of acreage is in Indonesia (1.1 million net acres) and South America (1.2 million net acres) with the balance in Canada, Morocco, Myanmar, Papua New Guinea and Gabon. DRILLING ACTIVITIES The table below sets forth, for the periods indicated, the number of wells drilled in which the Company had an economic interest. As of December 31, 1993, the Company was in the process of drilling or completing 9 gross (4.3 net) domestic exploratory wells and 13 gross (5.3 net) domestic development wells, 4 gross (1.2 net) foreign exploratory wells and 3 gross (1.0 net) foreign development wells.
YEAR ENDED DECEMBER 31, -------------------------------------------------------- 1993 1992 1991 ---------------- -------------- ---------------- GROSS NET GROSS NET GROSS NET ----- ------ ----- ---- ----- ------ Development Wells Domestic Completed as natural gas wells......... 21 6.0 6 1.5 25 7.5 Completed as oil wells................. 237 180.0 62 39.0 220 167.3 Dry holes.............................. 10 3.6 5 0.4 6 1.6 Foreign Completed as natural gas wells......... 4 1.0 -- -- -- -- Completed as oil wells................. 3 0.9 -- -- -- -- ----- ------ ----- ---- ----- ------ 275 191.5 73 40.9 251 176.4 ----- ------ ----- ---- ----- ------ Exploratory Wells Domestic Completed as natural gas wells......... 3 0.9 1 0.3 6 2.0 Completed as oil wells................. 7 2.7 4 1.2 6 1.9 Dry holes.............................. 12 5.4 2 0.6 19 7.2 Foreign Completed as natural gas wells......... 2 0.4 -- -- -- -- Completed as oil wells................. -- -- 1 0.3 -- -- Dry holes.............................. 4 1.3 4 1.3 3 0.4 ----- ------ ----- ---- ----- ------ 28 10.7 12 3.7 34 11.5 ----- ------ ----- ---- ----- ------ 303 202.2 85 44.6 285 187.9 ----- ------ ----- ---- ----- ------ ----- ------ ----- ---- ----- ------
38 39 DOMESTIC ACREAGE The following table summarizes the Company's developed and undeveloped fee and leasehold acreage in the United States at December 31, 1993. Excluded from such information is acreage in which the Company's interest is limited to royalty, overriding royalty and other similar interests.
UNDEVELOPED DEVELOPED --------------------- --------------------- GROSS NET GROSS NET -------- -------- -------- -------- Alabama--Offshore................................ -- -- 23,040 12,480 Alabama--Onshore................................. 3,089 108 6,063 382 Arkansas......................................... 633 493 4,177 3,173 California--Offshore............................. -- -- 17,280 2,074 California--Onshore.............................. 249,207 248,990 7,391 7,011 Colorado......................................... -- -- 6,368 5,657 Illinois......................................... 202 50 43 13 Kansas........................................... 19,433 19,373 4,591 1,002 Louisiana--Offshore.............................. 222,376 116,843 190,675 57,721 Louisiana--Onshore............................... 17,575 16,620 14,635 2,941 Michigan......................................... -- - 71 11 Mississippi...................................... 114 30 3,724 810 Montana.......................................... -- -- 3,196 142 Nevada........................................... 3,491 764 9,455 9,455 New Mexico....................................... 195,750 155,594 41,427 18,852 New York......................................... -- -- 189 47 North Dakota..................................... 1,509 544 4,337 1,377 Oklahoma......................................... 1,917 1,917 29,589 9,940 Texas--Offshore.................................. 77,397 30,545 67,194 21,243 Texas--Onshore................................... 180,828 174,912 246,287 168,421 Utah............................................. 1,348 575 8,389 3,494 Wyoming.......................................... 13,785 10,804 25,888 11,312 -------- -------- -------- -------- 988,654 778,162 714,009 337,558 -------- -------- -------- -------- -------- -------- -------- --------
The foregoing table excludes approximately 2,033,400 gross (1,682,000 net) undeveloped fee and leasehold acres and 80,200 gross (45,900 net) developed acres sold to Bridge in April 1994 pursuant to a purchase agreement signed in December 1993 and 123,000 gross (123,000 net) undeveloped acres sold in January 1994. FOREIGN ACREAGE The following table summarizes the Company's foreign acreage at December 31, 1993:
UNDEVELOPED DEVELOPED ------------------------- ------------------- GROSS NET GROSS NET ----------- --------- ------- ------- Argentina...................................... 2,103,010 550,457 53,988 10,858 Bolivia........................................ 1,442,446 649,100 -- -- Canada (Alberta)............................... 150,703 68,071 -- -- Gabon.......................................... 701,000 175,250 -- -- Indonesia...................................... 4,439,569 1,059,193 9,360 2,870 Morocco........................................ 1,300,000 422,500 -- -- Myanmar........................................ 394,000 315,200 -- -- Papua New Guinea............................... 1,970,000 295,500 -- -- ----------- --------- ------- ------- 12,500,728 3,535,271 63,348 13,728 ----------- --------- ------- ------- ----------- --------- ------- -------
39 40 CURRENT MARKETS FOR OIL AND GAS The revenues generated by the Company's operations are highly dependent upon the prices of, and demand for, oil and gas. For the last several years, prices of these products have reflected a worldwide surplus of supply over demand. The price received by the Company for its crude oil and natural gas depends upon numerous factors beyond the Company's control, including economic conditions in the United States and elsewhere and the world political situation as it affects OPEC, the Middle East (including the current embargo of Iraqi crude oil from worldwide markets) and other producing countries, the actions of OPEC and governmental regulation. The fluctuation in world oil prices continues to reflect market uncertainty regarding OPEC's ability to control member country production and underlying concern about the balance of world demand for and supply of oil and natural gas. Decreases in the prices of oil and gas have had, and could have in the future, an adverse effect on the Company's development and exploration programs, proved reserves, revenues, profitability, cash flow and dividend levels. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--General." The Company believes the market for heavy crude oil produced in California differs substantially from the remainder of the domestic crude oil market. It is necessary to heat or dilute heavy oil to make it flow, which increases transportation and handling costs, and it is also more costly to refine. As a result, the price paid for heavy crude oil is generally lower than the price paid for light crudes. In addition, there is currently an oversupply of crude oil in the California market that has had an adverse effect on the prices for crude oil in that market. Although no assurance can be given, the Company believes that such oversupply will not continue for the long term due to the availability of crude oil pipelines to transport excess crude oils, including blended oils, to markets in the Midwest and west Texas, and due to the decline of crude oil produced from the North Slope of Alaska. From time to time the Company has hedged a portion of its oil and natural gas production to manage its exposure to volatility in prices of oil and natural gas. The Company used several instruments whereby monthly settlements were based on the difference between the price, or a range of prices, specified in the instruments and the monthly average of the daily settlement prices of certain WTI crude oil futures contracts or of certain natural gas futures contracts quoted on the New York Mercantile Exchange. In instances where the actual average of the daily settlement price was less than the price specified in the contract, the Company received a settlement based on the difference; in instances where the actual average of the daily settlement price was higher than the specified price, the Company paid an amount based on the difference. The instruments utilized by the Company differed from futures contracts in that there was no contractual obligation which required or allowed for the future delivery of the product. Settlements were included in revenues in the period in which the oil and natural gas were sold. In 1990, oil hedges resulted in a $10.7 million reduction in oil revenues and in 1991 and 1992 oil hedges resulted in an increase in oil revenues of $41.7 million and $9.7 million, respectively. The Company has had no oil hedging contracts subsequent to 1992. In 1992 and 1993, natural gas hedges resulted in a reduction in natural gas revenues of $0.5 million and $8.2 million, respectively. The Company currently has open natural gas hedging contracts covering an aggregate of approximately 6.0 Bcf of natural gas during the period March through September 1994. The "approximate break-even price" (the average of the monthly settlement prices of the applicable futures contracts which would result in no settlement being due to or from the Company) with respect to such contracts is approximately $1.89 per Mcf. The Company has no other outstanding natural gas hedging instruments. During 1993, affiliates of Shell Oil Company and Celeron Corporation accounted for approximately 23% and 15%, respectively, of the Company's domestic crude oil and liquids and natural gas revenues. No other individual customer accounted for more than 10% of such revenues during 1993. Substantially all of the Company's oil and natural gas production is currently sold at market-responsive prices that approximate spot prices. Availability of a ready market for the Company's oil and gas production depends on numerous factors, including the level of consumer demand, the extent of worldwide oil production, the cost and availability of alternative fuels, the cost of and proximity of pipelines and other transportation 40 41 facilities, regulation by state and federal authorities and the cost of complying with applicable environmental regulations. In December 1993, the Company signed a seven-year gas sales contract with Hadson pursuant to the terms of which Hadson will market substantially all of the Company's domestic natural gas production. Pursuant to such gas contract, Santa Fe dedicated to Hadson all of its domestic natural gas production from specified existing wells, which consist of essentially all of the Company's domestic natural gas production, except to the extent such production was dedicated under pre-existing contracts. Upon the expiration of any such pre-existing contracts, that production shall also be dedicated to Hadson. In addition to production from existing wells, such gas contract provides for the dedication by the Company of gas production from certain domestic development wells and exploration wells to the extent that the Company accepts proposals from Hadson to gather and market production from such exploration wells. Production from gas wells acquired by the Company pursuant to an acquisition of producing oil and gas properties will not be dedicated under the gas contract but may be dedicated by the mutual agreement of the Company and Hadson. Pursuant to the gas contract, Hadson will be required to pay the Company for all production delivered at a price for such gas equal to stipulated published monthly index prices. Hadson is obligated to use its best efforts to receive gas from the Company at delivery points so as to maximize the net price received by the Company for such production. Payment for purchases by Hadson are to be made in immediately available funds no later than the last working day of the month following the month of production. SANTA FE ENERGY TRUST In November 1992, 5,725,000 Depositary Units, each consisting of beneficial ownership of one unit of undivided interest in the Trust and a $20 face amount beneficial ownership interest in a $1,000 face amount zero-coupon United States Treasury obligation maturing on February 15, 2008, were sold in a public offering. The assets of the Trust consist of certain oil and gas properties conveyed by the Company. A total of $114.5 million was received from public investors, of which $38.7 million was used to purchase the Treasury obligations and $5.7 million was used to pay underwriting commissions and discounts. The Company received the remaining $70.1 million of proceeds and retained 575,000 Depositary Units. A portion of the proceeds received by the Company was used to retire $30.0 million of the debt incurred in connection with the Adobe Merger and the remainder was used for general corporate purposes. In the first quarter of 1994, the Company sold the remaining 575,000 Depositary Units it held for $11.3 million. The properties conveyed to the Trust consisted of two term royalty interests in two production units in the Wasson field in west Texas and a net profits royalty interest in certain royalty and working interests in a diversified portfolio of properties located in 12 states. At December 31, 1993, 5.2 MMBOE of the Company's estimated proved reserves were subject to such net profits interest. The reserve estimates included herein reflect the conveyance of the Wasson term royalties to the Trust. For any calendar quarter ending on or prior to December 31, 2002, the Trust will receive additional royalty payments to the extent that such payments are required to provide distributions of $0.40 per Depositary Unit per quarter. Such additional royalty payments, if needed, will come from the Company's remaining royalty interest in one of the production units in the Wasson field described above, and are non-recourse to the Company. If such additional payments are made, certain proceeds otherwise payable to the Trust in subsequent quarters may be reduced to recoup the amount of such additional payments. The aggregate amount of the additional royalty payments (net of any amounts recouped) are limited to $20.0 million on a revolving basis. The Company was required to make an additional royalty payments of $362,000 and $505,700 with respect to the distributions made by the Trust for operations during the quarters ended December 31, 1993 and March 31, 1994, respectively. 41 42 OTHER BUSINESS MATTERS Competition The Company faces competition in all aspects of its business, including, but not limited to, acquiring reserves, leases, licenses and concessions; obtaining goods, services and labor needed to conduct its operations and manage the Company; and marketing its oil and gas. The Company's competitors include multinational energy companies, government-owned oil and gas companies, other independent producers and individual producers and operators. The Company believes that its competitive position is affected by price, its geological and geophysical capabilities and ready access to markets for production. Many competitors have greater financial and other resources than the Company, more favorable exploration prospects and ready access to more favorable markets for their production. The Company believes that the well-defined nature of the reservoirs in its long-lived oil fields, its expertise in EOR methods in these fields, its active development and exploration position and its experienced management may give it a competitive advantage over some other producers. Regulation of Crude Oil and Natural Gas The petroleum industry is subject to various types of regulation throughout the world, including regulation in the United States by state and federal agencies. Domestic legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations binding on the oil and gas industry and its individual members, compliance with which is often difficult and costly and which may carry substantial penalties for non-compliance. Although the regulatory burden on the oil and gas industry increases the cost of doing business and, consequently, affects profitability, generally these burdens do not appear to affect the Company any differently or to any greater or lesser extent than other companies in the industry with similar types and quantities of production. While the Company is a party to several regulatory proceedings before governmental agencies arising in the ordinary course of business, management does not believe that the outcome of such proceedings will have a material adverse affect on the operations or financial condition of the Company. Set forth below is a general description of certain state and federal regulations which have an effect on the Company's operations. State Regulation. State statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. Most states in which the Company operates also have statutes and regulations governing the conservation of oil and gas and the prevention of waste, including the unitization or pooling of oil and gas properties and rates of production from oil and gas wells. Rates of production may be regulated through the establishment of maximum daily production allowables on a market demand or conservation basis or both. Federal Regulation. A portion of the Company's oil and gas leases are granted by the federal government and administered by the Bureau of Land Management ("BLM") and the Minerals Management Service ("MMS"), both of which are federal agencies. Such leases are issued through competitive bidding, contain relatively standardized terms and require compliance with detailed BLM and MMS regulations and orders (which are subject to change by the BLM and the MMS). For offshore operations, lessees must obtain MMS approval for exploration plans and development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, Army Corps of Engineers and Environmental Protection Agency), lessees must obtain a permit from the BLM or the MMS prior to the commencement of drilling. The interstate transportation of natural gas is regulated by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 and, to a lesser extent, the Natural Gas Policy Act of 1978 (collectively, the "Acts"). Numerous questions have been raised concerning the interpretation and 42 43 implementation of several significant provisions of the Acts, as well as the regulations and policies promulgated by FERC thereunder. A number of lawsuits and administrative proceedings have been instituted which challenge the validity of regulations implementing the Acts. In addition, as described below, FERC currently has under consideration various policies and proposals which will affect the marketing of gas under new and existing contracts. Since 1991, FERC's regulatory efforts have centered largely around its generic rulemaking proceedings, Order No. 636. Through Order No. 636 and successor orders, FERC has undertaken to restructure the interstate pipeline industry with the goal of providing enhanced access to, and competition among, alternative gas suppliers. By requiring interstate pipelines to "unbundle" their sales services and to provide its customers with direct access to any upstream pipeline capacity held by pipelines, Order No. 636 has enabled pipeline customers to choose the levels of transportation and storage service they require, as well as to purchase gas directly from third-party merchants other than the pipelines. Although the implementation of Order No. 636 on individual interstate pipelines is nearing completion, this process is not yet final. Moreover, nearly all of these individual restructuring proceedings, as well as Order No. 636 itself and the regulations promulgated thereunder, are subject to pending appellate review and could possibly be substantially modified by the courts. Thus, while Order No. 636, if ultimately implemented without substantial change, should generally facilitate the transportation of gas and the direct access to end-user markets, the precise impact of these regulations on marketing production cannot be predicted at this time. Beyond Order No. 636, FERC is now considering a number of other important policies, all of which could significantly affect the marketing of gas. Some of the more notable of these regulatory initiatives include FERC's rulemakings on gathering and production-area rate design, regulation of pipeline marketing affiliates under Order No. 497, and standards for pipeline electronic bulletin boards and electronic data exchange. The U.S. Congress has historically been active in the area of oil and natural gas regulation. Although no prediction can be made concerning future regulation or legislation which may affect the competitive status of the Company, or affect the prices at which it may sell its oil and gas, any regulation or legislation that, directly or indirectly, lowers price levels for oil and gas sold or increases the costs of production could have an adverse effect on the Company's operations. Environmental Regulation Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect the Company's operations and costs. In particular, the Company's oil and gas exploration, development, production and EOR operations, its activities in connection with storage and transportation of liquid hydrocarbons and its use of facilities for treating, processing, recovering or otherwise handling hydrocarbons and wastes therefrom are subject to stringent environmental regulation by governmental authorities. Such regulation has increased the cost of planning, designing, drilling, installing, operating and abandoning the Company's oil and gas wells and other facilities. The Company has expended significant resources, both financial and managerial, to comply with environmental regulations and permitting requirements and anticipates that it will continue to do so in the future in order to comply with stricter industry and regulatory safety standards such as those described below. Although the Company believes that its operations and facilities are in general compliance with applicable environmental regulations, risks of substantial costs and liabilities are inherent in oil and gas operations and there can be no assurance that significant costs and liabilities will not be incurred in the future. Moreover, it is possible that other developments, such as increasingly strict environmental laws, regulations and enforcement policies thereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company's operations, could result in substantial costs and liabilities in the future. Although the resulting costs cannot be accurately estimated at this time, these requirements and risks typically apply 43 44 to companies with types and quantities of production similar to those of the Company and to the oil and gas industry in general. Offshore Production. Offshore oil and gas operations are subject to regulations of the United States Department of the Interior, the Department of Transportation, the United States Environmental Protection Agency ("EPA") and certain state agencies. In particular, the Federal Water Pollution Control Act of 1972, as amended ("FWPCA"), imposes strict controls on the discharge of oil and its derivatives into navigable waters. The FWPCA provides for civil and criminal penalties for any discharges of petroleum in reportable quantities and, along with the Oil Pollution Act of 1990 and similar state laws, imposes substantial liability for the costs of oil removal, remediation and damages. Solid and Hazardous Waste. The Company currently owns or leases, and has in the past owned or leased, numerous properties that have been used for production of oil and gas for many years. Although the Company has utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other solid wastes may have been disposed or released on or under the properties owned or leased by the Company. State and federal laws applicable to oil and gas wastes and properties have gradually become more strict. Under these new laws, the Company has been, and in the future could be, required to remove or remediate previously disposed wastes or property contamination (including groundwater contamination) or to perform remedial plugging operations to prevent future contamination. The Company generates hazardous and nonhazardous wastes that are subject to the federal Resource Conservation and Recovery Act and comparable state statutes. The EPA has limited the disposal options for certain hazardous wastes and has recently issued stricter disposal standards for nonhazardous wastes. Furthermore, it is possible that additional wastes (which could include certain wastes generated by the Company's oil and gas operations) could in the future be designated as "hazardous wastes," which are subject to more rigorous and costly disposal requirements. In response to the changing regulatory environment, the Company has made certain changes in its operations and disposal practices. For example, the Company has commenced remediation of sites or replacement of facilities in some locations where its wastes have previously been disposed. Superfund. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of a site and companies that disposed or arranged for the disposal of the hazardous substance found at a site. CERCLA also authorizes the EPA and, in some cases, third parties to take actions in responses to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In the course of its operations, the Company has generated and will generate wastes that may fall within CERCLA's definition of "hazardous substances." The Company may be responsible under CERCLA for all or part of the costs to clean up sites at which such wastes have been disposed. The Company has been identified as one of over 250 potentially responsible parties ("PRPs") at a superfund site in Los Angeles County, California. The site was operated by a third party as a waste disposal facility from 1948 until 1983. The EPA is requiring the PRPs to undertake remediation of the site in several phases, which include site monitoring and leachate control, gas control and final remediation. In 1989 the EPA and a group of the PRPs entered into a consent decree covering the site monitoring and leachate control phase of remediation. The Company is a member of the group that is responsible for carrying out this first phase of work, which is expected to be completed in five to eight years. The maximum liability of the group, which is joint and several for each member of the group, for the first phase is $37.0 million, of which the Company's share is expected to be approximately $2.4 million ($1.3 million after recoveries from working interest participants in the unit at which the wastes were generated) payable over the period that the phase one work is performed. The EPA and a group of PRPs of which the Company is a member have also entered into a subsequent consent decree with respect to the second phase of work (gas control). The liability of this group has not been capped, but is estimated to be 44 45 $130 million. The Company's share of costs for this phase, however, is expected to be approximately of the same magnitude as that of the first phase because more parties are involved in the settlement. The Company has provided for costs with respect to the first two phases, but it cannot currently estimate the cost of any subsequent phases of work which may be required by the EPA. In 1989, Adobe received requests from the EPA for information pursuant to Section 104(e) of CERCLA with respect to the Gulf Coast Vacuum Services and D. L. Mud superfund sites located in Abbeville, Louisiana. The EPA has issued its record of decision at the Gulf Coast Site and on February 9, 1993 the EPA issued to all PRPs at the site a settlement order pursuant to Section 122 of CERCLA. On December 15, 1993 the Company entered into a cost-sharing agreement with other PRPs to participate in the final remediation of the Gulf Coast site, which is presently estimated to cost $15.0 million. The Company's share of the remediation is approximately $600,000 and reflects its proportionate share of the "orphans' share" for this site. With respect to the D.L. Mud site, a former property owner has already conducted remedial activities at the site under a state agency agreement. To date, the Company has not been requested to share in the remediation costs. The extent, if any, of any further necessary remedial activity at, and the prospective PRPs and the Company's financial obligations for, the D. L. Mud site has not been finally determined. The Company has received a request for information from the EPA regarding the Lee Acres Landfill CERCLA site in New Mexico. The Company advised the EPA that it was not able to locate any information indicating that it had used that facility. The Company is investigating its potential connection, if any, to this facility and is not able to estimate its share of costs, if any, for the site at this time. On April 4, 1994, the Company received a request from the EPA for information pursuant to Section 104(a) of CERCLA and a letter ordering the Company and seven other PRPs to negotiate with the EPA regarding implementation of a remedial plan for a site located in Sante Fe Springs, California. The Company owned the property on which the site is located from 1921 to 1932. After the Company sold the property, hazardous wastes were allegedly disposed there by a third party who operated a disposal site. The EPA estimates that the total past and future costs for remediation will approximate $9 million. The Company believes that it has valid defenses to liability. While it is still investigating its exposure, if any, for the remedial costs, the Company does not believe that any such costs would be material. Air Emissions. The operations of the Company, including its operations in the San Joaquin Valley, are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Legal and regulatory requirements in this area are increasing, and there can be no assurance that significant costs and liabilities will not be incurred in the future as a result of new regulatory developments. In particular, the 1990 Clean Air Act Amendments will impose additional requirements that may affect the Company's operations, including permitting of existing sources and control of hazardous air pollutants. However, it is impossible to predict accurately the effects, if any, of the Clean Air Act Amendments on the Company at this time. The Company has been and may in the future be subject to administrative enforcement actions for failure to comply strictly with air regulations or permits. These administrative actions are generally resolved by payment of a monetary penalty and correction of any identified deficiencies. Alternatively, regulatory agencies may require the Company to forego construction or operation of certain air emission sources. Other. The Company is subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and similar state statutes (such as California Proposition 65) require the Company to organize information about hazardous materials used or produced in its operations. Certain of this information must be provided to employees, state and local governmental authorities and local citizens. The Company's facilities in California are also subject to California Proposition 65, which was adopted in 1986 to address discharges and releases of, or exposures to, toxic chemicals in the environment. Proposition 65 makes it illegal to knowingly discharge a listed chemical if the chemical will pass (or probably will pass) into any source of drinking water. It also prohibits companies from knowingly and intentionally exposing any 45 46 individual to such chemicals through ingestion, inhalation or other exposure pathways without first giving a clear and reasonable warning. Although generally less stringent, the Company's foreign operations are subject to similar foreign laws respecting environmental and worker safety matters. Insurance Coverage Maintained with Respect to Operations The Company maintains insurance policies covering its operations in amounts and areas of coverage normal for a company of its size in the oil and gas exploration and production industry. These coverages include, but are not limited to, workers' compensation, employers' liability, automotive liability and general liability. In addition, an umbrella liability and operator's extra expense policies are maintained. All such insurance is subject to normal deductible levels. The Company does not insure against all risks associated with its business either because insurance is not available or because it has elected not to insure due to prohibitive premium costs. Employees As of December 31, 1993, the Company had approximately 777 employees, 210 of whom were covered by a collective bargaining agreement which expires on January 31, 1996. The Company believes that its relations with its employees are satisfactory. Legal Proceedings The Company, its subsidiaries and other related companies are named defendants in several lawsuits and named parties in certain governmental proceedings arising in the ordinary course of business. For a description of certain proceedings in which the Company is involved, see "--Environmental Regulation." While the outcome of lawsuits or other proceedings against the Company cannot be predicted with certainty, management does not expect these matters to have a material adverse effect on the financial position or results of operations of the Company. 46 47 MANAGEMENT DIRECTORS AND EXECUTIVE OFFICERS The current directors and executive officers of the Company and their ages (as of January 1, 1994) and positions are listed below.
