-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, CWodH2gjG2XB+j9yAr9htTBslB96Ybm0GZERT0qXC5o5X41fh9ywWHLaToMyME6j mPTWbgdSB6I4BFKjvUEoTg== 0000890566-95-000690.txt : 19951211 0000890566-95-000690.hdr.sgml : 19951211 ACCESSION NUMBER: 0000890566-