NAME AGE POSITION - --------------------------------- --- ------------------------------------------------- James L. Payne................... 56 Chairman of the Board, President and Chief Executive Officer Hugh L. Boyt..................... 48 Senior Vice President--Production Jerry L. Bridwell................ 50 Senior Vice President--Exploration and Land Keith P. Hensler................. 62 Senior Vice President--Marketing Richard B. Bonneville............ 51 Vice President--Planning and Administration E. Everett Deschner.............. 53 Vice President--Reservoir Engineering and Evaluation C. Ed Hall....................... 51 Vice President--Public Affairs Charles G. Hain, Jr.............. 47 Vice President--Employee Relations David L. Hicks................... 44 Vice President--Law and General Counsel Michael J. Rosinski.............. 48 Vice President and Chief Financial Officer John R. Womack................... 55 Vice President--Business Development Rod F. Dammeyer.................. 53 Director Marc J. Shapiro.................. 47 Director William E. Greehey............... 57 Director Robert F. Vagt................... 47 Director Melvyn N. Klein.................. 52 Director Robert D. Krebs.................. 51 Director David M. Schulte................. 47 Director Allan V. Martini................. 66 Director Michael A. Morphy................ 61 Director Kathryn D. Wriston............... 55 Director Reuben F. Richards............... 64 Director
The business experience of the above officers and directors for the past five years is described below. Unless otherwise stated, all offices were held with Santa Fe Energy Company prior to its merger with the Company. Each executive officer holds office until his successor is elected or appointed or until his earlier death, resignation or removal. James L. Payne has served as a Director since 1986 and has been Chairman of the Board, President and Chief Executive Officer of the Company since June 1990. Mr. Payne was President of Santa Fe Energy Company from January 1986 to January 1990 when he became President of the Company. From 1982 to January 1986 Mr. Payne was Senior Vice President--Exploration and Land of Santa Fe Energy Company. Mr. Payne is also a director of Pool Energy Services Co. (oilfield services) and Hadson (natural gas transportation and marketing). Hugh L. Boyt has been Senior Vice President--Production since March 1, 1990. From 1989 until March 1990, Mr. Boyt served as Corporate Production Manager. From 1983, when Mr. Boyt joined the Company, until 1989 he served as District Production Manager--Permian Basin. Jerry L. Bridwell has been Senior Vice President--Exploration and Land since 1986. Mr. Bridwell served in various other capacities, including Vice President--Exploration, Central Division, since joining the Company in 1974. Keith P. Hensler has been Senior Vice President--Marketing since January 1990. From 1980, when Mr. Hensler joined the Company, until January 1990, he served as Vice President--Marketing. Mr. Hensler is also Senior Vice President of Energy Products. 47 48 Richard B. Bonneville has been Vice President--Planning and Administration since 1988. Prior to such time Mr. Bonneville served as Secretary of Santa Fe Pacific Corporation ("SFP"). E. Everett Deschner has been Vice President--Reservoir Engineering and Evaluation since April 1990. From 1982, when Mr. Deschner joined the Company, until 1990, he served as Manager-- Engineering and Evaluation. C. Ed Hall has been Vice President--Public Affairs since March 1991. Prior to such time Mr. Hall served as Director--Public Affairs since joining the Company in 1984. Charles G. Hain, Jr. has been Vice President--Employee Relations since 1988. From 1981, when Mr. Hain joined the Company, until 1988, Mr. Hain served as Director--Employee Relations. David L. Hicks has been Vice President--Law and General Counsel since March 1991. From 1988 until March 1991, Mr. Hicks was General Counsel and prior to that time was General Attorney for SFP. Michael J. Rosinski has been Vice President and Chief Financial Officer since September 1992. Prior to joining the Company, Mr. Rosinski was with Tenneco Inc. and its subsidiaries for 24 years. From 1988 until 1990, Mr. Rosinski served as Deputy Project Executive for the Colombian Crude Oil Pipeline Project and from 1990 until August 1992 he was Executive Director of Investor Relations. Mr. Rosinski is also a director of Hadson (natural gas transportation and marketing). John R. Womack has been Vice President--Business Development since 1987. From 1982, when Mr. Womack joined the Company, until 1987, Mr. Womack served as Vice President--Land. Rod F. Dammeyer has served as a Director since 1990. Mr. Dammeyer has been President and a director since 1985 and Chief Executive Officer since 1993 of Itel Corporation (holding company involved primarily in distribution of wiring systems products). Mr. Dammeyer is also a director of Q-Tel S.A., Servicios Financieros Quadrum, S.A., Lomas Financial Corporation, Jacor Communications, Inc., Revco D.S., Inc., Capsure Holdings Corp. and the Vigoro Corporation and a trustee of Van Kampen Merritt Closed-End Mutual Funds. In addition, Mr. Dammeyer is President, Chief Executive Officer and a director of Great American Management and Investment, Inc. Marc J. Shapiro has served as a Director since 1990. Mr. Shapiro has been Chairman, President and Chief Executive Officer of Texas Commerce Bancshares, Inc. (banking) since January 1994. He has been President and Chief Executive Officer of Texas Commerce Bancshares, Inc. since December 1989, Chairman and Chief Executive Officer of Texas Commerce Bank National Association since 1987 and a member of the Management Committee of Chemical Banking Corporation since December 1991. Mr. Shapiro was a member of the Office of the Chairman of Chemical Banking Corporation from August 1990 to December 1991, Vice Chairman of Texas Commerce Bancshares, Inc. from 1982 to 1989, and Vice Chairman of Texas Commerce Bank National Association from 1982 to 1987. Mr. Shapiro is also a director of Browning-Ferris Industries and a trustee of Weingarten Realty Investors. William F. Greehey has served as a Director since 1991. Mr. Greehey has been Chairman of the Board, Chief Executive Officer and director of Valero Energy Corporation (refining and marketing, gas transmission and processing) since 1983. Mr. Greehey is also a director of Weatherford International. Robert F. Vagt has served as a Director since 1992. Mr. Vagt has been President, Chief Executive Officer and director of Global Natural Resources Inc. (oil and gas exploration and production) since May 1992; President and Chief Operating Officer of Adobe (oil and gas exploration and production) from November 1990 to May 1992; Executive Vice President of Adobe from August 1987 to October 1990; and Senior Vice President of Adobe from October 1985 to August 1987. Mr. Vagt is also a director of First Albany Corporation (brokerage firm). Melvyn N. Klein has served as a Director since February 1993, when he was elected to fill the vacancy created by the resignation of L.G. Dodd. Mr. Klein is an Attorney and Counselor at Law, private investor and the sole stockholder of a general partner in GKH Partners, L.P. Mr. Klein is also a director of Itel Corporation, American Medical Holdings, Inc. (hospital ownership and management), Bayou Steel 48 49 Corporation (specialty steel manufacturer) and Savoy Pictures Entertainment, Inc. (distributor of motion pictures). Robert D. Krebs has served as a Director since 1985. Mr. Krebs has been Chairman, President and Chief Executive Officer of SFP since 1988. Prior to such time, Mr. Krebs was President and Chief Operating Officer of SFP. Mr. Krebs is also a director of SFP, Catellus Development Corporation, the Atchison, Topeka and Santa Fe Railway Company, Santa Fe Pacific Pipelines, Inc., Phelps Dodge Corporation and Northern Trust Corporation. David M. Schulte has served as a Director since February 1994. Mr. Schulte has been, for the past five years, Managing Partner of Chilmark Partners, L.P. (investments) and since July 1990, General Partner of ZC Limited Partnership, the General Partner of Zell/Chilmark Fund, L.P. (investments). Mr. Schulte is also a director of Carter Hawley Hale Stores, Inc., Revco D.S., Inc., Sealy Corporation and Jacor Communications, Inc. Allan V. Martini has served as a Director since 1990. Mr. Martini retired as Vice President Exploration/Production and director of Chevron Corporation (petroleum operations) in August 1988. Mr. Martini served in that position from July 1986 until his retirement. Michael A. Morphy has served as a Director since 1990. Mr. Morphy has been, for the past five years, retired Chairman and Chief Executive Officer of California Portland Cement Company. Mr. Morphy is also a director of Cyprus Amax Minerals Co. and SFP. Kathryn D. Wriston has served as a Director since 1990. Ms. Wriston has been, for the past five years, director of various corporations and organizations, including Northwestern Mutual Life Insurance Company and a Trustee of the Financial Accounting Foundation. Reuben F. Richards has served as a Director since 1992. Mr. Richards has been Chairman of the Board of Terra Industries Inc. (agribusiness) since December 1982; Chief Executive Officer of Terra Industries Inc. from December 1982 to May 1991 and President of Terra Industries Inc. from July 1983 to May 1991; Chairman of the Board of Engelhard Corporation (specialty chemicals and engineered materials) since May 1985; Chairman of the Board of Minorco (U.S.A.) Inc. ("Minorco (USA)") since May 1990 and Chief Executive Officer and President of Minorco (USA) since February 1994. Mr. Richards is also a director of Ecolab, Inc. (cleaning and sanitizing products), Potlatch Corporation (forest products), and Minorco. 49 50 DESCRIPTION OF CAPITAL STOCK AUTHORIZED AND OUTSTANDING CAPITAL STOCK At the date hereof, the authorized capital stock of the Company is 250,000,000 shares, consisting of 200,000,000 shares of Common Stock, par value $0.01 per share, and 50,000,000 shares of Preferred Stock, par value $0.01 per share ("Preferred Stock"), of which 5,000,000 have been designated as Convertible Preferred Stock, Series 7%, and of which up to 10,700,000 will be designated as DECS to be issued pursuant to this Offering. The following summary of the Company's Common Stock and Preferred Stock, including the Convertible Preferred Stock, Series 7%, is qualified in its entirety by reference to the Company's Restated Certificate of Incorporation ("Charter"), Bylaws and the Certificate of Designations, Rights and Preferences for the Convertible Preferred Stock, Series 7%, copies of which are included as exhibits to the Registration Statement of which this Prospectus is a part. For a description of the DECS, see "Description of the DECS." COMMON STOCK Restrictions on Dividends The holders of the Company's Common Stock are entitled to dividends in such amounts and at such times as may be declared by the Company's Board of Directors out of funds legally available therefor. Certain of the Company's existing credit agreements restrict the payment of dividends to the holders of Common Stock. The most restrictive of such agreements is the Senior Notes, which contain a dividend restriction that limits aggregate dividends to $45 million plus 100% (or minus 100% in the case of a deficit) of the cumulative consolidated net income of Santa Fe and its subsidiaries from April 1, 1990, subject to other financial conditions. For a description of the aggregate amount that the Company could pay as a dividend on its capital stock, see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." In addition, the terms of the Convertible Preferred Stock, Series 7%, restrict and the terms of the DECS will restrict any dividend payment by the Company to holders of Common Stock unless all dividends on the Convertible Preferred Stock, Series 7%, and the DECS for all past quarterly dividend periods shall have been paid, or declared and a sum sufficient for the payment thereof set apart. At March 31, 1994, under its most restrictive debt covenant the Company had the ability to pay up to $18.4 million in dividends on its outstanding capital stock. After giving effect as of March 31, 1994 to consummation of this Offering and the Concurrent Debenture Offering and the application of the net proceeds thereof as described in "Use of Proceeds," under the Company's most restrictive covenant the Company would have had the ability to pay up to only $50.0 million in dividends on its Common Stock (pursuant to such covenant, dividends on the Convertible Preferred Stock, Series 7%, and the DECS are exempted from, but will reduce, the amount available for the payment of dividends on Common Stock). The amount permitted under these covenants to be used to pay dividends will vary over time depending, among other things, on the Company's earnings and any issuances of capital stock. Other Holders of the Common Stock are entitled to one vote per share for the election of directors and other corporate matters. There are no cumulative voting rights, meaning that the holders of a majority of the shares voting for the election of directors can elect all the directors if they choose to do so. The Company's Board of Directors is divided into three classes, each of which consists of approximately one-third of the total number of directors constituting the Board. Directors are elected to three-year terms, and one class of directors is elected each year. The Company's Bylaws include provisions that establish procedures for director nominations by stockholders and for the presentation by stockholders of matters to be considered at stockholder meetings. In addition, upon the failure to pay dividends on the Convertible Preferred Stock, Series 7%, and, assuming consummation of the offering being made hereby, the DECS for four quarterly dividend periods, 50 51 the number of the Company's directors will be increased by two, and the holders of the Convertible Preferred Stock, Series 7%, and the DECS at the time outstanding, voting together as a class with all other holders of affected classes or series, if any, of Company parity capital stock, upon which like voting rights have been conferred and are exercisable, will be entitled to elect said two directors. See "--Description of Convertible Preferred Stock, Series 7%--Voting Rights." Upon liquidation or dissolution, holders of Common Stock are entitled to share ratably in all net assets available for distribution to stockholders after payment of any liquidation preferences to holders of Convertible Preferred Stock, Series 7%, and, assuming consummation of the Offering being made hereby, holders of the DECS. The Common Stock carries no preemptive rights. All outstanding shares of Common Stock are duly authorized, validly issued, fully-paid and nonassessable. As of March 14, 1994, there were 89,936,650 shares of Common Stock issued and outstanding held by approximately 57,755 shareholders of record. PREFERRED STOCK The Company's Board of Directors is authorized to issue from time to time, without stockholder authorization, in one or more designated series, shares of Preferred Stock with such dividend, redemption, conversion and exchange provisions as are provided in the particular series. As of the date hereof, 5,000,000 shares of Preferred Stock were designated as the Convertible Preferred Stock, Series 7%, all of which were outstanding as of March 1, 1994. The form of the Certificate of Designations, Rights and Preferences for the Convertible Preferred Stock, Series 7%, is included as an exhibit to the Registration Statement of which this Prospectus is a part and the summary of the terms of such shares contained herein is qualified in its entirety by reference thereto and is incorporated herein. In connection with this Offering, the Company's Board of Directors authorized the creation of the DECS. The form of the Certificate of Designations for the DECS is included as an exhibit to the Registration Statement of which this Prospectus is a part and the summary of the terms of such shares contained herein is qualified in its entirety by reference thereto and is incorporated herein. For a description of the terms of the DECS, see "Description of the DECS." TAKEOVER PROVISIONS Section 203 of the Delaware General Corporation Law Section 203 ("Section 203") of the Delaware General Corporation Law ("Delaware Act") restricts certain transactions between a corporation organized under Delaware law (or its majority-owned subsidiaries) and any person holding 15% or more of the corporation's outstanding voting stock, together with the affiliates or associates of such person (an "Interested Stockholder"). Section 203 prevents, for a period of three years following the date that a person becomes an Interested Stockholder, the following types of transactions between the corporation and the Interested Stockholder (unless certain conditions, described below, are met): (a) mergers or consolidations, (b) sales, leases, exchanges or other transfers of 10% or more of the aggregate assets of the corporation, (c) issuances or transfers by the corporation of any stock of the corporation which would have the effect of increasing the Interested Stockholder's proportionate share of the stock of any class or series of the corporation, (d) any other transaction which has the effect of increasing the proportionate share of the stock of any class or series of the corporation which is owned by the Interested Stockholder, and (e) receipt by the Interested Stockholder of the benefit (except proportionately as a stockholder) of loans, advances, guarantees, pledges or other financial benefits provided by the corporation. The three-year ban does not apply if either the proposed transaction or the transaction by which the Interested Stockholder became an Interested Stockholder is approved by the board of directors of the corporation prior to the date such stockholder becomes an Interested Stockholder. Additionally, an Interested Stockholder may avoid the statutory restriction if, upon the consummation of the transaction whereby such stockholder becomes an Interested Stockholder, the stockholder owns at least 85% of the 51 52 outstanding voting stock of the corporation without regard to those shares owned by the corporation's officers and directors or certain employee stock plans. Business combinations are also permitted within the three-year period if approved by the board of directors and authorized at an annual or special meeting of stockholders, by the holders of at least 66 2/3% of the outstanding voting stock not owned by the Interested Stockholder. In addition, any transaction is exempt from the statutory ban if it is proposed at a time when the corporation has proposed, and a majority of certain continuing directors of the corporation have approved, a transaction with a party who is not an Interested Stockholder of the corporation (or who becomes such with board approval) if the proposed transaction involves (a) certain mergers or consolidations involving the corporation, (b) a sale or other transfer of over 50% of the aggregate assets of the corporation, or (c) a tender or exchange offer for 50% or more of the outstanding voting stock of the corporation. Prior to the effective date of Section 203, a corporation, by action of its board of directors, had the option of electing to exclude itself from the coverage of Section 203. Since the effective date of such section, a corporation may, at its option, exclude itself from the coverage of Section 203 by amending its certificate of incorporation or bylaws by action of its shareholders to exempt itself from coverage, provided that such bylaw or charter amendment shall not become effective until 12 months after the date it is adopted. The Company has not adopted such a charter or bylaw amendment. No Action by Written Consent The Charter prohibits the taking of any action by written stockholder consent in lieu of a meeting and the amendment of the Charter to repeal or alter such provision without the affirmative vote of the holders of at least 80% of the voting capital stock of the Company. Rights Plan The Charter provides that the Company may, by action of its Board of Directors, adopt a rights plan. The Company does not currently have a rights plan in effect. The foregoing provisions in the Charter, the existence of authorized but unissued capital stock and the application of Section 203 to stockholders of the Company may tend to deter unfriendly offers or other efforts to obtain control of the Company that are not approved by the Company's Board of Directors and thereby deprive the Company's stockholders of opportunities to sell their shares of Common Stock at prices higher than prevailing market prices. DESCRIPTION OF CONVERTIBLE PREFERRED STOCK, SERIES 7% General The Convertible Preferred Stock, Series 7%, has a liquidation preference of $20 per share plus accrued and unpaid dividends and ranks prior to all shares of the Common Stock as to payment of dividends and as to distributions of assets upon liquidation, dissolution or winding up of the Company. Holders of the Convertible Preferred Stock, Series 7%, have no preemptive rights. The transfer agent for the Convertible Preferred Stock, Series 7%, is First Chicago Trust Company of New York, which also acts as transfer agent and registrar for the Common Stock, whose address is 525 Washington Boulevard, Suite 4690, Jersey City, New Jersey 07310. Dividends Holders of Convertible Preferred Stock, Series 7%, are entitled to receive, prior to the payment of dividends on shares of Common Stock, cumulative cash dividends at an annual rate equivalent to $1.40 per share, when, as and if declared by the Company's Board of Directors out of funds legally available therefor, payable quarterly on March 1, June 1, September 1 and December 1. 52 53 If at any time any dividend on any outstanding shares of capital stock of Santa Fe, which, by the terms of the Charter or of the instrument by which the Company's Board of Directors shall fix, shall be senior to the Convertible Preferred Stock, Series 7%, in respect of the right to receive dividends, then no dividend shall be paid or declared and set apart for payment on the Convertible Preferred Stock, Series 7%, unless and until all accrued and unpaid dividends with respect to such outstanding senior capital stock shall have been paid or declared and a sum sufficient for the payment thereof set apart for payment. No full dividend shall be paid or declared and set apart for payment on the Convertible Preferred Stock, Series 7%, for any dividend period unless full cumulative dividends have been or contemporaneously are paid or declared and a sum sufficient for the payment thereof set apart for such payment on all shares of outstanding Santa Fe capital stock which, by the terms of the Charter or of the instrument by which the Company's Board of Directors shall fix, shall be entitled to share ratably with the Convertible Preferred Stock, Series 7%, in the payment of full dividends, for all dividend periods terminating on or prior to the end of such dividend period. If this Offering is consummated, the DECS will be entitled to share ratably with the Convertible Preferred Stock, Series 7%, in the payment of dividends. When dividends are not paid in full as aforesaid on all shares of such outstanding parity capital stock and the Convertible Preferred Stock, Series 7%, any dividend payments on the Convertible Preferred Stock, Series 7%, including accumulated dividends, if any, will be paid to the holders of the shares of the Convertible Preferred Stock, Series 7%, and any such outstanding parity capital stock (including the DECS) ratably in proportion to the respective sums which such holders would receive if all dividends accumulated thereon to the date of payment were declared and paid in full. Accumulated dividends will not bear interest. So long as any shares of the Convertible Preferred Stock, Series 7%, are outstanding, in no event will any dividends, other than dividends payable solely in shares of junior stock, be paid or declared and set apart for payment, nor will any distribution be made, on any class of stock ranking subordinate to the Convertible Preferred Stock, Series 7%, unless all accrued and unpaid dividends on the Convertible Preferred Stock, Series 7%, for all past quarterly dividend periods shall have been paid, or declared and a sum sufficient for the payment thereof set apart. The amount of dividends payable per share of Convertible Preferred Stock, Series 7%, for each full quarterly dividend period will be computed by dividing the annual dividend rate by four. Voting Rights The holders of Convertible Preferred Stock, Series 7%, will have no voting rights except as set forth below or as otherwise may be required by the Delaware Act. On any matters on which the holders of the Convertible Preferred Stock, Series 7%, will be entitled to vote, they will be entitled to one vote for each share held. If and when four quarterly dividends payable on the Convertible Preferred Stock, Series 7%, or any capital stock of the Company ranking on a parity with the Convertible Preferred Stock, Series 7%, in respect of dividend rights and rights to share in the Company's liquidation upon dissolution or winding up of the Company ("Parity Stock"), whether or not consecutive, shall be unpaid in whole or in part, the number of directors will be increased by two, and the holders of the Convertible Preferred Stock, Series 7%, at the time outstanding, voting separately as a class with all holders of Parity Stock (which will include the DECS) upon which like voting rights have been conferred and are exercisable, will be entitled to elect said two directors. The right to elect said two directors will begin at any meeting of stockholders of the Company at which directors are to be elected held during the period such dividends remain in arrears and will continue until said arrearages in dividends shall have been paid or declared and a sum sufficient for the payment thereof set apart for payment, at which time the right of the holders of shares of the Convertible Preferred Stock, Series 7%, to elect said two directors will cease and the terms of said two directors then in office will expire and terminate. The affirmative vote of the holders of at least two-thirds of the shares of Convertible Preferred Stock, Series 7%, at the time outstanding, voting separately as a class, is necessary to amend, alter or repeal 53 54 any provision of the Certificate of Designations, Rights and Preferences for the Convertible Preferred Stock, Series 7%, so as to affect adversely the relative rights, preferences, qualifications, limitations or restrictions of holders of the Convertible Preferred Stock, Series 7%. Conversion Rights Voluntary Conversion. The holder of any shares of Convertible Preferred Stock, Series 7%, has the right, at its option and at any time, to convert any or all of such shares into Common Stock at the initial rate of 1.3913 shares of Common Stock for each share of Convertible Preferred Stock, Series 7% (subject to adjustments as described below). No payment or adjustment shall be made upon any conversion of any share of Convertible Preferred Stock, Series 7%, on account of any accrued and unpaid dividends on the shares surrendered for conversion prior to the record date for the determination of holders entitled to such dividends or on account of any dividends on the Common Stock issued upon conversion subsequent to the record date established by the Company for the determination of holders of Common Stock entitled to such dividend. Mandatory Conversion. The Company may, at its option and at any time on or after May 19, 1997, during the 10-day period following a "Special Conversion Event" (defined below), convert all outstanding shares of Convertible Preferred Stock, Series 7%, together with all unpaid dividends thereon accrued on a pro rata basis through the date of such conversion, into fully paid and non-assessable shares of Common Stock. A "Special Conversion Event" shall be deemed to have occurred at, and shall be defined as, such time(s) as the average of the daily closing prices for a share of Common Stock for 20 of 30 consecutive trading days equals or exceeds 125% of the quotient of (x) $20.00 divided by (y) the then applicable conversion rate. The number of shares of Common Stock into which each outstanding share of Convertible Preferred Stock, Series 7%, shall be converted shall equal the sum of (i) the then current conversion rate, plus (ii) the number determined by dividing the amount of such accrued and unpaid dividends by a fraction, the numerator of which is $20.00 and the denominator of which is the average of such daily closing prices. No fractional shares of Common Stock will be issued upon conversion but, in lieu thereof, an appropriate amount will be paid in cash by the Company in an amount equal to the same fraction of the market price per share of the Common Stock, as determined by the Company's Board of Directors, on the business day prior to the date of the conversion. The conversion rate of the Convertible Preferred Stock, Series 7%, is subject to adjustment in certain events. No adjustment of the conversion rate will be required to be made until cumulative adjustments amount to 1% or more of the conversion rate as last adjusted; however, any adjustment not made will be carried forward. Special Redemption Right Upon the occurrence of the first Ownership Change (as defined below) of the Company, each holder of shares of Convertible Preferred Stock, Series 7%, will have the right, at the holder's option, at any time within 45 days after notice of such Ownership Change is mailed, to elect to have all of such holder's shares of Convertible Preferred Stock, Series 7%, redeemed for an amount equal to the sum of (x) $20.00 for each share plus (y) accrued and unpaid dividends thereon up to the redemption date. An "Ownership Change" will be deemed to have occurred at, and is defined as, such time as any person or group, together with any affiliates or associates, becomes the beneficial owner of 50% or more of the outstanding Common Stock. Liquidation Preference Subject to the prior rights of the Company's creditors, secured and unsecured, and the prior rights of holders of the Company's capital stock ranking senior to the Convertible Preferred Stock, Series 7%, if any, in the event of any liquidation, dissolution or winding up of the Company, then, before any distribution or payment may be made to the holders of shares of any of the Company's capital stock 54 55 ranking subordinate to the Convertible Preferred Stock, Series 7%, the holders of shares of the Convertible Preferred Stock, Series 7%, will be entitled to be paid in full the respective amount per share of Convertible Preferred Stock, Series 7%, equal to the sum of (x) dividends accrued and unpaid thereon to the date of final dissolution to such holders, whether or not declared, plus (y) $20.00; provided that neither the consolidation, the merger or other business combination of the Company with or into another corporation, nor sale or transfer of all or part of the assets of the Company for cash, securities or other property will be deemed a liquidation, dissolution or winding up of the Company for purposes of this sentence. In any event, the right of holders of Convertible Preferred Stock, Series 7%, to the foregoing liquidation preference will accrue to such holders only if the Company's payments with respect to the liquidation preferences of the holders of outstanding capital stock of the Company ranking senior to the Convertible Preferred Stock, Series 7%, if any, are fully met. If the assets of the Company available for distribution to the holders of the shares of the Convertible Preferred Stock, Series 7%, shall not be sufficient to make the payment thereon required to be made in full, such assets will be distributed to the holders of the shares of the Convertible Preferred Stock, Series 7%, and any Parity Stock (such as the DECS) ratably in proportion to the full amounts to which they would otherwise be entitled. After payment is made in full to the holders of the shares of the Convertible Preferred Stock, Series 7%, the remaining assets and funds of the Company will be distributed among the holders of all shares of stock ranking subordinate to the Convertible Preferred Stock, Series 7%, according to their respective rights. DESCRIPTION OF THE DECS The following information is a summary of the material terms of the Certificate of Designations with respect to the DECS ("Certificate of Designations"), a copy of which has been filed as an exhibit to the Registration Statement of which this Prospectus is a part, and such summary is subject to and qualified in its entirety by reference to the Company's Charter and the Certificate of Designations. Ranking. The DECS will rank prior to the Common Stock both as to payment of dividends and distribution of assets upon liquidation and will rank pari passu with the Company's outstanding Convertible Preferred Stock, Series 7%. In addition, the DECS will rank on a parity with any Preferred Stock issued in the future by the Company that by its terms ranks pari passu with the DECS. Dividends. The holders of DECS are entitled to receive, when, as and if dividends on the DECS are declared by the Board of Directors of the Company out of funds legally available therefor, cumulative preferential dividends from the issue date of the DECS, accruing at the rate per share of $0.732 per annum or $0.183 per quarter for each DECS, payable quarterly in arrears on the fifteenth day of each February, May, August and November, or, if any such date is not a business day, on the next succeeding business day; provided, however, that with respect to any dividend period during which a redemption occurs, the Company may, at its option, declare accrued dividends to, and pay such dividends on, the date fixed for redemption, in which case such dividends would be payable in cash to the holders of DECS as of the record date for such dividend payment and would not be included in the calculation of the related Call Price as set forth below. The first dividend payment will be for the period from the issue date of the DECS to and including August 14, 1994 and will be payable on August 15, 1994. Dividends (or amounts equal to accrued and unpaid dividends) payable on the DECS for any period shorter than a quarterly dividend period will be computed on the basis of a 360-day year of twelve 30-day months. Dividends will be payable to holders of record of the DECS as they appear on the stock register of the Company, on such record dates, not less than 15 nor more than 60 days preceding the payment date thereof, as shall be fixed by the Board of Directors. Dividends are payable in cash except in connection with certain redemptions by the Company. Dividends on the DECS will accrue whether or not the Company has earnings, whether or not there are funds legally available for the payment of such dividends and whether or not such dividends are declared. Dividends accumulate to the extent they are not paid on the dividend payment date for the quarter for which they accrue. Accumulated and unpaid dividends will not bear interest. 55 56 Unless full cumulative dividends with respect to the DECS shall have been paid or contemporaneously are declared and paid through the most recent dividend payment date, then, whether or not the Mandatory Conversion Date has occurred, (a) no full cash dividend shall be declared or paid or set aside for payment or other distribution declared or made on any shares of the Company ranking on a parity as to dividends with the DECS, (b) no dividend or other distribution (other than a dividend or distribution paid in shares of, or warrants, rights or options exercisable for or convertible into, shares of Common Stock or in any other stock of the Company ranking junior to the DECS as to dividends and upon liquidation) shall be declared or paid or set aside for payment or other distribution declared or made upon the Common Stock or upon any other shares of the Company ranking junior to the DECS as to dividends and (c) no Common Stock or any other shares of the Company ranking junior to or on a parity with the DECS as to dividends or upon liquidation shall be redeemed, purchased or otherwise acquired for any consideration (or any moneys be paid to or made available for a sinking fund for the redemption of any shares of any such series or class) by the Company, except by conversion into or exchange for shares of the Company ranking junior to the DECS as to dividends and upon liquidation. When dividends which are payable in cash have not been paid or set aside in full with respect to the DECS and any other shares of the Company ranking on a parity as to dividends with the DECS, all dividends declared with respect to the DECS and any other shares of the Company ranking on a parity as to dividends with the DECS shall be declared pro rata so that the amount of dividends declared per share on the DECS and such other shares shall in all cases bear to each other the same ratio that at the time of declaration accrued and payable but unpaid dividends per share on the DECS and such other shares bear to each other. Holders of the DECS shall not be entitled to any dividends, whether payable in cash, property or stock, in excess of full cumulative dividends, as herein described. Mandatory Conversion of DECS. On the Mandatory Conversion Date, each outstanding DECS will convert automatically into shares of Common Stock at the Common Equivalent Rate in effect on such date and the right to receive an amount in cash equal to all accrued and unpaid dividends on such DECS (other than dividends payable to a holder of record on a prior date) to the Mandatory Conversion Date, whether or not declared, out of funds legally available for the payment of dividends, subject to the right of the Company to redeem the DECS on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, as described below, and subject to the conversion of the DECS at the option of the holder at any time prior to the Mandatory Conversion Date. The Common Equivalent Rate is initially one share of Common Stock for each DECS, and is subject to adjustment as described below. Because the price of the Common Stock is subject to market fluctuations, the value of the Common Stock received by a holder of DECS upon Mandatory Conversion may be more or less than the amount paid for the DECS. Dividends will cease to accrue on the Mandatory Conversion Date in respect of the DECS then outstanding. Right to Redeem DECS. The DECS are not redeemable by the Company prior to the Initial Redemption Date. At any time and from time to time on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, the Company may redeem the outstanding DECS, in whole or in part. Upon any such redemption, each holder of DECS will receive, in exchange for each DECS so called, a number of shares of Common Stock equal to the Call Price of the DECS in effect on the date of redemption divided by the Current Market Price of the Common Stock determined as of the date which is the trading day prior to the public announcement of the call for redemption. The Call Price of each DECS is the sum of (i) $9.058 on and after the Initial Redemption Date through August 14, 1997, $9.012 on and after August 15, 1997 through November 14, 1997, $8.967 on and after November 15, 1997 through February 14, 1998, $8.921 on and after February 15, 1998 through April 14, 1998, and $8.875 on and after April 15, 1998 until the Mandatory Conversion Date, and (ii) all accrued and unpaid dividends thereon to the date fixed for redemption (other than dividends payable to a holder of record as of a prior date). The public announcement of any call for redemption shall be made prior to the mailing of the notice of such call to holders of DECS as described below. Dividends will cease to accrue on DECS on the date fixed for their redemption. The term "Current Market Price" per share of the Common Stock on any date of determination means the lesser of (x) the average of the closing sale prices of the Common Stock as reported on the 56 57 NYSE for the 15 consecutive trading days ending on and including such date of determination and (y) the closing sale price of the Common Stock as reported on the NYSE for such date of determination; provided, however, that, with respect to any redemption of the DECS, if any event that results in an adjustment of the Common Equivalent Rate occurs during the period beginning on the first day of such 15-day period and ending on the applicable redemption date, the Current Market Price as determined pursuant to the foregoing will be appropriately adjusted to reflect the occurrence of such event. The opportunity for equity appreciation afforded by an investment in the DECS is less substantial than the opportunity for equity appreciation afforded by an investment in the Common Stock because the Company may, at its option, redeem the DECS at any time on or after the Initial Redemption Date and prior to the Mandatory Conversion Date, and may be expected to do so prior to the Mandatory Conversion Date if the market price of the Common Stock exceeds the Call Price. In such event, holders of the DECS will receive less than one share of Common Stock for each DECS. However, because holders of DECS called for redemption will have the option to surrender DECS for conversion at the Conversion Price up to the close of business on the redemption date (and may be expected to do so if the market price of the Common Stock exceeds the Conversion Price), a holder that elects to convert will receive 0.8474 of a share of Common Stock for each DECS. Because the number of shares of Common Stock to be delivered in payment of the Call Price will be determined on the basis of the market price of the Common Stock prior to the announcement of the call, the value per share of the shares of Common Stock to be delivered may be more or less than the Call Price on the date of delivery. As a result of these provisions, holders of DECS would be expected to realize no equity appreciation if the market price of one share of Common Stock is below the Conversion Price, and less than all of such appreciation if the market price of one share of Common Stock is above the Conversion Price. Holders of DECS will realize the entire decline in equity value if the market price of the Common Stock is less than the price paid for a DECS. Conversion at Option of Holder. The DECS are convertible, in whole or in part, at the option of the holders thereof, at any time prior to the Mandatory Conversion Date, unless previously redeemed, into shares of Common Stock at a rate of 0.8474 of a share of Common Stock for each DECS (the "Optional Conversion Rate") (equivalent to a Conversion Price of $10.473 per share of Common Stock), subject to adjustment as described below. The right to convert DECS called for redemption will terminate at the close of business on the redemption date. Conversion of DECS may be effected by delivering certificates evidencing such DECS, together with written notice of conversion and a proper assignment of such certificates to the Company or in blank, to the office or agency to be maintained by the Company for that purpose (and, if applicable, payment of an amount equal to the dividend payable on such shares), and otherwise in accordance with conversion procedures established by the Company. Each conversion shall be deemed to have been effected immediately prior to the close of business on the date on which the foregoing requirements shall have been satisfied. The conversion shall be at the Optional Conversion Rate in effect at such time and on such date. Holders of DECS at the close of business on a record date for any payment of dividends will be entitled to receive the dividend payable on such DECS on the corresponding dividend payment date notwithstanding the conversion of such DECS following such record date and prior to such dividend payment date. However, DECS surrendered for conversion after the close of business on a record date for any payment of dividends and before the opening of business on the next succeeding dividend payment date (unless such DECS are subject to redemption on a redemption date in that period) must be accompanied by payment of an amount equal to the dividend thereon which is to be paid on such dividend payment date. Except as provided above, the Company will make no payment of or allowance for unpaid dividends, whether or not in arrears, on converted DECS or for dividends or distributions on the shares of Common Stock issued upon such conversion. Conversion Adjustment. The Common Equivalent Rate and the Optional Conversion Rate are each subject to adjustment if the Company shall (i) pay a dividend or make a distribution with respect to 57 58 Common Stock in shares of such stock, (ii) subdivide or split its outstanding shares of Common Stock, (iii) combine its outstanding shares of Common Stock into a smaller number of shares, (iv) issue by reclassification of its shares of Common Stock any shares of common stock of the Company, (v) issue rights or warrants to all holders of its Common Stock entitling them (for a period not exceeding 45 days from the date of such issuance) to subscribe for or purchase shares of Common Stock at a price per share less than the market price of the Common Stock or (vi) pay a dividend or make a distribution to all holders of its Common Stock in the form of evidences of its indebtedness, cash or other assets (including capital stock of the Company other than Common Stock but excluding any dividends or distributions referred to in clause (i) above or any cash dividends other than "Extraordinary Cash Dividends" as defined below) or issue to all holders of its Common Stock rights or warrants to subscribe for or purchase any of its securities (other than those referred to in clause (v) above). The Company will also be entitled (but shall not be required) to make upward adjustments in the Common Equivalent Rate, the Optional Conversion Rate and the Call Price, as it in its discretion shall determine to be advisable, in order that any stock dividends, subdivision of shares, distribution of rights to purchase stock or securities, or distribution of securities convertible into or exchangeable for stock (or any transaction which could be treated as any of the foregoing transactions pursuant to Section 305 of the Internal Revenue Code of 1986, as amended) hereafter made by the Company to its stockholders will not be taxable. "Extraordinary Cash Distribution" means the portion of any cash dividend or cash distribution on the Common Stock that, when added to all other cash dividends and cash distributions on the Common Stock made during the immediately preceding 12-month period (other than cash dividends and cash distributions for which a prior adjustment to the Common Equivalent Rate and the Optional Conversion Rate was previously made) exceeds, on a per share of Common Stock basis, 10 percent of the average daily closing sales price of the Common Stock over such 12-month period. All adjustments to the Common Equivalent Rate and the Optional Conversion Rate will be calculated to the nearest 1/100th of a share of Common Stock (or if there is not a nearest 1/100th of a share to the next lower 1/100th of a share). No adjustment in the Common Equivalent Rate and the Optional Conversion Rate shall be required unless such adjustment would require an increase or decrease of at least one percent therein; provided, however, that any adjustments which by reason of the foregoing are not required to be made shall be carried forward and taken into account in any subsequent adjustment. Whenever the Common Equivalent Rate and the Optional Conversion Rate are adjusted as provided in the preceding paragraph, the Company will file with each transfer agent for the DECS a certificate with respect to such adjustment, make a prompt public announcement thereof and mail a notice to holders of the DECS providing specified information with respect to such adjustment. At least 10 business days prior to certain specified actions that could result in certain adjustments in the Common Equivalent Rate and the Optional Conversion Rate, the Company will notify each holder of DECS concerning such proposed action. Adjustment for Consolidation or Merger. In case of any consolidation or merger to which the Company is a party (other than a merger or consolidation in which the Company is the continuing corporation and in which the Common Stock outstanding immediately prior to the merger or consolidation is not exchanged for cash, securities or other property of the Company or another corporation) or in case of any statutory exchange of securities with another corporation (other than in connection with a merger or acquisition), each DECS shall, after consummation of such transaction, be subject to (i) conversion at the option of the holder into the kind and amount of securities, cash or other property receivable upon consummation of such transaction by a holder of the number of shares of Common Stock into which such DECS might have been converted immediately prior to consummation of such transaction, (ii) conversion on the Mandatory Conversion Date into the kind and amount of securities, cash or other property receivable upon consummation of such transaction by a holder of the number of shares of Common Stock into which such DECS would have been converted if the conversion on the Mandatory Conversion Date had occurred immediately prior to the date of consummation of such transaction and (iii) redemption on any redemption date in exchange for the kind and amount of securities, cash or other property receivable upon consummation of such transaction by a holder of the number of shares of Common Stock that would have been issuable at the Call Price in effect on such redemption date upon a redemption of such DECS 58 59 immediately prior to consummation of such transaction, assuming that, if the earlier of the public announcement of such redemption or the commencement of the mailing of notice of such redemption to holders of DECS (the "Notice Date") is not prior to such transaction, the Notice Date had been the date of such transactions; and assuming in each case that such holder of Common Stock failed to exercise rights of election, if any, as to the kind or amount of securities, cash or other property receivable upon consummation of such transaction (provided that if the kind or amount of securities, cash or other property receivable upon consummation of such transaction is not the same for each non-electing share of Common Stock, then the kind and amount of securities, cash or other property receivable upon consummation of such transaction for each non-electing share shall be deemed to be the kind and amount so receivable per share by a plurality of the non-electing shares). The kind and amount of securities into which the DECS shall be convertible after consummation of such transaction shall be subject to adjustment as described above under the caption "Conversion Adjustments" following the date of consummation of such transaction. The Company may not become a party to any such transaction unless the terms thereof are consistent with the foregoing. Fractional Shares. No fractional shares of Common Stock will be issued upon redemption or conversion of the DECS. In lieu of any fractional share otherwise issuable in respect of all DECS of any holder which are redeemed or converted on any redemption date or upon Mandatory Conversion or any optional conversion, such holder shall be entitled to receive an amount in cash equal to the same fraction of the (i) Current Market Price in the case of redemption, or (ii) Closing Price (as defined in the Certificate of Designations) of the Common Stock determined (A) as of the fifth trading day immediately preceding the Mandatory Conversion Date, in the case of Mandatory Conversion, or (B) as of the second trading day immediately preceding the effective date of conversion, in the case of an optional conversion by a holder. Notice to Holders of DECS. The Company will provide notice of any call of the DECS to holders of record of the DECS to be called not less than 15 nor more than 60 days prior to the date fixed for redemption. Such notice shall be provided by mailing notice of such redemption to the holders of record of the DECS to be called. Each holder of DECS to be called shall surrender the certificates evidencing such DECS to the Company at the place designated in such notice and shall be entitled to receive certificates for shares of Common Stock following such surrender and the date of such redemption. If fewer than all the outstanding DECS are to be called, the DECS to be called shall be selected by the Company from outstanding DECS by lot or pro rata (as nearly as may be) or by any other method determined by the Board of Directors of the Company in its sole discretion to be equitable. Liquidation Rights. In the event of the liquidation, dissolution or winding up of the business of the Company, whether voluntary or involuntary, the holders of DECS, after payment or provision for payment of the debts and other liabilities of the Company and before any distribution to the holders of the Common Stock or any other stock ranking junior to the DECS with respect to distributions upon liquidation, dissolution or winding up, will be entitled to receive, for each DECS, an amount equal to the sum of (i) the per share price to the public shown on the cover page of this Prospectus and (ii) all accrued and unpaid dividends thereon to the date of liquidation, dissolution or winding up. In the event the assets of the Company available for distribution to the holders of the DECS upon any dissolution, liquidation or winding up of the Company shall be insufficient to pay in full the liquidation payments payable to the holders of outstanding DECS and any shares of the Company ranking on a parity with the DECS upon liquidation, then the holders of all such DECS shall share ratably in such distribution of assets in accordance with the amount which would be payable on such distribution if the amounts to which the holders of outstanding DECS and the holders of such shares of the Company ranking on a parity with the DECS upon liquidation are entitled were paid in full. Voting Rights. The holders of DECS shall have the right to vote with the holders of Common Stock in the election of directors and upon each other matter coming before any meeting of the stockholders on the basis of 4/5 of a vote for each DECS held; the holders of DECS, and the holders of Common Stock will vote together as one class except as otherwise provided by law or by the Charter. 59 60 Whenever dividends on the DECS shall be in arrears and unpaid in an aggregate amount of dividends payable thereon for four quarterly dividend periods, or if any other series of Preferred Stock shall be entitled for any reason to exercise voting rights, separate from the Common Stock, to elect any Director of the Company ("Preferred Stock Directors"), the holders of the DECS (voting separately as a class with holders of all other series of Preferred Stock upon which like voting rights have been conferred and are exercisable), with each DECS entitled to one vote on this and other matters in which the holders of Preferred Stock vote as a group, will be entitled to vote for the election of two Preferred Stock Directors of the Company, such Directors to be in addition to the number of directors constituting the Board of Directors immediately prior to the accrual of such right. Such right shall, when vested, continue until all dividends in default on the DECS shall have been paid in full and the right of any other series of Preferred Stock to exercise voting rights, separate from the Common Stock, to elect any Preferred Stock Directors shall terminate or have terminated and, when so paid and such termination occurs or has occurred, such right of the holders of the DECS shall cease. The term of office of all Directors elected by the holders of the DECS and such other series shall terminate on the earlier of (i) the next annual meeting of the stockholders at which a successor shall have been elected and qualified or (ii) the termination of the right of holders of the DECS and such other series to vote for such Directors. The Company will not, without the approval of the holders of at least 66 2/3 percent of all the DECS then outstanding: (i) amend, alter or repeal any of the provisions of the Charter or the Bylaws of the Company so as to affect adversely the powers, preferences or rights of the holders of the DECS then outstanding or reduce the minimum time required for any notice to which only the holders of the DECS then outstanding may be entitled (an amendment of the Charter to authorize or create, or to increase the authorized amount of any stock of any class ranking junior to or on a parity with the DECS shall be deemed not to affect adversely the powers, preferences, or rights of the holders of the DECS); (ii) create any series of Preferred Stock ranking prior to the DECS as to payment of dividends or upon liquidation; (iii) authorize or create, or increase the authorized amount of, any capital stock, or any security convertible into capital stock, of any class ranking prior to the DECS as to payment of dividends or upon liquidation; or (iv) merge or consolidate with or into any other corporation, unless each holder of the DECS immediately preceding such merger or consolidation shall receive or continue to hold in the resulting corporation the same number of shares, with substantially the same rights and preferences, as correspond to the DECS so held. As long as any DECS are outstanding, the Company will not, without the approval of the holders of at least a majority of the DECS and shares of any Preferred Stock ranking on a parity with the DECS then outstanding: (i) increase the authorized amount of the Preferred Stock or (ii) create any class or classes of capital stock ranking on a parity with the DECS, either as to payment of dividends or upon liquidation, and not existing on the date of the Certificate of Designations, or create any stock, or other security, convertible into or exchangeable for or evidencing the right to purchase any stock of such other class of capital stock ranking on a parity with the DECS, or increase the authorized number of shares of any such other class of capital stock or amount of such other stock or security. Notwithstanding the provisions summarized in the preceding two paragraphs, however, no such approval described therein of the holders of the DECS shall be required if, at or prior to the time when such amendment, alteration, or repeal is to take effect or when the authorization, creation or increase of any such prior or parity stock or such other stock or security is to be made, or when such consolidation or merger is to take effect, as the case may be, provision is made for the redemption of all DECS at the time outstanding. Reissuance. DECS redeemed for or converted into Common Stock or otherwise acquired by the Company will assume the status of authorized but unissued Preferred Stock and may thereafter be reissued in the same manner as other authorized but unissued Preferred Stock. Listing. The DECS have been approved for listing on the NYSE under the symbol SFRPRA. 60 61 Registrar and Transfer Agent. First Chicago Trust Company of New York, which also acts as transfer agent and registrar for the Common Stock and the Convertible Preferred Stock, 7%, will serve as registrar and transfer agent for the DECS. FEDERAL INCOME TAX CONSIDERATIONS The following discussion sets forth the material United States federal income tax consequences under existing law of the ownership and disposition of the DECS. Changes to existing law, which could have retroactive effect, may alter the consequences described below. This discussion relates only to DECS or shares of Common Stock received upon conversion thereof or in exchange therefor that are held as capital assets within the meaning of Section 1221 of the Internal Revenue Code of 1986, as amended at the date hereof (the "Code"), and does not deal with all tax consequences that may be relevant in the particular circumstances of each holder (some of which, such as dealers in securities, insurance companies, tax-exempt organizations and foreign persons, may be subject to special rules). In addition, stock having terms closely resembling those of the DECS has not been the subject of any regulation, ruling or judicial decision currently in effect, and there can be no assurance that the Internal Revenue Service will take the positions set forth below. Except as otherwise indicated, statements of legal conclusions regarding federal income tax consequences in this section reflect the opinion of Andrews & Kurth L.L.P., counsel to the Company. These conclusions are based on the Code, regulations promulgated thereunder, and the current judicial and administrative interpretations thereof. The Company has not and will not seek a ruling as to any tax matters relating to the DECS. Persons considering the purchase of DECS should consult their tax advisors with respect to the application of the United States federal income tax laws to their particular situations as well as any tax consequences arising under the laws of any state, local or foreign taxing jurisdiction. DIVIDENDS Dividends paid on the DECS out of the Company's current or accumulated earnings and profits will be taxable as ordinary income and will qualify for the 70 percent intercorporate dividends-received deduction subject to the minimum holding period (generally at least 46 days) and other applicable requirements. Under certain circumstances, a corporate holder may be subject to the alternative minimum tax with respect to the amount of its dividends-received deduction. Under certain circumstances, a corporation that receives an "extraordinary dividend," as defined in Section 1059(c) of the Code, is required to reduce its stock basis by the non-taxed portion of such dividend. Generally, quarterly dividends not in arrears paid to an original holder of the DECS will not constitute extraordinary dividends under Section 1059(c). In addition, under Section 1059(f), any dividend with respect to "disqualified preferred stock" is treated as an "extraordinary dividend." However, while the issue is not free from doubt due to the lack of authority directly on point, the DECs will not constitute "disqualified preferred stock." REDEMPTION PREMIUM Under certain circumstances, Section 305(c) of the Code requires that any excess of the redemption price of preferred stock over its issue price be includable in income, prior to receipt, as a constructive dividend. While the issue is not free from doubt due to a lack of authority addressing the issue, Section 305(c) should not currently apply to stock with terms such as those of the DECS. REDEMPTION OR MANDATORY OR OPTIONAL CONVERSION INTO COMMON STOCK Gain or loss generally will not be recognized by a holder upon the redemption of the DECS for shares of Common Stock or the conversion of DECS into shares of Common Stock if no cash is received. Income may be recognized, however, to the extent cash or Common Stock is received in payment of accrued and unpaid dividends in arrears. Such income would probably be characterized as dividend income, although some uncertainty exists as to the appropriate characterization of payments in satisfaction of undeclared 61 62 accrued and unpaid dividends. In addition, a holder who receives cash in lieu of a fractional share will be treated as having received such fractional share and having exchanged it for cash in a transaction subject to Section 302 of the Code and related provisions. Such exchange should generally result in capital gain or loss measured by the difference between the cash received for the fractional share interest and the holder's basis in the fractional share interest. Generally, a holder's basis in the Common Stock received upon the redemption or conversion of the DECS (other than shares of Common Stock taxed upon receipt) will equal the adjusted tax basis of the redeemed or converted DECS plus the amount of gain recognized, minus the amount of cash received, and the holding period of such Common Stock will include the holding period of the redeemed or converted DECS. ADJUSTMENT OF CONVERSION RATE Certain adjustments (or failures to make adjustments) to the Common Equivalent Rate to reflect the Company's issuance of certain rights, warrants, evidences of indebtedness, securities or other assets to holders of Common Stock may result in a constructive distribution taxable as dividends to the holders of the DECS, which may constitute (and cause other dividends to constitute) "extraordinary dividends" to corporate holders. See "--Dividends." CONVERSION OF DECS AFTER DIVIDEND RECORD DATE If a holder of DECS exercises such holder's right to convert DECS into shares of Common Stock after a dividend record date but before payment of the dividend, then such holder generally will be required to pay the Company an amount equal to the portion of such dividend attributable to the current quarterly dividend period upon conversion, which amount would increase the basis of the Common Stock received. The holder would recognize the dividend payment as income. BACKUP WITHHOLDING Certain non-corporate holders may be subject to backup withholding at a rate of 31 percent on dividends and certain consideration received upon the redemption or conversion of the DECS. Generally, backup withholding applies only when the taxpayer fails to furnish or certify a proper Taxpayer Identification Number or when the taxpayer is notified by the Internal Revenue Service that the taxpayer has failed to report payments of interest and dividends properly. Holders should consult their tax advisors regarding their qualification for exemption from backup withholding and the procedure for obtaining any applicable exemption. UNDERWRITING The Underwriters named below have severally agreed, subject to the terms and conditions of the Underwriting Agreement with the Company, to purchase from the Company the number of DECS set forth opposite their respective names. The Underwriters are committed to purchase all of the DECS if any are purchased.
NUMBER OF UNDERWRITERS DECS ------------------------------------------------------ ----------- Salomon Brothers Inc.................................. 3,566,668 Lazard Freres & Co.................................... 3,566,666 PaineWebber Incorporated.............................. 3,566,666 ----------- Total............................................ 10,700,000 -----------
The Underwriters have advised the Company that they propose initially to offer DECS to the public at the public offering price set forth on the cover page of this Prospectus and to certain dealers at such 62 63 price less a concession not in excess of $.16 per share. The Underwriters may allow, and such dealers may reallow, a discount not in excess of $.02 per share on sales to certain other dealers. After the initial public offering, the public offering price, concession and discount may be changed. The Company and each of its executive officers and directors (other than Mr. Dammeyer) and each of HC Associates and Minorco USA, have agreed not to offer, sell, contract to sell or otherwise dispose of any shares of Common Stock, any securities convertible into or exercisable or exchangeable for Common Stock, or any rights to acquire Common Stock for a period of 120 days after the date of this Prospectus without the prior written consent of Salomon Brothers Inc; provided, however, that such restriction shall not affect the ability of the Company or its subsidiaries to take any such actions (i) as a consequence of obligations with respect to securities outstanding prior to the date of this Prospectus, (ii) in connection with any employee benefit or incentive plans of the Company or (iii) in connection with the offering of the DECS made hereby or the conversion thereof. The Company has agreed to indemnify the Underwriters against certain civil liabilities, including certain liabilities under the Securities Act of 1933, as amended. The DECS are a new issue of securities with no established trading market. The DECS have been approved for trading on the NYSE, but no assurance can be given as to the development or liquidity of any trading market in the DECS. If an active market does not develop, the market price and liquidity of the DECS may be adversely affected. VALIDITY OF THE SECURITIES The validity of the DECS will be passed upon for the Company by Andrews & Kurth L.L.P., Houston, Texas. Certain legal matters will be passed upon for the Underwriters by Cravath, Swaine & Moore, New York, New York. EXPERTS The financial statements as of December 31, 1993 and 1992 and for each of the three years in the period ended December 31, 1993 included in this Prospectus have been so included in reliance on the report of Price Waterhouse, independent accountants, given on the authority of said firm as experts in auditing and accounting. Certain information appearing in this Prospectus regarding the estimated quantities of reserves of the oil and natural gas properties owned by the Company, the future net revenues from such reserves and the present value thereof is based on estimates of such reserves and present values prepared by Ryder Scott Company, independent petroleum engineers. 63 64 INDEX TO FINANCIAL STATEMENTS
PAGE ------ Audited Financial Statements Report of Independent Accountants............................................ F-2 Consolidated Statement of Operations for the years ended December 31, 1993, 1992 and 1991................................................................. F-3 Consolidated Balance Sheet -- December 31, 1993 and 1992..................... F-4 Consolidated Statement of Cash Flows for the years ended December 31, 1993, 1992 and 1991................................................................. F-5 Consolidated Statement of Shareholders' Equity for the years ended December 31, 1993, 1992 and 1991....................................................... F-6 Notes to Consolidated Financial Statements................................... F-7 Unaudited Financial Information Supplemental Information to the Consolidated Financial Statements............ F-26 Unaudited Financial Statements Consolidated Statement of Operations for the three months ended March 31, 1994 and 1993................................................................... F-35 Consolidated Balance Sheet -- March 31, 1994 and December 31, 1993........... F-36 Consolidated Statement of Cash Flows for the three months ended March 31, 1994 and 1993................................................................... F-37 Consolidated Statement of Shareholders' Equity for the three months ended March 31, 1994 and 1993....................................................... F-38 Notes to Consolidated Financial Statements................................... F-39
F-1 65 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders of Santa Fe Energy Resources, Inc. In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of cash flows, and of shareholders' equity present fairly, in all material respects, the financial position of Santa Fe Energy Resources, Inc. and its subsidiaries at December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. 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 of these statements in accordance with generally accepted auditing standards which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. PRICE WATERHOUSE Houston, Texas February 18, 1994 F-2 66 SANTA FE ENERGY RESOURCES, INC. CONSOLIDATED STATEMENT OF OPERATIONS (IN MILLIONS OF DOLLARS, EXCEPT PER SHARE DATA)
YEAR ENDED DECEMBER 31, ------------------------------- 1993 1992 1991 --------- --------- --------- Revenues Crude oil and liquids......................................................... $ 307.3 $ 333.6 $ 320.3 Natural gas................................................................... 107.8 74.8 47.9 Natural gas systems........................................................... 8.2 7.3 -- Crude oil marketing and trading............................................... 9.9 5.9 7.2 Other......................................................................... 3.7 5.9 4.4 --------- --------- --------- 436.9 427.5 379.8 --------- --------- --------- Costs and Expenses Production and operating...................................................... 163.8 153.4 134.6 Oil and gas systems and pipelines............................................. 4.2 3.2 -- Exploration, including dry hole costs......................................... 31.0 25.5 18.7 Depletion, depreciation and amortization...................................... 152.7 146.3 106.6 Impairment of oil and gas properties.......................................... 99.3 -- -- General and administrative.................................................... 32.3 30.9 27.8 Taxes (other than income)..................................................... 27.3 24.3 27.2 Restructuring charges......................................................... 38.6 -- -- Loss (gain) on disposition of oil and gas properties.......................... 0.7 (13.6) 0.5 --------- --------- --------- 549.9 370.0 315.4 --------- --------- --------- Income (Loss) from Operations..................................................... (113.0) 57.5 64.4 Interest income............................................................... 9.1 2.3 2.3 Interest expense.............................................................. (45.8) (55.6) (47.3) Interest capitalized.......................................................... 4.3 4.9 7.7 Other income (expense)........................................................ (4.8) (10.0) 5.6 --------- --------- --------- Income (Loss) Before Income Taxes................................................. (150.2) (0.9) 32.7 Income taxes.................................................................. 73.1 (0.5) (14.2) --------- --------- --------- Net Income (Loss)................................................................. (77.1) (1.4) 18.5 Preferred dividend requirement.................................................... (7.0) (4.3) -- --------- --------- --------- Earnings (Loss) Attributable to Common Shares..................................... $ (84.1) $ (5.7) $ 18.5 ========= ========= ========= Earnings (Loss) Attributable to Common Shares Per Share........................... $ (0.94) $ (0.07) $ 0.29 ========= ========= ========= Weighted Average Number of Shares Outstanding (in millions)....................... 89.7 79.0 63.8 ========= ========= =========
The accompanying notes are an integral part of these financial statements. F-3 67 SANTA FE ENERGY RESOURCES, INC. CONSOLIDATED BALANCE SHEET (IN MILLIONS OF DOLLARS)
DECEMBER 31, -------------------------- 1993 1992 ----------- ------------ ASSETS Current Assets Cash and cash equivalents......................................................... $ 4.8 $ 83.8 Accounts receivable............................................................... 87.4 90.0 Income tax refund receivable...................................................... -- 16.2 Inventories....................................................................... 8.7 4.8 Assets held for sale.............................................................. 59.5 -- Other current assets.............................................................. 12.2 10.6 ------------ ------------ 172.6 205.4 ------------ ------------ Investment in Hadson Corporation...................................................... 56.2 -- ------------ ------------ Properties and Equipment, at cost Oil and gas (on the basis of successful efforts accounting)....................... 2,064.3 2,330.9 Other............................................................................. 27.3 26.8 ------------ ------------ 2,091.6 2,357.7 Accumulated depletion, depreciation, amortization and impairment.................. (1,258.9) (1,255.9) ------------ ------------ 832.7 1,101.8 ------------ ------------ Other Assets Receivable under gas balancing arrangements....................................... 3.9 7.7 Other............................................................................. 11.5 22.3 ------------ ------------ 15.4 30.0 ------------ ------------ $ 1,076.9 $ 1,337.2 ============ ============ LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts payable.................................................................. $ 93.5 $ 90.9 Interest payable.................................................................. 10.2 11.0 Current portion of long-term debt................................................. 44.3 53.4 Other current liabilities......................................................... 18.1 17.1 ------------ ------------ 166.1 172.4 ------------ ------------ Long-Term Debt........................................................................ 405.4 492.8 ------------ ------------ Deferred Revenues..................................................................... 8.6 13.0 ------------ ------------ Other Long-Term Obligations........................................................... 48.8 43.4 ------------ ------------ Deferred Income Taxes................................................................. 44.4 119.0 ------------ ------------ Commitments and Contingencies (Note 12)............................................... -- -- ------------ ------------ Convertible Preferred Stock, $0.01 par value, 5.0 million shares authorized, issued and outstanding..................................................................... 80.0 80.0 ------------ ------------ Shareholders' Equity Preferred stock, $0.01 par value, 45.0 million shares authorized, none issued..... -- -- Common stock, $0.01 par value, 200.0 million shares authorized.................... 0.9 0.9 Paid-in capital................................................................... 496.9 494.3 Unamortized restricted stock awards............................................... (0.1) (0.4) Accumulated deficit............................................................... (173.8) (78.0) Foreign currency translation adjustment........................................... (0.3) (0.2) ------------ ------------ 323.6 416.6 ------------ ------------ $ 1,076.9 $ 1,337.2 ============ ============
The accompanying notes are an integral part of these financial statements. F-4 68 SANTA FE ENERGY RESOURCES, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (IN MILLIONS OF DOLLARS)
YEAR ENDED DECEMBER 31, ---------------------------------- 1993 1992 1991 ---------- ---------- ---------- Operating Activities: Net income (loss)......................................................... $ (77.1) $ (1.4) $ 18.5 Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation and amortization.............................. 152.7 146.3 106.6 Impairment of oil and gas properties.................................. 99.3 -- -- Restructuring charges................................................. 27.8 -- -- Deferred income taxes................................................. (71.9) (6.3) 1.5 Net loss (gain) on disposition of properties.......................... 0.7 (13.6) (5.5) Exploratory dry hole costs............................................ 8.9 4.7 3.8 Expenses related to acquisition of Adobe Resources Corporation........ -- 10.9 -- Other................................................................. 4.2 2.0 0.3 Changes in operating assets and liabilities: Decrease (increase) in accounts receivable............................ 12.4 (8.3) 23.6 Decrease (increase) in inventories.................................... (3.8) 0.3 5.6 Increase (decrease) in accounts payable............................... (2.6) 5.9 (24.9) Increase (decrease) in interest payable............................... (0.8) 0.4 0.2 Decrease in income taxes payable...................................... (0.6) (0.4) (3.6) Net change in other assets and liabilities............................ 11.0 1.0 2.3 ---------- ---------- ---------- Net Cash Provided by Operating Activities..................................... 160.2 141.5 128.4 ---------- ---------- ---------- Investing Activities: Capital expenditures, including exploratory dry hole costs................ (127.0) (76.8) (108.1) Acquisitions of producing properties, net of related debt................. (4.4) (14.2) (28.5) Acquisition of Adobe Resources Corporation................................ -- (11.9) -- Acquisition of Santa Fe Energy Partners, L.P.............................. (28.3) -- -- Net proceeds from sales of properties..................................... 39.9 89.1 22.1 Increase in partnership interest due to reinvestment...................... (1.6) (2.1) (2.7) ---------- ---------- ---------- Net Cash Used in Investing Activities......................................... (121.4) (15.9) (117.2) ---------- ---------- ---------- Financing Activities: Net change in short-term debt............................................. -- (4.6) (4.2) Proceeds from long-term borrowings........................................ -- 5.0 -- Principal payments on long-term borrowings................................ (41.5) (55.5) (16.3) Net change in revolving credit agreement.................................. (55.0) -- -- Cash dividends paid to others............................................. (21.3) (14.9) (10.2) ---------- ---------- ---------- Net Cash Used in Financing Activities......................................... (117.8) (70.0) (30.7) ---------- ---------- ---------- Net Increase (Decrease) in Cash and Cash Equivalents.......................... (79.0) 55.6 (19.5) Cash and Cash Equivalents at Beginning of Year................................ 83.8 28.2 47.7 ---------- ---------- ---------- Cash and Cash Equivalents at End of Year...................................... $ 4.8 $ 83.8 $ 28.2 ========== ========== ==========
The accompanying notes are an integral part of these financial statements. F-5 69 SANTA FE ENERGY RESOURCES, INC. CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (SHARES AND DOLLARS IN MILLIONS)
FOREIGN UNAMORTIZED CURRENCY COMMON STOCK RESTRICTED TRANSLA- TOTAL --------------- PAID-IN STOCK ACCUMULATED TION SHAREHOLDERS' SHARES AMOUNT CAPITAL AWARDS DEFICIT ADJUSTMENT EQUITY ------ ------ ------- ------------ ----------- ---------- ------------- Balance at December 31, 1990.................. 63.8 $0.6 $ 282.4 $ -- $ (67.2) $ -- $ 215.8 Net income.................................. -- -- -- -- 18.5 -- 18.5 Issuance of common stock.................... 0.3 -- 2.5 (1.4) -- -- 1.1 Dividends declared.......................... -- -- -- -- (10.3) -- (10.3) ---- ---- ------- ------- --------- ------ ------- Balance at December 31, 1991.................. 64.1 0.6 284.9 (1.4) (59.0) -- 225.1 Issuance of common stock Acquisition of Adobe Resources Corporation.................... 24.9 0.3 205.3 -- -- -- 205.6 Employee stock compensation and savings plans.................................... 0.5 -- 4.1 (0.5) -- -- 3.6 Amortization of restricted stock awards..... -- -- -- 1.5 -- -- 1.5 Foreign currency translation adjustments.... -- -- -- -- -- (0.2) (0.2) Net loss.................................... -- -- -- -- (1.4) -- (1.4) Dividends declared.......................... -- -- -- -- (17.6) -- (17.6) ---- ---- ------- ------- --------- ------ ------- Balance at December 31, 1992.................. 89.5 0.9 494.3 (0.4) (78.0) (0.2) 416.6 Issuance of common stock Employee stock compensation and savings plans.................................... 0.3 -- 2.6 (0.1) -- -- 2.5 Amortization of restricted stock awards............................... -- -- -- 0.4 -- -- 0.4 Pension liability adjustment................ -- -- -- -- (0.9) -- (0.9) Foreign currency transaction adjustments.... -- -- -- -- -- (0.1) (0.1) Net loss.................................... -- -- -- -- (77.1) -- (77.1) Dividends declared.......................... -- -- -- -- (17.8) -- (17.8) ---- ---- ------- ------- --------- ------ ------- Balance December 31, 1993..................... 89.8 $0.9 $ 496.9 $ (0.1) $ (173.8) $ (0.3) $ 323.6 ==== ==== ======= ======= ========= ====== =======
The accompanying notes are an integral part of these financial statements. F-6 70 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation The consolidated financial statements of Santa Fe Energy Resources, Inc. ("Santa Fe" or the "Company") and its subsidiaries include the accounts of all wholly owned subsidiaries. The accounts of Santa Fe Energy Partners, L.P., (the "Partnership") are included on a proportional basis until September 1993 when Santa Fe purchased all the Partnership's outstanding Depositary Units and undeposited LP Units other than those units held by Santa Fe and its affiliates. On September 27, 1993 the Company exercised its right under the Agreement of Limited Partnership to purchase all of the Partnership's outstanding Depositary Units and undeposited LP Units, other than those units held by the Company and its affiliates, at a redemption price of $4.9225 per unit. Consideration for the 5,749,500 outstanding units totalled $28.3 million. The acquisition of the units has been accounted for as a purchase and the results of operations of the Partnership attributable to the units acquired is included in the Company's results of operations with effect from October 1, 1993. The purchase price has been allocated primarily to oil and gas properties. References herein to the "Company" or "Santa Fe" relate to Santa Fe Energy Resources, Inc., individually or together with its consolidated subsidiaries; references to the "Partnership" relate to Santa Fe Energy Partners, L.P. All significant intercompany accounts and transactions have been eliminated. Prior years' financial statements include certain reclassifications to conform to current year's presentation. Oil and Gas Operations The Company follows the successful efforts method of accounting for its oil and gas exploration and production activities. Costs (both tangible and intangible) of productive wells and development dry holes, as well as the cost of prospective acreage, are capitalized. The costs of drilling and equipping exploratory wells which do not find proved reserves are expensed upon determination that the well does not justify commercial development. Other exploratory costs, including geological and geophysical costs and delay rentals, are charged to expense as incurred. Depletion and depreciation of proved properties are computed on an individual field basis using the unit-of-production method based upon proved oil and gas reserves attributable to the field. Certain other oil and gas properties are depreciated on a straight-line basis. Individual proved properties are reviewed periodically to determine if the carrying value of the field exceeds the estimated undiscounted future net revenues from proved oil and gas reserves attributable to the field. Based on this review and the continuing evaluation of development plans, economics and other factors, if appropriate, the Company records impairments (additional depletion and depreciation) to the extent that the carrying value exceeds the estimated undiscounted future net revenues. Such impairments totaled $99.3 million in 1993 and there were none in 1992 and 1991. The Company provides for future abandonment and site restoration costs with respect to certain of its oil and gas properties. The Company estimates that with respect to these properties such future costs total approximately $24.7 million and such amount is being accrued over the expected life of the properties. At December 31, 1993 Accumulated Depletion, Depreciation, Amortization and Impairment includes $14.6 million with respect to such costs. The value of undeveloped acreage is aggregated and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized to expense over the average holding period. Additional amortization may be recognized based upon periodic assessment of prospect evaluation results. The cost of properties determined to be productive is transferred to proved F-7 71 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) properties; the cost of properties determined to be nonproductive is charged to accumulated amortization. Maintenance and repairs are expensed as incurred; major renewals and improvements are capitalized. Gains and losses arising from sales of properties are included in income currently. Revenue Recognition Revenues from the sale of petroleum produced are generally recognized upon the passage of title, net of royalties and net profits interests. Crude oil revenues include the effect of hedging transactions; see Note 12 -- Commitments and Contingencies -- Crude Oil Hedging Program. Crude oil revenues also include the value of crude oil consumed in operations with an equal amount charged to operating expenses. Such amounts totalled $15.4 million in 1991, $4.8 million in 1992 and $1.2 million in 1993. Revenues from natural gas production are generally recorded using the entitlement method, net of royalties and net profits interests. Sales proceeds in excess of the Company's entitlement are included in Deferred Revenues and the Company's share of sales taken by others is included in Other Assets. At December 31, 1993 the Company's deferred revenues for sales proceeds received in excess of the Company's entitlement was $6.8 million with respect to 5.2 MMcf and the asset related to the Company's share of sales taken by others was $3.9 million with respect to 2.7 MMcf. Natural gas revenues are net of the effect of hedging transactions; see Note 12 -- Commitments and Contingencies -- Natural Gas Hedging Program. Revenues from crude oil marketing and trading represent the gross margin resulting from such activities. Revenues from such activities are net of costs of sales of $210.5 million in 1991, $247.3 million in 1992 and $225.9 million in 1993. Revenues from natural gas systems are net of the cost of natural gas purchased and resold. Such costs totalled $43.8 million in 1992 and $49.9 million in 1993. Earnings Per Share Earnings per share are based on the weighted average number of common shares outstanding during the year. Accounts Receivable Accounts Receivable relates primarily to sales of oil and gas and amounts due from joint interest partners for expenditures made by the Company on behalf of such partners. The Company reviews the financial condition of potential purchasers and partners prior to signing sales or joint interest agreements. At December 31, 1993 and 1992 the Company's allowance for doubtful accounts receivable, which is reflected in the consolidated balance sheet as a reduction in accounts receivable, totaled $6.3 million and $5.0 million, respectively. Accounts receivable totalling $0.2 million, $1.1 million and $0.1 million were written off as uncollectible in 1991, 1992 and 1993, respectively. Inventories Inventories are valued at the lower of cost (average price or first.in, first.out) or market. Crude oil inventories at December 31, 1993 and 1992 were $1.1 million and $1.5 million, respectively, and materials and supplies inventories at such dates were $7.6 million and $3.3 million, respectively. Environmental Expenditures Environmental expenditures relating to current operations are expensed or capitalized, as appropriate, depending on whether such expenditures provide future economic benefits. Liabilities F-8 72 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) are recognized when the expenditures are considered probable and can be reasonably estimated. Measurement of liabilities is based on currently enacted laws and regulations, existing technology and undiscounted site-specific costs. Generally, such recognition coincides with the Company's commitment to a formal plan of action. Income Taxes The Company follows the asset and liability approach to accounting for income taxes. Deferred tax assets and liabilities are determined using the tax rate for the period in which those amounts are expected to be received or paid, based on a scheduling of temporary differences between the tax bases of assets and liabilities and their reported amounts. Under this method of accounting for income taxes, any future changes in income tax rates will affect deferred income tax balances and financial results. (2) CORPORATE RESTRUCTURING PROGRAM In October 1993 the Company's Board of Directors endorsed a broad corporate restructuring program that focuses on the disposition of non-core assets, the concentration of capital spending in core areas, the refinancing of certain long-term debt and the elimination of the payment of its $0.04 per share quarterly dividend on common stock. In implementing the restructuring program the Company recorded a nonrecurring charge of $38.6 million in 1993 comprised of (1) losses on property dispositions of $27.8 million: (2) long-term debt repayment penalties of $8.6 million; and (3) accruals for certain personnel benefits and related costs of $2.2 million. The Company's non-core asset disposition program includes the sale of its natural gas gathering and processing assets to Hadson Corporation ("Hadson"), the sale to Vintage Petroleum, Inc. of certain southern California and Gulf Coast oil and gas producing properties and the sale to Bridge Oil (U.S.A.) Inc. ("Bridge") of certain Mid-Continent and Rocky Mountain oil and gas producing properties and undeveloped acreage. The Company also plans to dispose of other non-core oil and gas properties during 1994. In 1994 the Company intends to refinance a portion of its existing long-term debt and is currently evaluating a combination of debt and equity financing arrangements with which to effect the refinancing. Sale to Hadson. In December 1993 the Company completed a transaction with Hadson under the terms of which the Company sold the common stock of Adobe Gas Pipeline Company ("AGPC"), a wholly-owned subsidiary which held the Company's natural gas gathering and processing assets, to Hadson in exchange for Hadson 11.25% preferred stock with a face value of $52.0 million and 40% of Hadson's common stock. In addition, the Company signed a seven-year gas sales contract under the terms of which Hadson will market substantially all of the Company's domestic natural gas production at market prices as defined by published monthly indices for relevant production locations. The Company accounted for the sale as a non-monetary transaction and the investment in Hadson has been valued at $56.2 million, the carrying value of the Company's investment in AGPC. The Company's investment in Hadson is being accounted for on the equity basis. At December 31, 1993 the Company's investment in Hadson's common stock exceeded the net book value attributable to such common shares by approximately $11.3 million. The Company's income from operations for 1993 includes $1.6 million attributable to the assets sold to Hadson. Sale to Vintage. In November 1993 the Company completed the sale of certain southern California and Gulf Coast producing properties for net proceeds totalling $41.3 million in cash, $31.5 F-9 73 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) million of which was collected in 1993. The Company's income from operations for 1993 includes $2.7 million attributable to the assets sold to Vintage. Sale to Bridge. In December 1993 the Company signed a Purchase and Sales Agreement with Bridge under the terms of which Bridge will purchase certain Mid-Continent and Rocky Mountain producing and nonproducing oil and gas properties. The sale price of $51.0 million, subject to certain adjustments, will be received by the Company either in the form of cash plus 10% of the outstanding shares of Bridge, following the contemplated public offering of that stock in the first quarter of 1994, or entirely in cash. The transaction is expected to close in the second quarter of 1994. The net book value of these assets is included in Assets Held for Sale at December 31, 1993. The Company's income from operations for 1993 includes $5.8 million attributable to the assets to be sold to Bridge. Other Dispositions. The Company has identified certain other oil and gas properties which it plans to dispose of in 1994. The estimated realizable value of these properties, $1.0 million, is included in Assets Held for Sale at December 31, 1993. In the first quarter of 1994 the Company sold its interest in certain other oil and gas properties for $8.3 million. (3) MERGER WITH ADOBE RESOURCES CORPORATION On May 19, 1992 Adobe Resources Corporation ("Adobe"), an oil and gas exploration and production company, was merged with and into Santa Fe (the "Merger"). The acquisition has been accounted for as a purchase and the results of operations of the properties acquired (the "Adobe Properties") are included in Santa Fe's results of operations effective June 1, 1992. To consummate the Merger, the Company issued 24.9 million shares of common stock valued at $205.5 million, 5.0 million shares of convertible preferred stock valued at $80.0 million, assumed long-term bank debt and other liabilities of $140.0 million and $35.0 million, respectively, and incurred $13.8 million in related costs. The Company also recorded a $19.7 million deferred tax liability with respect to the difference between the book and tax basis in the assets acquired. Certain merger.related costs incurred by Adobe and paid by Santa Fe totaling $10.9 million were charged to income in the second quarter of 1992. The Merger constituted a "change of control" as defined in certain of the Company's employee benefit plans and employment agreements (see Notes 10 and 12). In a separate transaction in January 1992, the Company purchased three producing properties from Adobe for $14.2 million. (4) SANTA FE ENERGY TRUST In November 1992 5,725,000 Depository Units ("Trust Units"), each consisting of beneficial ownership of one unit of undivided beneficial interest in the Santa Fe Energy Trust (the "Trust") and a $20 face amount beneficial ownership interest in a $1,000 face amount zero coupon United States Treasury obligation maturing on or about February 15, 2008, were sold in a public offering. The Trust consists of certain oil and gas properties conveyed by Santa Fe. A total of $114.5 million was received from public investors, of which $38.7 million was used to purchase the Treasury obligations and $5.7 million was used to pay underwriting commissions and discounts. Santa Fe received the remaining $70.1 million and 575,000 Trust Units. A portion of the proceeds received by the Company was used to retire $30.0 million of the debt incurred in connection with the Merger and the remainder will be used for general corporate purposes including possible acquisitions. F-10 74 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) For any calendar quarter ending on or prior to December 31, 2002, the Trust will receive additional royalty payments to the extent that it needs such payments to distribute $0.40 per Depository Unit per quarter. The source of such additional royalty payments, if needed, will be limited to the Company's remaining royalty interest in certain of the properties conveyed to the Trust. If such additional payments are made, certain proceeds otherwise payable to the Trust in subsequent quarters may be reduced to recoup the amount of such additional payments. The aggregate amount of the additional royalty payments (net of any amounts recouped) will be limited to $20.0 million on a revolving basis. At December 31, 1993 the Company held 575,000 Trust Units. At December 31, 1993 Accounts Receivable includes $0.2 million due from the Trust and Accounts Payable includes $1.9 million due to the Trust. In the first quarter of 1994 the Company sold the Trust Units for $11.3 million, the Company's investment in the Trust Units, $10.4 million, is included in Assets Held for Sale at December 31, 1993. (5) ACQUISITIONS OF OIL AND GAS PROPERTIES In January 1991 the Company completed the purchase of Mission Operating Partnership, L.P.'s ("Mission") interest in certain oil and gas properties, effective from November 1, 1990, for approximately $55.0 million. The Company formed a partnership, with an institutional investor as a limited partner, to acquire and operate the properties. The investor contributed $27.5 million for a 50% interest in the partnership, which will be reduced to 15% upon the occurence of payout. Payout will occur when the investor has received distributions from the partnership totalling an amount equal to its original contribution plus a 12% rate of return on such contribution. Prior to payout, the Company will bear 100% of the capital expenditures of the partnership. Under the terms of the partnership agreement a total of $36.8 million must be expended on development of the property by the year 2000, $12.4 million of which had been expended through the end of 1993. The Company funded $16.8 million of its share of the purchase of the properties with the assumption of a term loan and paid the remainder from working capital. The Company has given the lender the equivalent of an overriding royalty interest in certain production from the properties. The royalty is payable only if such production occurs and is limited to a maximum of $3.0 million. In June 1991 the Company acquired a 10% interest in a producing field in Argentina for approximately $18.3 million and in October 1991 purchased an additional 8% interest in the field for approximately $15.7 million. The Company financed $17.8 million of the total purchase price with loans from an Argentine bank. The Company has agreed to spend approximately $16.7 million over a five-year period on development and maintenance of the field. (6) CASH FLOWS The Company considers all highly liquid investments with a maturity of three months or less when purchased to be cash equivalents. The Merger included certain non-cash investing and financing activities not reflected in the Statement of Cash Flows as follows (in millions of dollars): Common stock issued............................................. 205.5 Convertible preferred stock issued.............................. 80.0 Deferred tax liability.......................................... 19.7 Long-term debt.................................................. 140.0 Assets acquired, other than cash, net of liabilities assumed.... (457.1) ------ Cash paid....................................................... (11.9) ======
F-11 75 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In 1991, the Company sold a producing property for $0.9 million in cash and a note receivable for $1.2 million. In 1991, the Partnership purchased certain surface properties for $6.2 million, $5.5 million of which was funded by the issuance of promissory notes and the Company also purchased producing properties for $63.1 million, $34.6 million of which was funded with debt (see Notes 5 and 7). The Company made interest payments of $45.5 million, $49.0 million and $48.0 million in 1991, 1992 and 1993, respectively. In 1991, 1992 and 1993, the Company made tax payments of $18.4 million, $4.4 million and $5.0 million, respectively, and in 1993 received refunds of $4.1 million, primarily related to the audit of prior years' returns. (7) FINANCING AND DEBT Long-term debt at December 31, 1993 and 1992 consisted of (in millions of dollars):
DECEMBER 31, -------------------------------------------- 1993 1992 -------------------- -------------------- CURRENT LONG-TERM CURRENT LONG-TERM ------- --------- ------- ---------- SFER Senior Notes................................................... 30.0 310.0 25.0 340.0 Revolving and Term Credit Agreement............................ 1.3 48.7 12.8 92.2 Notes Payable to Bank.......................................... 3.8 11.3 2.5 15.1 Term.Loan...................................................... 1.2 11.4 1.2 12.6 Partnership Credit Agreement............................................... 8.0 24.0 11.1 29.5 Promissory Notes............................................... -- -- 0.8 3.4 ---- ----- ---- ----- 44.3 405.4 53.4 492.8 ==== ===== ==== =====
Aggregate total maturities of long-term debt during the next five years are as follows: 1994 -- $44.3 million; 1995 -- $78.9 million; 1996 -- $73.5 million; 1997 -- $43.0 million; and 1998 -- $35.0 million. These maturities will be affected by the refinancing discussed in Note 2 -- Corporate Restructuring Program. On April 11, 1990 SFER issued $365.0 million of serial unsecured Senior Notes with interest rates averaging 10.35%. The Note Agreement pursuant to which the Senior Notes were issued includes certain covenants which, among other things, restrict the Company's ability to incur additional indebtedness and to pay dividends. Under the terms of the Note Agreement, at December 31, 1993 the Company had the ability to incur at least $64.0 million in additional long-term debt and pay $26.0 million in dividends and other restricted payments. At December 31, 1993 $340.0 million in Senior Notes were outstanding and are to be repaid, $30.0 million in 1994 and 1995, $35.0 million in 1996 through 1998 and $25.0 million per year in 1999 through 2005. In January 1991 the Company executed a $16.8 million term.loan agreement, with interest at 9.0%, in connection with the purchase of certain producing properties from Mission. At December 31, 1993 $12.6 million was outstanding under the terms of the agreement and is to be repaid $1.2 million in 1994 and $11.4 million in 1995. The Company made principal payments on the loan totalling $1.8 million in 1991, $1.2 million in 1992 and $1.2 million in 1993. In June 1991 the Company borrowed $10.4 million from an Argentine bank in connection with the purchase of an interest in a producing oil field in Argentina. The loan bore interest at the higher of 12% or the interbank offering rate plus 2%. In October 1991 the Company borrowed an additional $7.8 million in connection with the purchase of an additional interest in the field. The second loan bore interest at the higher of rates ranging from 13.4% to 14.0% or the London Interbank Offering F-12 76 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Rate ("LIBOR") plus 2%. During 1993 the two loans were combined in a new loan which bears interest at the higher of 13.06% or LIBOR plus 2%. In connection with the Merger the Company entered into a $195.0 million Revolving and Term Credit Agreement (the "Credit Agreement") with a group of banks. Upon consummation of the Merger the Company drew down the $145.0 million available under the term loan feature of the Credit Agreement and repaid the $140.0 million of long-term debt assumed in the Merger. The borrowings under the term loan feature of the Credit Agreement are secured by properties acquired in the Merger. Interest rates on borrowings are determined from time to time and at December 31, 1993 amounts outstanding under the term loan feature bore interest at an average of 5.5% per annum. In April 1993 the term loan feature was amended to allow the Company to make voluntary prepayments and reborrowings. At December 31, 1993 the balance outstanding under the term loan feature was $50.0 million and the total amount available under the term loan feature, including amounts then outstanding, was $87.7 million. The amount available will be reduced, in semi.annual increments, to $48.6 million in December 31, 1994 and $24.3 million at December 31, 1995. The Credit Agreement expires December 31, 1996. In certain circumstances, primarily related to the sale of properties securing the loans, the amount available may be reduced or the Company may be required to make mandatory repayments. The Company is currently negotiating an amendment to the Credit Agreement which would extend the maturities and under certain circumstances increase the amount available for borrowings. Under the revolving credit feature of the Credit Agreement the Company may borrow and issue letters of credit totalling up to $50.0 million. Borrowings under the revolving credit feature are unsecured but are subject to compliance with covenants identical to existing covenants under the Company's other long-term debt agreeements including covenants related to debt incurrence, dividends and other restricted payments, investments and limitations on liens, mergers and sales of assets. In addition, the Company must comply annually with certain borrowing base coverage ratios relating to projected cash flows from oil and gas revenues. The amount available under the revolving credit feature will be reduced to $10.0 million on February 28, 1994 and this feature expires on February 28, 1995. At December 31, 1993, the Company had $8.7 million in letters of credit outstanding under the revolving credit feature of the Credit Agreement. The Company has two uncommitted lines of credit totalling $35.0 million which is used to meet short-term cash needs. Interest rates on borrowings under this line of credit is typically lower than rates paid under the Credit Agreement. At December 31, 1993 no amounts were outstanding under these lines of credit. In December 1991 the Partnership issued two promissory notes for a total of $5.5 million in connection with the purchase of certain surface lands. The notes, which bore interest at 10.0%, were retired in 1993. The Company's proportionate share of such debt at December 31, 1992 was $4.2 million. At December 31, 1993 and 1992 the Partnership had $32.0 million and $44.0 million, respectively, outstanding under the terms of long-term credit agreement which expires in 1997. The Company's proportionate share of such debt totaled $40.6 million at December 31, 1992. Interest on 65% of principal amount outstanding is fixed at 10.13% with interest on the remaining amount outstanding at floating rates which averaged 4.3% in 1993 and 5.46% in 1992. The credit agreement imposes certain restrictions on future indebtedness and the transfer or sale of principal properties and requires the maintenance of certain financial ratios to avoid collateralization or default. F-13 77 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (8) SEGMENT INFORMATION The principal business of the Company is oil and gas, which consists of the acquisition, exploration and development of oil and gas properties and the production and sale of crude oil and liquids and natural gas. Pertinent information with respect to the Company's oil and gas business is presented in the following table (in millions of dollars):
OIL AND GAS --------------------------------------------- OTHER GENERAL U.S. ARGENTINA INDONESIA FOREIGN CORPORATE TOTAL -------- --------- --------- ------- --------- --------- 1993 Revenues..................................... 401.2 12.5 23.2 -- -- 436.9 Income (Loss) from Operations................ (33.6) 3.0 (13.4) (18.4) (50.6) (113.0) Depletion, Depreciation, Amortization and Impairment................................. 218.8 3.6 21.2 6.7 1.7 252.0 Additions to Property and Equipment.......... 116.1 7.3 16.8 6.1 4.4 150.7 Identifiable Assets at December 31........... 862.0 48.2 65.3 2.8 98.6 1,076.9 1992 Revenues..................................... 400.0 13.9 13.6 -- -- 427.5 Income (Loss) from Operations................ 100.6 2.5 2.3 (10.7 ) (37.2) 57.5 Depletion, Depreciation and Amortization..... 136.7 3.7 2.7 1.6 1.6 146.3 Additions to Property and Equipment.......... 452.6 4.0 71.6 5.7 2.4 536.3 Identifiable Assets at December 31........... 1,076.5 39.2 73.9 5.8 141.8 1,337.2 1991 Revenues..................................... 376.1 3.7 -- -- -- 379.8 Income (Loss) from Operations................ 103.7 (2.2) .2 (2.5 ) (34.8) 64.4 Depletion, Depreciation and Amortization..... 101.3 1.8 -- .7 2.8 106.6 Additions to Property and Equipment.......... 125.8 35.4 -- 3.7 8.8 173.7 Identifiable Assets at December 31........... 816.5 37.5 .2 3.9 53.8 911.9
Crude oil and liquids and natural gas accounted for more than 95% of revenues in 1991, 1992 and 1993. The following table reflects sales revenues from crude oil purchasers who accounted for more than 10% of the Company's crude oil and liquids revenues (in millions of dollars):
YEAR ENDED DECEMBER 31, ------------------------- 1993 1992 1991 ---- ---- ---- Texaco Trading and Transportation, Inc................................... -- 46.8 55.9 Celeron Corporation...................................................... 56.8 56.3 45.6 Shell Oil Company........................................................ 86.3 -- --
None of the Company's purchasers of natural gas accounted for more than 10% of revenues in 1991, 1992 or 1993. The Company does not believe the loss of any purchaser would have a material adverse effect on its financial position since the Company believes alternative sales arrangements could be made on relatively comparable terms. F-14 78 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (9) CONVERTIBLE PREFERRED STOCK The convertible preferred stock issued in connection with the Merger is non-voting and entitled to receive cumulative cash dividends at an annual rate equivalent to $1.40 per share. The holders of the convertible preferred shares may, at their option, convert any or all such shares into 1.3913 shares of the Company's common stock. The Company may, at any time after the fifth anniversary of the effective date of the Merger and upon the occurrence of a "Special Conversion Event", convert all outstanding shares of convertible preferred stock into common stock at the initial conversion rate of 1.3913 shares of common stock, subject to certain adjustments, plus additional shares in respect to accrued and unpaid dividends. A Special Conversion Event is deemed to have occurred when the average daily closing price for a share of the Company's common stock for 20 of 30 consecutive trading days equals or exceeds 125% of the quotient of $20.00 divided by the then applicable conversion rate (approximately $18.00 per share at a conversion rate of 1.3913). Upon the occurrence of the "First Ownership Change" of Santa Fe, each holder of shares of convertible preferred stock shall have the right, at the holder's option, to elect to have all of such holder's shares redeemed for $20.00 per share plus accrued and unpaid interest and dividends. The First Ownership Change shall be deemed to have occurred when any person or group, together with any affiliates or associates, becomes the beneficial owner of 50% or more of the outstanding common stock of Santa Fe. (10) SHAREHOLDERS' EQUITY Common Stock In 1991, 1992 and 1993 the Company issued 1.1 million previously unissued shares of common stock in connection with certain employee benefit and compensation plans. Also in 1992, the Company issued 24.9 million previously unissued shares of common stock in connection with the Merger. The Company declared dividends to common shares of $0.16 per share in 1991 and 1992 and $0.12 per share in 1993. Preferred Stock The Board of Directors of the Company is empowered, without approval of the shareholders, to cause shares of preferred stock to be issued in one or more series, and to determine the number of shares in each series and the rights, preferences and limitations of each series. Among the specific matters which may be determined by the Board of Directors are: the annual rate of dividends; the redemption price, if any; the terms of a sinking or purchase fund, if any; the amount payable in the event of any voluntary liquidation, dissolution or winding up of the affairs of the Company; conversion rights, if any; and voting powers, if any. Accumulated Deficit At December 31, 1993 Accumulated Deficit included dividends in excess of retained earnings of $89.8 million. 1990 Incentive Stock Compensation Plan The Company has adopted the Santa Fe Energy Resources 1990 Incentive Stock Compensation Plan (the "Plan") under the terms of which the Company may grant options and awards with respect to no more than 5,000,000 shares of common stock to officers and key employees. Options granted in 1991 and prior are fully vested and expire in 2000. Options granted in 1992 have a ten year term and vest as to 33.33 percent one year after grant, as to a cumulative 66.67 F-15 79 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) percent two years after grant and as to the entire amount three years after grant. The options granted in 1993 have a ten year term and vest as to 50 percent 5 years after grant, as to a cumulative 75 percent 6 years after grant and as to the entire amount 7 years after grant. The options are exercisable on an accelerated basis beginning one year and ending three years after grant in certain circumstances. If the market value per share of the Company's common stock (sustained in all events for at least 60 days) exceeds $15, 25 percent of the options shall become exercisable; in the event the market value per share exceeds $20, 50 percent of the options shall become exercisable; and in the event the market value exceeds $25, 100 percent shall become exercisable. Unexercised options would be forfeited in the event of voluntary or involuntary termination. Vested options are exercisable for a period of one year following termination due to death, disability or retirement. In the event of termination by the Company for any reason there is no prorata vesting of unvested options. The following table reflects activity with respect to Non-Qualified Stock Options during 1991 through 1993:
OPTION OPTIONS PRICE OUTSTANDING PER SHARE ----------- ------------------ Outstanding at December 31, 1990................................ 1,803,923 $14.4375 to $24.24 Grants.......................................................... 4,500 $14.625 Cancellations................................................... (45,332) $14.4375 to $24.24 --------- Outstanding at December 31, 1991................................ 1,763,091 $14.4375 to $24.24 Grants.......................................................... 1,099,000 $ 9.5625 Cancellations................................................... (50,163) $14.4375 to $24.24 --------- Outstanding at December 31, 1992................................ 2,811,928 $ 9.5625 to $24.24 Grants.......................................................... 800,000 $ 9.5625 Cancellations................................................... (95,398) $ 9.5625 to $24.24 Exercises....................................................... (6,945) $ 9.5625 --------- Outstanding at December 31, 1993................................ 3,509,585 $ 9.5625 to $24.24 =========
At December 31, 1993 options on 780,790 shares were available for future grants. A "Phantom Unit" is the right to receive a cash payment in an amount equal to the average trading price of the shares of common stock at the time the award becomes payable. Awards are made for a specified period and are dependent upon continued employment and the achievement of performance objectives established by the Company. In December 1990 the Company awarded 211,362 Phantom Units and in December 1991 313,262 shares of restricted stock were issued in exchange for such units. Compensation expense is recognized over the period the awards are earned based on the market price of the restricted stock on the date it was issued ($8.00 per share). During 1990 and 1991 $0.2 million and $0.8 million, respectively, were charged to expense with respect to such awards. The unamortized portion of the award at December 31, 1991 ($1.4 million) was reflected in Shareholders' Equity. The consummation of the Merger resulted in a "change of control" as defined in the Plan and resulted in the vesting of the awards and $1.4 million in compensation expense was recognized in 1992. In 1993 the Company issued 6,432 shares of restricted stock to certain employees and 118,039 common shares in accordance with the terms of certain other employee compensation plans. F-16 80 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (11) PENSION AND OTHER EMPLOYEE BENEFIT PLANS Pension Plans Prior to the Spin-Off the Company was included in certain non-contributory pension plans of SFP. The Santa Fe Pacific Corporation Retirement Plan (the "SFP Plan") covered substantially all of the Company's officers and salaried employees who were not covered by collective bargaining agreements. The Santa Fe Pacific Corporation Supplemental Retirement Plan was an unfunded plan which provided supplementary benefits, primarily to senior management personnel. The Company adopted, effective as of the date of the Spin-Off, a defined benefit retirement plan (the "SFER Plan") covering substantially all salaried employees not covered by collective bargaining agreements and a nonqualified supplemental retirement plan (the "Supplemental Plan"). The Supplemental Plan will pay benefits to participants in the SFER Plan in those instances where the SFER Plan formula produces a benefit in excess of limits established by ERISA and the Tax Reform Act of 1986. Benefits payable under the SFER Plan are based on years of service and compensation during the five highest paid years of service during the ten years immediately preceding retirement. Benefits accruing to the Company's employees under the SFP Plan have been assumed by the SFER Plan. The Company's funding policy is to contribute annually not less than the minimum required by ERISA and not more than the maximum amount deductible for income tax purposes. In the fourth quarter of 1993 the Company established a new pension plan with respect to certain persons employed in foreign locations. The following table sets forth the funded status of the SFER Plan and the Supplemental Plan at December 31, 1993 and 1992 (in millions of dollars):
SFER PLAN SUPPLEMENTAL PLAN -------------------- -------------------- 1993 1992 1993 1992 -------- --------- -------- --------- Plan assets at fair value, primarily invested in common stocks and U.S. and corporate bonds..................... 30.2 28.9 -- -- Actuarial present value of projected benefit obligations: Accumulated benefit obligations Vested............................................ (30.9) (24.5) (0.6) (0.5) Nonvested......................................... (1.5) (1.4) -- -- Effect of projected future salary increases....... (8.3) (6.4) (0.3) (0.2) ----- ----- ---- ---- Excess of projected benefit obligation over plan assets.................................................. (10.5) (3.4) (0.9) (0.7) Unrecognized net loss from past experience different from that assumed and effects of changes in assumptions...... 6.4 0.7 0.3 0.2 Unrecognized net (asset) obligation being recognized over plan's average remaining service life................... (1.0) (1.1) 0.2 0.3 Additional minimum liability.............................. -- -- (0.3) (0.3) ----- ----- ---- ---- Accrued pension liability................................. (5.1) (3.8) (0.7) (0.5) ===== ===== ==== ==== Major assumptions at year-end Discount rate......................................... 7.0% 8.25% 7.0% 8.25% Long-term asset yield................................. 9.5% 9.5% 9.5% 9.5% Rate of increase in future compensation............... 5.25% 5.25% 5.25% 5.25%
F-17 81 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth the components of pension expense for the SFER Plan and Supplemental Plan for 1993, 1992 and 1991 (in millions of dollars):
SFER PLAN SUPPLEMENTAL PLAN ------------------------------- ------------------------------- 1993 1992 1991 1993 1992 1991 --------- --------- --------- --------- --------- --------- Service cost..................... 1.4 1.2 1.1 -- -- -- Interest cost.................... 2.6 2.4 2.3 0.1 0.1 0.1 Return on plan assets............ (2.7) (2.5) (2.4) -- -- -- Net amortization and deferral.... -- -- (0.1) -- -- -- ---- ---- ---- --- --- --- 1.3 1.1 0.9 0.1 0.1 0.1 ==== ==== ==== === === ===
The Company also sponsors a pension plan covering certain hourly-rated employees in California (the "Hourly Plan"). The Hourly Plan provides benefits that are based on a stated amount for each year of service. The Company annually contributes amounts which are actuarially determined to provide the Hourly Plan with sufficient assets to meet future benefit payment requirements. The following table sets forth the components of pension expense for the Hourly Plan for the years 1993, 1992 and 1991 (in millions of dollars):
YEAR ENDED DECEMBER 31, ------------------------------- 1993 1992 1991 --------- --------- --------- Service cost............................................................. 0.2 0.2 0.2 Interest cost............................................................ 0.7 0.7 0.7 Return on plan assets.................................................... (0.8) (0.1) (0.5) Net amortization and deferral............................................ 0.4 (0.4) 0.1 ---- ---- ---- 0.5 0.4 0.5 ==== ==== ====
The following table sets forth the funded status of the Hourly Plan at December 31, 1993 and 1992 (in millions of dollars):
1993 1992 ---- ---- Plan assets at fair value, primarily invested in fixed-rate securities........... 7.7 7.2 Actual present value of projected benefit obligations Accumulated benefit obligations Vested................................................................... (11.2) (9.1) Nonvested................................................................ (0.4) (0.3) ----- ---- Excess of projected benefit obligation over plan assets.......................... (3.9) (2.2) Unrecognized net (gain) loss from past experience different from that assumed and effects of changes in assumptions................................ 1.5 (0.3) Unrecognized prior service cost.................................................. 0.5 0.6 Unrecognized net obligation...................................................... 1.5 1.6 Additional minimum liability..................................................... (3.5) (2.1) ----- ---- Accrued pension liability.................................................... (3.9) (2.4) Major assumptions at year-end ===== ==== Discount rate................................................................ 7.0% 8.25% Expected long-term rate of return on plan assets............................. 8.5% 8.5 %
At December 31, 1993 the Company's additional minimum liability exceeded the total of its unrecognized prior service cost and unrecognized net obligation by $1.5 million. Accordingly, at F-18 82 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) December 31, 1993 the Company's retained earnings have been reduced by such amount, net of related taxes of $0.6 million. Postretirement Benefits Other Than Pensions The Company provides health care and life insurance benefits for substantially all employees who retire under the provisions of a Company-sponsored retirement plan and their dependents. Participation in the plans is voluntary and requires a monthly contribution by the employee. Effective January 1, 1993 the Company adopted the provisions of SFAS No. 106 -- "Employers' Accounting for Postretirement Benefits Other Than Pensions". The Statement requires the accrual, during the years the employee renders service, of the expected cost of providing postretirement benefits to the employee and the employee's beneficiaries and covered dependents. The following table sets forth the plan's funded status at December 31, 1993 and January 1, 1993 (in millions of dollars):
DECEMBER 31, JANUARY 1, 1993 1993 ------------ ---------- Plan assets, at fair value............................................ -- -- Accumulated postretirement benefit obligation Retirees............................................................ (3.6) (3.1) Eligible active participants........................................ (1.2) (0.9) Other active participants........................................... (1.4) (1.2) ----- ---- Accumulated postretirement benefit obligation in excess of plan assets.............................................................. (6.2) (5.2) Unrecognized transition obligation.................................... 5.0 5.2 Unrecognized net loss from past experience different from that assumed and from changes in assumptions........................ 0.5 -- ----- ---- Accrued postretirement benefit cost................................... (0.7) -- ===== ==== Assumed discount rate................................................. 7.5% 8.25% Assumed rate of compensation increase................................. 5.25% 5.25%
The Company's net periodic postretirement benefit cost for 1993 includes the following components (in millions of dollars): Service costs........................................................ 0.3 Interest costs....................................................... 0.4 Amortization of unrecognized transition obligation................... 0.3 --- 1.0 ===
In periods prior to 1993 the cost to the Company of providing health care and life insurance benefits for qualified retired employees was recognized as expenses when claims were paid. Such amounts totalled $0.4 million in 1991 and $0.3 million in 1992. Estimated costs and liabilities have been developed assuming trend rates for growth in future health care costs beginning with 10% for 1993 graded to 6% (5.5% for post age 65) by the year 2000 and remaining constant thereafter. Increasing the assumed health care cost trend rate by one percent each year would increase the accumulated postretirement benefit obligation as of December 31, 1993 by $0.9 million and the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 1994 by $0.2 million. Savings Plan The Company has a savings plan, which became effective November 1, 1990, available to substantially all salaried employees and intended to qualify as a deferred compensation plan under F-19 83 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Section 401(k) of the Internal Revenue Code (the "401(k) Plan"). The Company will match employee contributions for an amount up to 4% of each employee's base salary. In addition, if at the end of each fiscal year the Company's performance for such year has exceeded certain predetermined criteria, each participant will receive an additional matching contribution equal to 50% of the regular matching contribution. The Company's contributions to the 401(k) Plan, which are charged to expense, totaled $1.2 million in 1991, $1.3 million in 1992 and $1.5 million in 1993. In the fourth quarter of 1993 the Company established a new savings plan with respect to certain personnel employed in foreign locations. Other Postemployment Benefits In the fourth quarter of 1993 the Company adopted SFAS No. 112 -- "Employers' Accounting for Postemployment Benefits". The Statement requires the accrual of the estimated costs of benefits provided by an employer to former or inactive employees after employment but before retirement. Such benefits include salary continuation, supplemental unemployment benefits, severance benefits, disability-related benefits, job training and counseling and continuation of benefits such as health care and life insurance coverage. The adoption of SFAS No. 112 resulted in a charge to earnings of $1.8 million in 1993. (12) COMMITMENTS AND CONTINGENCIES Crude Oil Hedging Program In the third quarter of 1990, the Company initiated a hedging program designed to provide a certain minimum level of cash flow from its sales of crude oil. Settlements were included in oil revenues in the period the oil is sold. In the year ended December 31, 1990 hedges resulted in a reduction in oil revenues of $10.7 million; in 1991 hedges resulted in an increase in oil revenues of $41.7 million and in 1992 hedges resulted in an increase in oil revenues of $9.7 million. The Company had no open crude oil hedging contracts during 1993. Natural Gas Hedging Program In the third quarter of 1992 the Company initiated a hedging program with respect to its sales of natural gas. The Company has used various instruments whereby monthly settlements are based on the differences between the price or range of prices specified in the instruments and the settlement price of certain natural gas futures contracts quoted on the New York Mercantile Exchange. In instances where the applicable settlement price is less than the price specified in the contract, the Company receives a settlement based on the difference; in instances where the applicable settlement price is higher than the specified prices the Company pays an amount based on the difference. The instruments utilized by the Company differ from futures contracts in that there is no contractual obligation which requires or allows for the future delivery of the product. In 1992 and 1993 hedges resulted in a reduction in natural gas revenues of $0.5 million and $8.2 million, respectively. At December 31, 1993 the Company had two open natural gas hedging contracts covering approximately 1.2 Bcf during the six month period beginning March 1994. The "approximate break-even price" (the average of the monthly settlement prices of the applicable futures contracts which would result in no settlement being due to or from the Company) with respect to such contracts is approximately $1.82 per Mcf. In addition, certain parties hold options on contracts covering approximately 4.8 Bcf during the seven month period beginning March 1994 at an approximate break even price of $1.90 per Mcf. The Company has no other outstanding natural gas hedging instruments. Indemnity Agreement With SFP At the time of the Spin-Off, the Company and SFP entered into an agreement to protect SFP from federal and state income taxes, penalties and interest that would be incurred by SFP if the F-20 84 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Spin-off were determined to be a taxable event resulting primarily from actions taken by the Company during a one-year period that ended December 4, 1991. If the Company were required to make payments pursuant to the agreement, such payments could have a material adverse effect on its financial condition; however, the Company does not believe that it took any actions during such one-year period that would have such an effect on the Spin-Off. Environmental Regulation Federal, state and local laws and regulations relating to environmental quality control affect the Company in all of its oil and gas operations. The Company has been identified as one of over 250 potentially responsible parties ("PRPs") at a superfund site in Los Angeles County, California. The site was operated by a third party as a waste disposal facility from 1948 until 1983. The Environmental Protection Agency ("EPA") is requiring the PRPs to undertake remediation of the site in several phases, which include site monitoring and leachate control, gas control and final remediation. In 1989, the EPA and a group of the PRPs entered into a consent decree covering the site monitoring and leachate control phases of remediation. The Company is a member of the group that is responsible for carrying out this first phase of work, which is expected to be completed in five to eight years. The maximum liability of the group, which is joint and several for each member of the group, for the first phase is $37.0 million, of which the Company's share is expected to be approximately $2.4 million ($1.3 million after recoveries from working interest participants in the unit at which the wastes were generated) payable over the period that the phase one work is performed. The EPA and a group of PRPs of which the Company is a member have also entered into a subsequent consent decree (which has not been finally entered by the court) with respect to the second phase of work (gas control). The liability of this group has not been capped, but is estimated to be $130.0 million. The Company's share of costs of this phase, however, is expected to be approximately of the same magnitude as that of the first phase because more parties are involved in the settlement. The Company has provided for costs with respect to the first two phases, but it cannot currently estimate the cost of any subsequent phases of work or final remediation which may be required by the EPA. In 1989, Adobe received requests from the EPA for information pursuant to Section 104(e) of CERCLA with respect to the D.L. Mud and Gulf Coast Vacuum Services superfund sites located in Abbeville, Louisiana. The EPA has issued its record of decision at the Gulf Coast Site and on February 9, 1993 the EPA issued to all PRP's at the site a settlement order pursuant to Section 122 of CERCLA. Earlier, an emergency order pursuant to Section 106 of CERLA was issued on December 11, 1992, for purposes of containment due to the Louisiana rainy season. On December 15, 1993 the Company entered into a sharing agreement with other PRP'S to participate in the final remediation of the Gulf Coast site. The Company's share of the remediation is approximately $600,000 and includes its proportionate share of those PRPs who do not have the financial resources to provide their share of the work at the site. A former site owner has already conducted remedial activities at the D.L. Mud Site under a state agency agreement. The extent, if any, of any further necessary remedial activity at the D.L. Mud Site has not been finally determined. Employment Agreements The Company has entered into employment agreements with certain key employees. The initial term of each agreement expired on December 31, 1990 and, on January 1, 1991 and beginning on each January 1 thereafter, is automatically extended for one-year periods, unless by September 30 of any year the Company gives notice that the agreement will not be extended. The term of the agreements is automatically extended for 24 months following a change of control. The consummation of the Merger constituted a change of control as defined in the agreements. F-21 85 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In the event that following a change of control employment is terminated for reasons specified in the agreements, the employee would receive: (i) a lump sum payment equal to two years' base salary; (ii) the maximum possible bonus under the terms of the Company's incentive compensation plan; (iii) a lapse of restrictions on any outstanding restricted stock grants and full payout of any outstanding Phantom Units; (iv) cash payment for each outstanding stock option equal to the amount by which the fair market value of the common stock exceeds the exercise price of the option; and, (v) life, disability and health benefits for a period of up to two years. In addition, payments and benefits under certain employment agreements are subject to further limitations based on certain provisions of the Internal Revenue Code. Interest Rate Swaps Prior to the Merger, Adobe had entered into two interest rate swaps with a bank with notional principal amounts of $15.0 mllion and $20.0 million. Under the terms of the $20.0 million swap, which expires in April 1994, during any quarterly period at the beginning of which a floating rate specified in the agreement is less than 7.84%, the Company must pay the bank interest for such period on the principal amount at the difference between the rates. Should the floating rate be in excess of 7.84%, the bank must pay the Company interest for such period on the principal amount at the difference between the rates. For the period from the effective date of the Merger to December 31, 1992 the amount due the bank in accordance with the terms of the $20.0 million swap totalled $0.6 million and the amount due the bank in 1993 totalled $0.9 million. For the quarterly period which ends in April 1994, the amount due the bank is based on a floating rate of 3.375%. The $15.0 million swap, which expired December 31, 1992, had terms similar to the $20.0 million swap and the amount due the bank for the period subsequent to the Merger totaled $0.5 million. Operating Leases The Company has noncancellable agreements with terms ranging from one to ten years to lease office space and equipment. Minimum rental payments due under the terms of these agreements are: 1994 -- $6.1 million, 1995 -- $6.0 million, 1996 -- $5.5 million, 1997 -- $5.2 million, 1998 -- $4.4 million and $4.7 million thereafter. Rental payments made under the terms of noncancellable agreements totaled $4.0 million in 1991,$4.5 million in 1992 and $5.5 million in 1993. Other Matters The Company has several long-term contracts ranging up to fifteen years for the supply and transportation of approximately 30 million cubic feet per day of natural gas. In the aggregate, these contracts involve a minimum commitment on the part of the Company of approximately $10 million per year. There are other claims and actions, including certain other environmental matters, pending against the Company. In the opinion of management, the amounts, if any, which may be awarded in connection with any of these claims and actions could be significant to the results of operations of any period but would not be material to the Company's consolidated financial position. (13) INCOME TAXES Effective January 1, 1993 the Company adopted the provisions of Statement of Financial Accounting Standards No. 109 -- "Accounting for Income Taxes". The adoption of SFAS No. 109 had no significant impact on the Company's provision for income taxes. Through the date of the Spin-Off the taxable income or loss of the Company was included in the consolidated federal income tax return filed by SFP. The Company has filed separate consolidated federal income tax returns for periods subsequent to the Spin-Off. The consolidated federal income F-22 86 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) tax returns of SFP have been examined through 1988 and all years prior to 1981 are closed. Issues relating to the years 1981 through 1985 are being contested through various stages of administrative appeal. The Company is evaluating its position with respect to issues raised in a 1986 through 1988 audit. The Company believes adequate provision has been made for any adjustments which might be assessed for all open years. During 1989, the Company received a notice of deficiency for certain state franchise tax returns filed for the years 1978 through 1983 as part of the consolidated tax returns of SFP. The years subsequent to 1983 are still subject to audit. At December 31, 1993 Other Long-Term Obligations includes $20.6 million with respect to this matter. The Company intends to contest this matter. With the Merger of Adobe the Company succeeded to a net operating loss carryforward that is subject to Internal Revenue Code Section 382 limitations which annually limit taxable income that can be offset by such losses. Certain changes in the Company's shareholders may impose additional limitations as well. Losses carrying forward of $133.3 million expire beginning in 1998. At date of the Merger, Adobe had ongoing tax litigation related to a refund claim for carryback of certain net operating losses denied by the Internal Revenue Service. During 1991 Adobe successfully defended its claim in Federal District Court and prevailed again in 1992 in the United States Court of Appeals for the Fifth Circuit. The Internal Revenue Service had no further recourse to litigation and a $16.2 million refund was reflected as Income Tax Refund Receivable at December 31, 1992 and collected in 1993. Pretax income from continuing operations for the years ended December 31, 1993, 1992 and 1991 was taxed under the following jurisdictions:
1993 1992 1991 ------- ------ ----- Domestic............................................................... (120.9) 2.7 34.8 Foreign................................................................ (29.3) (3.6) (2.1) ------ ---- ---- (150.2) (0.9) 32.7 ====== ==== ====
The Company's income tax expense (benefit) for the years ended December 31, 1993, 1992 and 1991 consisted of (in millions of dollars):
1993 1992 1991 ------ ----- ---- Current U.S. federal........................................................... (1.3) 3.5 11.0 State.................................................................. (1.2) 1.4 1.7 Foreign................................................................ 1.3 1.9 -- ---- ---- ---- (1.2) 6.8 12.7 ----- ---- ---- Deferred U.S. federal........................................................... (65.6) (3.5) 0.2 U.S. federal tax rate change........................................... 2.6 -- -- State.................................................................. (8.0) (2.5) 1.3 Foreign................................................................ (0.9) (0.3) -- ----- ---- ---- (71.9) (6.3) 1.5 ----- ---- ---- (73.1) 0.5 14.2 ===== ==== ====
F-23 87 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The Company's deferred income tax liabilities (assets) at December 31, 1993 and 1992 are composed of the following differences between financial and tax reporting (in millions of dollars):
1993 1992 ----- ----- Capitalized costs and write-offs.............................................. 83.0 150.8 Differences in Partnership basis.............................................. 15.1 29.3 State deferred liability...................................................... 5.8 13.4 Foreign deferred liability.................................................... 13.7 15.5 ----- ----- Gross deferred liabilities.................................................... 117.6 209.0 ----- ----- Accruals not currently deductible for tax purposes............................ (17.7) (28.3) Alternative minimum tax carryforwards......................................... (8.3) (5.3) Net operating loss carryforwards.............................................. (46.7) (56.4) Other......................................................................... (0.5) -- ----- ----- Gross deferred assets......................................................... (73.2) (90.0) ----- ----- Deferred tax liability........................................................ 44.4 119.0 ===== =====
The Company had no deferred tax asset valuation allowance at December 31, 1993 or 1992. A reconciliation of the Company's U.S. income tax expense (benefit) computed by applying the statutory U.S. federal income tax rate to the Company's income (loss) before income taxes for the years ended December 31, 1993, 1992 and 1991 is presented in the following table (in millions of dollars):
1993 1992 1991 ------ ----- ---- U.S. federal income taxes (benefit) at statutory rate................ (52.6) (0.3) 11.1 Increase (reduction) resulting from: State income taxes, net of federal effect.......................... (1.0) 1.4 2.2 Foreign income taxes in excess of U.S. rate........................ (0.8) 0.3 -- Nondeductible amounts.............................................. (0.2) (2.4) -- Effect of increase in statutory rate on deferred taxes............. 2.6 -- -- Federal audit refund............................................... (3.2) -- -- Amendment to tax sharing agreement with SFP........................ (1.2) -- -- Benefit of tax losses.............................................. (11.2) -- -- Prior period adjustments........................................... (5.5) -- -- Other.............................................................. -- 1.5 0.9 ----- ---- ---- (73.1) 0.5 14.2 ===== ==== ====
The Company increased its deferred tax liability in 1993 as a result of legislation enacted during 1993 increasing the corporate tax rate from 34% to 35% commencing in 1993. (14) FAIR VALUE OF FINANCIAL INSTRUMENTS SFAS No. 107 "Disclosure About Fair Value of Financial Instruments" requires the disclosure, to the extent practicable, of the fair value of financial instruments which are recognized or unrecognized in the balance sheet. The fair value of the financial instruments disclosed herein is not representative of the amount that could be realized or settled, nor does the fair value amount consider the tax consequences, if any, of realization or settlement. The following table reflects the F-24 88 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) financial instruments for which the fair value differs from the carrying amount of such financial instrument in the Company's December 31, 1993 and 1992 balance sheets (in millions of dollars):
1993 1992 ------------------- ------------------- CARRYING FAIR CARRYING FAIR AMOUNT VALUE AMOUNT VALUE -------- ----- -------- ----- Assets Trust Units.................................... 10.4 11.3 10.4 10.5 Liabilities Long-Term Debt (including current portion)..................................... 449.7 482.2 546.2 572.2 Convertible Preferred Stock.................... 80.0 103.8 80.0 93.8 Interest rate swap............................. -- 0.4 -- 1.1
The fair value of the Trust Units and convertible preferred stock is based on market prices. The fair value of the Company's fixed-rate long-term debt is based on current borrowing rates available for financings with similar terms and maturities. With respect to the Company's floating-rate debt, the carrying amount approximates fair value. The fair value of the interest rate swap represents the estimated cost to the Company over the remaining life of the contract. At December 31, 1993 the Company had two open natural gas hedging contracts and options outstanding on five additional contracts (see Note 12 -- Commitments and Contingencies -- Natural Gas Hedging Contracts). Based on the settlement prices of certain natural gas futures contracts as quoted on the New York Mercantile Exchange on December 30, 1993, assuming all options are exercised, the cost to the Company with respect to such contracts during 1994 would be approximately $0.6 million. F-25 89 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) OIL AND GAS RESERVES AND RELATED FINANCIAL DATA Information with respect to the Company's oil and gas producing activities is presented in the following tables. Reserve quantities as well as certain information regarding future production and discounted cash flows were determined by independent petroleum consultants, Ryder Scott Company. Oil and Gas Reserves The following table sets forth the Company's net proved oil and gas reserves at December 31, 1990, 1991, 1992 and 1993 and the changes in net proved oil and gas reserves for the years ended December 31, 1991, 1992 and 1993.
CRUDE OIL AND LIQUIDS (MMBBLS) NATURAL GAS (BCF) -------------------------------------- ------------------------------------ U.S. ARGENTINA INDONESIA TOTAL U.S. ARGENTINA INDONESIA TOTAL ---- --------- --------- ----- ---- --------- --------- ----- Proved reserves at December 31, 1990.............................. 222.3 -- -- 222.3 185.9 -- -- 185.9 Revisions of previous estimates............... (1.9) -- -- (1.9) 0.4 -- -- 0.4 Improved recovery techniques.................. 15.9 -- -- 15.9 0.5 -- -- 0.5 Extensions, discoveries and other additions.................................... 1.8 -- -- 1.8 19.6 -- -- 19.6 Purchases of minerals-in-place................ 4.6 8.7 -- 13.3 2.5 -- -- 2.5 Sales of minerals-in-place.................... (2.4) -- -- (2.4) (5.5) -- -- (5.5) Increase in ownership in Partnership.......... 0.4 -- -- 0.4 2.2 -- -- 2.2 Production.................................... (20.0) (0.2) -- (20.2) (34.8) -- -- (34.8) ----- ---- ---- ----- ----- ---- ---- ----- Proved reserves at December 31, 1991.............................. 220.7 8.5 -- 229.2 170.8 -- -- 170.8 Revisions of previous estimates............... 14.4 (0.3) -- 14.1 7.3 -- -- 7.3 Improved recovery techniques.................. 17.0 -- -- 17.0 1.3 -- -- 1.3 Extensions, discoveries and other additions.................................... 1.3 1.3 -- 2.6 5.6 -- -- 5.6 Purchases of minerals-in-place................ 13.5 -- 7.2 20.7 141.5 -- 0.6 142.1 Sales of minerals-in-place.................... (5.7) -- -- (5.7) (5.0) -- -- (5.0) Increase in ownership in Partnership.......... 0.2 -- -- 0.2 1.6 -- -- 1.6 Production.................................... (21.4) (0.8) (0.8) (23.0) (46.2) -- -- (46.2) ----- ---- ---- ----- ----- ---- ---- ----- Proved reserves at December 31, 1992.............................. 240.0 8.7 6.4 255.1 276.9 -- 0.6 277.5 Revisions to previous estimates............... (11.9) 0.5 0.6 (10.8) 26.6 -- 0.1 26.7 Improved recovery techniques.................. 26.7 -- -- 26.7 -- -- -- -- Extensions, discoveries and other additions.................................... 3.4 0.5 2.3 6.2 29.5 26.4 -- 55.9 Purchases of minerals-in-place................ 3.2 -- 0.7 3.9 9.8 -- 0.1 9.9 Sales of minerals in place.................... (8.7) -- -- (8.7) (47.4) -- -- (47.4) Increase in ownership in Partnership.......... 0.1 -- -- 0.1 0.8 -- -- 0.8 Production.................................... (21.9) (0.9) (1.5) (24.3) (60.3) -- (0.1) (60.4) ----- ---- ---- ----- ----- ---- ---- ----- Proved reserves at December 31, 1993............................. 230.9 8.8 8.5 248.2 235.9 26.4 0.7 263.0 ===== ==== ==== ===== ===== ==== ==== =====
(Table continued on following page) F-26 90 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
CRUDE OIL AND LIQUIDS (MMBBLS) NATURAL GAS (BCF) -------------------------------------- --------------------------------------- U.S. ARGENTINA INDONESIA TOTAL U.S. ARGENTINA INDONESIA TOTAL ---- --------- --------- ------ ---- --------- --------- ----- Proved developed reserves at December 31 1990........................ 176.8 -- -- 176.8 169.4 -- -- 169.4 1991........................ 179.2 5.4 -- 184.6 154.2 -- -- 154.2 1992........................ 194.6 5.6 6.4 206.6 250.2 -- 0.6 250.8 1993........................ 178.8 5.5 6.7 191.0 206.0 -- 0.7 206.7
Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data indicate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Indonesian reserves represent an entitlement to gross reserves in accordance with a production sharing contract. These reserves include estimated quantities allocable to the Company for recovery of operating costs as well as quantities related to the Company's net equity share after recovery of costs. Accordingly, these quantities are subject to fluctuations with an inverse relationship to the price of oil. If oil prices increase, the reserve quantities attributable to the recovery of operating costs decline. Although this reduction would be offset partially by an increase in the net equity share, the overall effect would be a reduction of reserves attributable to the Company. At December 31, 1993, the quantities include 0.6 million barrels which the Company is contractually obligated to sell for $.20 per barrel. At December 31, 1993 the Company's reserves were 6.9 million barrels of crude oil and liquids and 14.5 Bcf of natural gas lower than at December 31, 1992, reflecting the sale in 1993 of properties with reserves totalling 8.7 million barrels of crude oil and liquids and 47.4 Bcf of natural gas. At December 31, 1993, 1.9 million barrels of crude oil reserves and 19.7 billion cubic feet of natural gas reserves were subject to a 90% net profits interest held by Santa Fe Energy Trust. F-27 91 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) Estimated Present Value of Future Net Cash Flows Estimated future net cash flows from the Company's proved oil and gas reserves at December 31, 1991, 1992 and 1993 are presented in the following table (in millions of dollars, except as noted):
U.S. ARGENTINA INDONESIA TOTAL ---- --------- --------- ----- 1993 Future cash inflows...................................... 2,654.9 117.9 115.6 2,888.4 Future production costs.................................. (1,547.2) (65.9) (78.7) (1,691.8) Future development costs................................. (216.7) (32.4) (8.9) (258.0) Future income tax expenses............................... (100.5) -- (6.9) (107.4) -------- ----- ----- -------- Net future cash flows................................ 790.5 19.6 21.1 831.2 Discount at 10% for timing of cash flows................. (308.5) (12.1) (8.2) (328.8) -------- ----- ----- -------- Present value of future net cash flows from proved reserves........................................ 482.0 7.5 12.9 502.4 ======== ===== ===== ======== Average sales prices Oil ($/Barrel)....................................... 9.10 9.74 13.50 Natural gas ($/Mcf).................................. 2.28 1.23 0.97 1992 Future cash inflows...................................... 3,709.8 132.9 105.8 3,948.5 Future production costs.................................. (1,982.6) (82.1) (79.5) (2,144.2) Future development costs................................. (292.2) (13.5) -- (305.7) Future income tax expenses............................... (286.9) (1.0) (9.5) (297.4) -------- ----- ----- -------- Net future cash flows................................ 1,148.1 36.3 16.8 1,201.2 Discount at 10% for timing of cash flows................. (450.5) (14.0) (3.2) (467.7) -------- ----- ----- -------- Present value of future net cash flows from proved reserves........................................ 697.6 22.3 13.6 733.5 ======== ===== ===== ======== Average sales prices Oil ($/Barrel)....................................... 13.30 15.28 16.46 Natural gas ($/Mcf).................................. 2.01 -- 0.97 1991 Future cash inflows...................................... 2,899.9 117.2 -- 3,017.1 Future production costs.................................. (1,655.3) (76.1) -- (1,731.4) Future development costs................................. (242.2) (13.7) -- (255.9) Future income tax expenses............................... (236.6) -- -- (236.6) -------- ----- ----- -------- Net future cash flows................................ 765.8 27.4 -- 793.2 Discount at 10% for timing of cash flows................. (320.0) (9.6) -- (329.6) -------- ----- ----- -------- Present value of future net cash flows from proved reserves........................................ 445.8 17.8 -- 463.6 ======== ===== ===== ======== Average sales prices Oil ($/Barrel)....................................... 11.80 13.72 -- Natural gas ($/Mcf).................................. 1.78 -- --
F-28 92 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) The following tables sets forth the changes in the present value of estimated future net cash flows from proved reserves during 1991, 1992 and 1993 (in millions of dollars):
U.S. ARGENTINA INDONESIA TOTAL ---- --------- --------- ----- 1993 Balance at beginning of year.............................. 697.6 22.3 13.6 733.5 ------ ----- ----- ------ Increase (decrease) due to: Sales of oil and gas, net of production costs of $189.5 million..................................... (230.1) (7.3) (10.0) (247.4) Net changes in prices and production costs.............. (325.1) (7.7) 1.7 (331.1) Extensions, discoveries and improved recovery........... 94.8 14.8 7.0 116.6 Purchases of minerals-in-place.......................... 20.4 -- 2.1 22.5 Sales of minerals-in-place.............................. (84.7) -- -- (84.7) Development costs incurred.............................. 50.0 5.1 -- 55.1 Changes in estimated volumes............................ 28.3 1.5 1.8 31.6 Changes in estimated development costs.................. 25.6 (24.1) (8.9) (7.4) Interest factor -- accretion of discount................ 87.1 2.3 2.1 91.5 Income taxes............................................ 112.0 0.6 3.5 116.1 Increase in ownership in Partnership.................... 1.2 -- -- 1.2 Other................................................... 4.9 -- -- 4.9 ------ ----- ----- ------ (215.6) (14.8) (0.7) (231.1) ------ ----- ----- ------ 482.0 7.5 12.9 502.4 ====== ===== ===== ======
U.S. ARGENTINA INDONESIA TOTAL ---- --------- --------- ----- 1992 Balance at beginning of year.............................. 445.8 17.8 -- 463.6 ------ ----- ----- ------ Increase (decrease) due to: Sales of oil and gas, net of production costs of $176.2 million..................................... (236.6) (8.4) (6.3) (251.3) Net changes in prices and production costs.............. 191.7 7.8 3.5 203.0 Extensions, discoveries and improved recovery........... 70.9 4.6 -- 75.5 Purchases of minerals-in-place.......................... 230.6 -- 24.1 254.7 Sales of minerals-in-place.............................. (77.7) -- -- (77.7) Development costs incurred.............................. 26.5 3.1 -- 29.6 Changes in estimated volumes............................ 63.4 (1.0) -- 62.4 Changes in estimated development costs.................. (76.9) (2.8) -- (79.7) Interest factor -- accretion of discount................ 58.7 1.8 -- 60.5 Income taxes............................................ (14.8) (0.6) (7.7) (23.1) Increase in ownership in Partnership.................... 1.9 -- -- 1.9 Other................................................... 14.1 -- -- 14.1 ------ ----- ----- ------ 251.8 4.5 13.6 269.9 ------ ----- ----- ------ 697.6 22.3 13.6 733.5 ====== ===== ===== ======
F-29 93 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
U.S. ARGENTINA INDONESIA TOTAL ---- --------- --------- ----- 1991 Balance at beginning of year.............................. 839.4 -- -- 839.4 ------ ---- ---- ------ Increase (decrease) due to: Sales of oil and gas, net of production costs of $157.6 million..................................... (221.0) (1.2) -- (222.2) Net changes in prices and production costs.............. (617.6) 7.9 -- (609.7) Extensions, discoveries and improved recovery........... 71.6 -- -- 71.6 Purchases of minerals-in-place.......................... 10.4 24.8 -- 35.2 Sales of minerals-in-place.............................. (30.7) -- -- (30.7) Development costs incurred.............................. 54.0 0.7 -- 54.7 Changes in estimated volumes............................ 2.3 -- -- 2.3 Changes in estimated development costs.................. (117.5) (14.4) -- (131.9) Interest factor -- accretion of discount................ 123.5 -- -- 123.5 Income taxes............................................ 233.5 -- -- 233.5 Increase in ownership in Partnership.................... 4.6 -- -- 4.6 Other................................................... 93.3 -- -- 93.3 ------ ---- ---- ------ (393.6) 17.8 -- (375.8) ------ ---- ---- ------ 445.8 17.8 -- 463.6 ====== ==== ==== ======
Estimated future cash flows represent an estimate of future net cash flows from the production of proved reserves using estimated sales prices and estimates of the production costs, ad valorem and production taxes, and future development costs necessary to produce such reserves. No deduction has been made for depletion, depreciation or any indirect costs such as general corporate overhead or interest expense. The sales prices used in the calculation of estimated future net cash flows are based on the prices in effect at year end. Such prices have been held constant except for known and determinable escalations. Operating costs and ad valorem and production taxes are estimated based on current costs with respect to producing oil and gas properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions. Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved. While applicable investment tax credits and other permanent differences are considered in computing taxes, no recognition is given to tax benefits applicable to future exploration costs or the activities of the Company that are unrelated to oil and gas producing activities. The information presented with respect to estimated future net revenues and cash flows and the present value thereof is not intended to represent the fair value of oil and gas reserves. Actual future sales prices and production and development costs may vary significantly from those in effect at year-end and actual future production may not occur in the periods or amounts projected. This information is presented to allow a reasonable comparison of reserve values prepared using standardized measurement criteria and should be used only for that purpose. F-30 94 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) Costs Incurred in Oil and Gas Producing Activities The following table includes all costs incurred, whether capitalized or charged to expense at the time incurred (in millions of dollars):
OTHER U.S. ARGENTINA INDONESIA FOREIGN TOTAL ------ --------- --------- ------- ----- 1993 Property acquisition costs Unproved....................................... 6.4 -- 1.8 3.8 12.0 Proved......................................... 29.7 -- 2.9 -- 32.6 Other.......................................... 0.8 -- -- -- 0.8 Exploration costs................................ 20.9 0.7 5.2 11.7 38.5 Development costs................................ 85.3 7.3 7.6 -- 100.2 ----- ---- ---- ---- ----- 143.1 8.0 17.5 15.5 184.1 ===== ==== ==== ==== ===== 1992 Property acquisition costs Unproved....................................... 29.3 0.2 8.8 3.5 41.8 Proved......................................... 294.1 -- 59.4 -- 353.5 Other.......................................... 65.6 -- -- -- 65.6 Exploration costs................................ 18.4 2.1 2.9 8.9 32.3 Development costs................................ 56.8 3.0 1.8 -- 61.6 ----- ---- ---- ---- ----- 464.2 5.3 72.9 12.4 554.8 ===== ==== ==== ==== ===== 1991 Property acquisition costs Unproved....................................... 4.4 -- -- 3.2 7.6 Proved......................................... 29.0 -- -- 34.1 63.1 Other.......................................... -- -- -- -- -- Exploration costs................................ 20.7 -- -- 4.1 24.8 Development costs................................ 85.8 -- -- 0.7 86.5 ----- ---- ---- ---- ----- 139.9 -- -- 42.1 182.0 ===== ==== ==== ==== =====
F-31 95 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) Capitalized Costs Related to Oil and Gas Producing Activities The following table sets forth information concerning capitalized costs at December 31, 1993 and 1992 related to the Company's oil and gas operations (in millions of dollars):
1993 1992 ------------------------------------------------- -------------------------------------------------- OTHER OTHER U.S. ARGENTINA INDONESIA FOREIGN TOTAL U.S. ARGENTINA INDONESIA FOREIGN TOTAL ------ --------- --------- ------- -------- ----- --------- --------- ------- ------- Oil and gas properties Unproved............ 40.3 1.3 12.0 10.7 64.3 80.1 1.3 10.2 7.3 98.9 Proved.............. 1,869.9 48.9 68.0 -- 1,986.8 2,049.8 37.5 62.7 -- 2,150.0 Other............... 13.2 -- -- -- 13.2 82.0 -- -- 82.0 Accumulated amortization of unproved properties............ (14.6) (1.2) (2.8) (9.9) (28.5) (23.6) (1.0) (1.7) (2.6) (28.9) Accumulated depletion, depreciation and impairment of proved properties............ (1,181.9) (7.9) (22.4) -- (1,212.2) (1,200.0) (4.6) (2.3) -- (1,206.9) Accumulated depreciation of other oil and gas properties (4.3) -- -- -- (4.3) (7.5) -- -- -- (7.5) -------- ---- ----- ---- -------- -------- ---- ---- ---- -------- 722.6 41.1 54.8 0.8 819.3 980.8 33.2 68.9 4.7 1,087.6 ======== ==== ===== ==== ======== ======== ==== ==== ==== ========
F-32 96 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) Results of Operations From Oil and Gas Producing Activities The following table sets forth the Company's results of operations from oil and gas producing activities for the years ended December 31, 1993, 1992 and 1991 (in millions of dollars):
OTHER U.S. ARGENTINA INDONESIA FOREIGN TOTAL ------- --------- --------- ------- --------- 1993 Revenues.................................................. 401.2 12.5 23.2 -- 436.9 Production costs.......................................... (166.9) (5.2) (13.2) -- (185.3) Oil and gas systems and pipelines......................... (4.2) -- -- -- (4.2) Exploration, including dry hole costs..................... (16.4) (0.7) (2.2) (11.7) (31.0) Depletion, depreciation, amortization and impairments..... (218.8) (3.6) (21.2) (6.7) (250.3) Restructuring charges..................................... (27.8) -- -- -- (27.8) Gain (loss) on disposition of properties.................. (0.7) -- -- -- (0.7) ------ ----- ----- ----- ------ (33.6) 3.0 (13.4) (18.4) (62.4) Income taxes.............................................. 24.1 (0.9) 1.9 -- 25.1 ------ ----- ----- ----- ------ (9.5) 2.1 (11.5) (18.4) (37.3) ====== ===== ===== ===== ====== 1992 Revenues.................................................. 400.0 13.9 13.6 -- 427.5 Production costs.......................................... (160.2) (5.5) (7.3) -- (173.0) Oil and gas systems and pipelines......................... (3.2) -- -- -- (3.2) Exploration, including dry hole costs..................... (12.9) (2.2) (1.3) (9.1) (25.5) Depletion, depreciation, amortization and impairments..... (136.7) (3.7) (2.7) (1.6) (144.7) Gain (loss) on disposition of properties.................. 13.6 -- -- -- 13.6 ------ ----- ----- ----- ------ 100.6 2.5 2.3 (10.7) 94.7 Income taxes.............................................. (37.9) -- (1.6) -- (39.5) ------ ----- ----- ----- ------ 62.7 2.5 0.7 (10.7) 55.2 ====== ===== ===== ===== ====== 1991 Revenues.................................................. 376.1 3.7 -- -- 379.8 Production costs.......................................... (155.1) (2.5) -- -- (157.6) Exploration, including dry hole costs..................... (15.5) (1.5) -- (1.7) (18.7) Depletion, depreciation, amortization and impairments..... (101.3) (1.8) -- (0.7) (103.8) Gain (loss) on disposition of properties.................. (0.5) -- -- -- (0.5) ------ ----- ----- ----- ------ 103.7 (2.1) -- (2.4) 99.2 Income Taxes.............................................. (42.3) -- -- -- (42.3) ------ ----- ----- ----- ------ 61.4 (2.1) -- (2.4) 56.9 ====== ===== ===== ===== ======
Income taxes are computed by applying the appropriate statutory rate to the results of operations before income taxes. Applicable tax credits and allowances related to oil and gas producing activities have been taken into account in computing income tax expenses. No deduction has been made for indirect cost such as corporate overhead or interest expense. F-33 97 SANTA FE ENERGY RESOURCES, INC. SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) SUMMARIZED QUARTERLY FINANCIAL DATA
1 QTR 2 QTR 3 QTR 4 QTR YEAR ----- ----- ----- ----- ---- (IN MILLIONS OF DOLLARS EXCEPT PER SHARE DATE) 1993 Revenues........................................................... 115.3 116.3 102.7 102.6 436.9 Gross profit (a)................................................... 19.0 22.5 8.5 (130.7) (80.7) Income (loss) from operations...................................... 12.0 15.4 1.2 (141.6)(b) (113.0) Net income (loss).................................................. (0.4) 4.0 2.4 (83.1) (77.1) Earnings (loss) attributable to common shares...................... (2.2) 2.3 0.6 (84.8) (84.1) Earnings (loss) attributable to common shares per share............ (0.02) 0.02 0.01 (0.95) (0.94) Average shares outstanding (millions).............................. 89.6 89.7 89.8 89.8 89.7 1992 Revenues........................................................... 78.5 97.7 127.9 123.4 427.5 Gross profit (a)................................................... 2.9 34.1 32.0 19.4 88.4 Income (loss) from operations...................................... (3.5) 25.1 24.4 11.5 57.5 Net income (loss).................................................. (8.8) 1.8 7.3 (1.7) (1.4) Earnings (loss) attributable to common shares...................... (8.8) 1.0 5.5 (3.4) (5.7) Earnings (loss) attributable to common shares per share............ (.14) .01 .06 (.04) (.07) Average shares outstanding (millions).............................. 64.3 72.7 89.4 89.5 79.0
__________ (a) Revenues less operating expenses other than general and administrative. (b) Includes charges of $99.3 million for impairment of oil and gas properties and $38.6 million for restructuring charges. F-34 98 SANTA FE ENERGY RESOURCES, INC. CONSOLIDATED STATEMENT OF OPERATIONS (UNAUDITED) (IN MILLIONS OF DOLLARS, EXCEPT PER SHARE DATA)
THREE MONTHS ENDED MARCH 31, -------------------- 1994 1993 --------- --------- Revenues Crude oil and liquids............ $ 58.6 $ 80.5 Natural gas...................... 28.1 28.6 Natural gas systems.............. -- 3.0 Crude oil marketing and trading........................ 2.7 2.3 Other............................ 0.9 0.9 --------- --------- 90.3 115.3 --------- --------- Costs and Expenses Production and operating......... 40.6 42.7 Oil and gas systems and pipelines...................... -- 1.1 Exploration, including dry hole costs.......................... 5.0 7.1 Depletion, depreciation and amortization................... 32.1 37.6 General and administrative....... 7.6 7.0 Taxes (other than income)........ 7.4 7.1 Restructuring charges............ 7.0 -- Loss (gain) on disposition of oil and gas properties............. (9.4) 0.7 --------- --------- 90.3 103.3 --------- --------- Income (Loss) from Operations........ -- 12.0 Interest income.................. 0.2 1.2 Interest expense................. (10.3) (13.7) Interest capitalized............. 0.9 1.1 Other income (expense)........... 0.9 (0.2) --------- --------- Income (Loss) Before Income Taxes.... (8.3) 0.4 Income tax benefit (expense)..... 5.8 (0.8) --------- --------- Net Income (Loss).................... (2.5) (0.4) Preferred dividend requirement....... (1.8) (1.8) --------- --------- Earnings (Loss) Attributable to Common Shares...................... $ (4.3) $ (2.2) ========= ========= Earnings (Loss) Attributable to Common Shares Per Share............ $ (0.05) $ (0.02) ========= ========= Weighted Average Number of Shares Outstanding (in millions).......... 89.9 89.6 ========= =========
The accompanying notes are an integral part of these financial statements. F-35 99 SANTA FE ENERGY RESOURCES, INC. CONSOLIDATED BALANCE SHEET (IN MILLIONS OF DOLLARS)
MARCH 31, DECEMBER 31, 1994 1993 ------------ ------------ (UNAUDITED) ASSETS Current Assets Cash and cash equivalents........ $ 3.2 $ 4.8 Accounts receivable.............. 78.4 87.4 Inventories...................... 9.7 8.7 Assets held for sale............. 49.1 59.5 Other current assets............. 11.7 12.2 ------------ ---------- 152.1 172.6 ------------ ---------- Investment in Hadson Corporation..... 57.0 56.2 ------------ ---------- Properties and Equipment, at cost Oil and gas (on the basis of successful efforts accounting).................... 2,081.0 2,064.3 Other............................ 27.0 27.3 ------------ ---------- 2,108.0 2,091.6 Accumulated depletion, depreciation, amortization and impairment..................... (1,289.8) (1,258.9) ------------ ---------- 818.2 832.7 ------------ ---------- Other Assets Receivable under gas balancing arrangements................... 4.0 3.9 Other............................ 10.9 11.5 ------------ ---------- 14.9 15.4 ------------ ---------- $ 1,042.2 $ 1,076.9 ============ ========== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities Accounts payable................. $ 85.0 $ 93.5 Interest payable................. 0.8 10.2 Current portion of long-term debt........................... 42.9 44.3 Other current liabilities........ 16.2 18.1 ------------ ---------- 144.9 166.1 ------------ ---------- Long-Term Debt....................... 403.5 405.4 ------------ ---------- Deferred Revenues.................... 8.2 8.6 ------------ ---------- Other Long-Term Obligations.......... 43.9 48.8 ------------ ---------- Deferred Income Taxes................ 41.0 44.4 Commitments and Contingencies (Note 5)........................... -- -- ------------ ---------- Convertible Preferred Stock.......... 80.0 80.0 ------------ ---------- Shareholders' Equity Preferred stock.................. -- -- Common stock..................... 0.9 0.9 Paid-in capital.................. 498.3 496.9 Unamortized restricted stock awards......................... (0.1) (0.1) Accumulated deficit.............. (178.1) (173.8) Foreign currency translation adjustment..................... (0.3) (0.3) ------------ ---------- 320.7 323.6 ------------ ---------- $ 1,042.2 $ 1,076.9 ============ ==========
The accompanying notes are an integral part of these financial statements. F-36 100 SANTA FE ENERGY RESOURCES, INC. CONSOLIDATED STATEMENT OF CASH FLOWS (UNAUDITED) (IN MILLIONS OF DOLLARS)
THREE MONTHS ENDED MARCH 31, ---------------------- 1994 1993 ---------- ---------- Operating Activities: Net income (loss)................ $ (2.5) $ (0.4) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation and amortization............... 32.1 37.6 Restructuring charges........ 1.0 -- Deferred income taxes........ (3.4) (0.4) Net loss (gain) on disposition of properties................. (9.4) 0.7 Exploratory dry hole costs...................... 0.6 1.3 Other........................ (0.1) 0.7 Changes in operating assets and liabilities: Decrease (increase) in accounts receivable........ 9.0 2.3 Decrease (increase) in income tax refund receivable...... -- 16.2 Decrease (increase) in inventories................ (1.0) (4.7) Increase (decrease) in accounts payable........... 2.8 (3.4) Increase (decrease) in interest payable........... (9.4) (8.9) Increase (decrease) in income taxes payable.............. (0.1) 1.3 Net change in other assets and liabilities............ (5.3) (0.7) ---------- ---------- Net Cash Provided by Operating Activities......................... 14.3 41.6 ---------- ---------- Investing Activities: Capital expenditures, including exploratory dry hole costs..... (30.5) (30.0) Acquisitions of producing properties, net of related debt........................... (0.6) (4.7) Net proceeds from sales of properties..................... 20.3 7.4 Increase in partnership interest due to reinvestment............ -- (0.5) ---------- ---------- Net Cash Used in Investing Activities......................... (10.8) (27.8) ---------- ---------- Financing Activities: Net change in debt............... (3.3) (30.1) Cash dividends paid.............. (1.8) (5.3) ---------- ---------- Net Cash Used in Financing Activities......................... (5.1) (35.4) ---------- ---------- Net Decrease in Cash and Cash Equivalents........................ (1.6) (21.6) Cash and Cash Equivalents at Beginning of Period................ 4.8 83.8 ---------- ---------- Cash and Cash Equivalents at End of Period............................. $ 3.2 $ 62.2 ========== ==========
The accompanying notes are an integral part of these financial statements. F-37 101 SANTA FE ENERGY RESOURCES, INC. CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY (UNAUDITED) (SHARES AND DOLLARS IN MILLIONS)
FOREIGN UNAMORTIZED CURRENCY COMMON STOCK RESTRICTED TRANSLA- TOTAL --------------- PAID-IN STOCK ACCUMULATED TION SHAREHOLDERS' SHARES AMOUNT CAPITAL AWARDS DEFICIT ADJUSTMENT EQUITY ------ ------ ------- ----------- ------------ ---------- ------------- Balance at December 31, 1993......... 89.8 $0.9 $ 496.9 $ (0.1) $ (173.8) $ (0.3) $ 323.6 Issuance of common stock........... 0.1 -- 1.4 -- -- -- 1.4 Net loss........................... -- -- -- -- (2.5) -- (2.5) Dividends declared................. -- -- -- -- (1.8) -- (1.8) ---- ---- ------- ------- --------- ------ ------- Balance at March 31, 1994............ 89.9 $0.9 $ 498.3 $ (0.1) $ (178.1) $ (0.3) $ 320.7 ==== ==== ======= ======= ========= ====== ======= Balance at December 31, 1992......... 89.5 $0.9 $ 494.3 $ (0.4) $ (78.0) $ (0.2) $ 416.6 Issuance of common stock........... 0.2 -- 1.8 -- -- -- 1.8 Amortization of restricted stock awards...................... -- -- -- 0.1 -- -- 0.1 Net loss........................... -- -- -- -- (0.4) -- (0.4) Dividends declared................. -- -- -- -- (5.3) -- (5.3) ---- ---- ------- ------- --------- ------ ------- Balance March 31, 1993............... 89.7 $0.9 $ 496.1 $ (0.3) $ (83.7) $ (0.2) $ 412.8 ==== ==== ======= ======= ========= ====== =======
The accompanying notes are an integral part of these financial statements. F-38 102 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) (1) ACCOUNTING POLICIES The unaudited consolidated financial statements of Santa Fe Energy Resources, Inc. ("Santa Fe" or the "Company") reflect, in the opinion of management, all adjustments, consisting only of normal and recurring adjustments, necessary to present fairly the Company's financial position at March 31, 1994 and the Company's results of operations and cash flows for the three-month periods ended March 31, 1994 and 1993. Interim period results are not necessarily indicative of results of operations or cash flows for a full-year period. These financial statements and the notes thereto should be read in conjunction with the Company's annual report on Form 10-K for the year ended December 31, 1993. (2) CORPORATE RESTRUCTURING PROGRAM In the fourth quarter of 1993 the Company adopted a corporate restructuring program which includes (i) the concentration of capital spending in the Company's core operating areas; (ii) the disposition of non-core assets; (iii) the elimination of the $0.04 per share quarterly common stock dividend; and (iv) an evaluation of the Company's capital and cost structures. The Company's non-core asset disposition program includes the sale of its natural gas gathering and processing assets to Hadson Corporation ("Hadson"), the sale to Vintage Petroleum, Inc. of certain southern California and Gulf Coast oil and gas producing properties and the sale to Bridge Oil (U.S.A.) Inc. of certain Mid-Continent and Rocky Mountain oil and gas producing properties and undeveloped acreage. Based on the evaluation of its capital and cost structures, the Company (i) implemented a cost reduction program which includes the reduction of its salaried work force by approximately 20%, an improvement in the efficiency of its information systems and reductions in other general and administrative costs and (ii) determined to proceed with a refinancing of certain of its long-term debt. In implementing the corporate restructuring program, in 1993 the Company recorded restructuring charges of $38.6 million comprised of (i) losses on property dispositions of $27.8 million; (ii) long-term debt repayment penalties of $8.6 million; and (iii) accruals for certain personnel benefits and related costs of $2.2 million. In the first quarter of 1994 the Company recorded additional restructuring charges of $7.0 million comprised of severance, benefits and relocation expenses associated with the cost reduction program. (3) STATEMENT OF CASH FLOWS The Company made interest and income tax payments as follows during the three months ended March 31, 1994 and 1993 (in millions of dollars):
1994 1993 ---- ---- Interest payments.................... 21.2 21.5 Income tax payments.................. 0.8 0.8
F-39 103 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) (4) INVESTMENT IN HADSON CORPORATION The following table summarizes the Company's investment in Hadson Corporation ("Hadson") and the changes in such investment during the three months ended March 31, 1994 (in millions of dollars):
INVESTMENT IN ------------------- PREFERRED COMMON STOCK STOCK TOTAL --------- ------ ----- Investment at December 31, 1993...... 48.7 7.5 56.2 Preferred dividends, paid in-kind.... 1.4 -- 1.4 Equity in loss attributable to common shares............................. -- (0.6) (0.6) ---- ---- ---- Investment at March 31, 1994......... 50.1 6.9 57.0 ==== ==== ====
The following table summarizes Hadson's results of operations for the three months ended March 31, 1994 (in millions of dollars): Revenues............................. 193.2 Expenses............................. (192.8) ------ Income before income taxes........... 0.4 Income taxes......................... -- ------ Net income........................... 0.4 Preferred dividend requirement....... (1.4) ------ Loss attributable to common shares............................. (1.0) ======
(5) COMMITMENTS AND CONTINGENCIES NATURAL GAS HEDGING PROGRAM In the third quarter of 1992 the Company initiated a hedging program with respect to its sales of natural gas. The Company has used various instruments whereby monthly settlements are based on the differences between the price or range of prices specified in the instruments and the settlement price of certain natural gas futures contracts quoted on the New York Mercantile Exchange. In instances where the applicable settlement price is less than the price specified in the contract, the Company receives a settlement based on the difference; in instances where the applicable settlement price is higher than the specified prices the Company pays an amount based on the difference. The instruments utilized by the Company differ from futures contracts in that there is no contractual obligation which requires or allows for the future delivery of the product. For the three months ended March 31, 1994 and 1993, hedges resulted in a reduction in natural gas revenues of $0.3 million and $0.8 million, respectively. The Company has open natural gas hedging contracts covering approximately 6.0 Bcf during the period March through September 1994. The "approximate break-even price" (the average of the monthly settlement prices of the applicable futures contracts which would result in no settlement being due to or from the Company) with respect to such contracts is approximately $1.89 per Mcf. The Company has no other outstanding natural gas hedging instruments. ENVIRONMENTAL REGULATION Federal, state and local laws and regulations relating to environmental quality control affect the Company in all of its oil and gas operations. The Company has been identified as one of over 250 potentially responsible parties ("PRPs") at a superfund site in Los Angeles County, California. The site was operated by a third party as a waste disposal facility from 1948 until 1983. The Environmental Protection Agency ("EPA") is requiring the PRPs to undertake remediation of the site in F-40 104 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) several phases, which include site monitoring and leachate control, gas control and final remediation. In 1989, the EPA and a group of the PRPs entered into a consent decree covering the site monitoring and leachate control phases of remediation. The Company is a member of the group that is responsible for carrying out this first phase of work, which is expected to be completed in five to eight years. The maximum liability of the group, which is joint and several for each member of the group, for the first phase is $37.0 million, of which the Company's share is expected to be approximately $2.4 million ($1.3 million after recoveries from working interest participants in the unit at which the wastes were generated) payable over the period that the phase one work is performed. The EPA and a group of PRPs of which the Company is a member have also entered into a subsequent consent decree with respect to the second phase of work (gas control). The liability of this group has not been capped, but is estimated to be $130.0 million. The Company's share of costs of this phase, however, is expected to be approximately of the same magnitude as that of the first phase because more parties are involved in the settlement. The Company has provided for costs with respect to the first two phases, but it cannot currently estimate the cost of any subsequent phases of work or final remediation which may be required by the EPA. In 1989, Adobe received requests from the EPA for information pursuant to Section 104(e) of CERCLA with respect to the D. L. Mud and Gulf Coast Vacuum Services superfund sites located in Abbeville, Louisiana. The EPA has issued its record of decision at the Gulf Coast Site and on February 9, 1993 the EPA issued to all PRP's at the site a settlement order pursuant to Section 122 of CERCLA. Earlier, an emergency order pursuant to Section 106 of CERLA was issued on December 11, 1992, for purposes of containment due to the Louisiana rainy season. On December 15, 1993 the Company entered into a sharing agreement with other PRP'S to participate in the final remediation of the Gulf Coast site. The Company's share of the remediation is approximately $600,000 and includes its proportionate share of those PRPs who do not have the financial resources to provide their share of the work at the site. A former site owner has already conducted remedial activities at the D. L. Mud Site under a state agency agreement. The extent, if any, of any further necessary remedial activity at the D. L. Mud Site has not been finally determined. The Company has received a request for information from the EPA regarding the Lee Acres Landfill CERCLA site in New Mexico. The Company advised the EPA that it was not able to locate any information indicating that it had used that facility. The Company is investigating its potential connection, if any, to this facility and is not able to estimate its share of costs, if any, for the site at this time. On April 4, 1994, the Company received a request from the EPA for information pursuant to Section 104(a) of CERCLA and a letter ordering the Company and seven other PRPs to negotiate with the EPA regarding implementation of a remedial plan for a site located in Santa Fe Springs, California. The Company owned the property on which the site is located from 1921 to 1932. After the Company sold the property, hazardous wastes were allegedly disposed there by a third party who operated a disposal site. The EPA estimates that the total past and future costs for remediation will approximate $9 million. The Company believes that it has valid defenses to liability. While it is still investigating its exposure, if any, for the remedial costs, the Company does not believe that any such costs would be material. EMPLOYMENT AGREEMENTS The Company has entered into employment agreements with certain key employees. The initial term of each agreement expired on December 31, 1990 and, on January 1, 1991 and beginning on each January 1 thereafter, is automatically extended for one-year periods, unless by September 30 of any year the Company gives notice that the agreement will not be extended. The term of the F-41 105 SANTA FE ENERGY RESOURCES, INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED) agreements is automatically extended for 24 months following a change of control. The consummation of the merger of Adobe Resources into the Company in 1992 constituted a change of control as defined in the agreements. In the event that following a change of control employment is terminated for reasons specified in the agreements, the employee would receive: (i) a lump sum payment equal to two years' base salary; (ii) the maximum possible bonus under the terms of the Company's incentive compensation plan; (iii) a lapse of restrictions on any outstanding restricted stock grants and full payout of any outstanding Phantom Units; (iv) cash payment for each outstanding stock option equal to the amount by which the fair market value of the common stock exceeds the exercise price of the option; and, (v) life, disability and health benefits for a period of up to two years. In addition, payments and benefits under certain employment agreements are subject to further limitations based on certain provisions of the Internal Revenue Code. OTHER MATTERS The Company has several long-term contracts ranging up to fifteen years for the supply and transportation of approximately 30 million cubic feet per day of natural gas. In the aggregate, these contracts involve a minimum commitment on the part of the Company of approximately $10 million per year. There are other claims and actions, including certain other environmental matters, pending against the Company. In the opinion of management, the amounts, if any, which may be awarded in connection with any of these claims and actions could be significant to the results of operations of any period but would not be material to the Company's consolidated financial position. F-42 106 NO DEALER, SALESPERSON OR ANY OTHER 10,700,000 SHARES PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN OR INCORPORATED BY REFERENCE IN THIS PROSPECTUS IN CONNECTION WITH THE OFFER MADE BY THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY SANTA FE ENERGY THE COMPANY OR ANY OF THE RESOURCES, INC. UNDERWRITERS. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL UNDER ANY CIRCUMSTANCES CREATE ANY IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER OR SOLICITATION BY ANYONE IN ANY JURISDICTION IN WHICH SUCH OFFER OR SOLICITATION IS NOT AUTHORIZED OR $.732 SERIES A IN WHICH THE PERSON MAKING SUCH OFFER CONVERTIBLE PREFERRED STOCK IS NOT QUALIFIED TO DO SO OR TO ANY PERSON TO WHOM IT IS UNLAWFUL TO (DIVIDEND ENHANCED CONVERTIBLE MAKE SUCH SOLICITATION. STOCKSM--DECSSM) ------------------- TABLE OF CONTENTS (Logo)
PAGE ---- Available Information.................. 2 Documents Incorporated by Reference.... 2 Certain Definitions.................... 2 Prospectus Summary..................... 3 Investment Considerations.............. 12 SALOMON BROTHERS INC Ratios of Earnings to Fixed Charges.... 17 Use of Proceeds........................ 17 Capitalization......................... 18 Price Range of Common Stock and LAZARD FRERES & CO. Dividends............................ 19 Selected Financial and Operating Data................................. 20 Management's Discussion and Analysis of Financial Condition and Results of PAINEWEBBER INCORPORATED Operations........................... 22 Business and Properties................ 29 Management............................. 47 Description of Capital Stock........... 50 Description of the DECS................ 55 Federal Income Tax Considerations...... 61 Underwriting........................... 62 Validity of the Securities............. 63 PROSPECTUS Experts................................ 63 Index to Financial Statements.......... F-1 DATED MAY 18, 1994
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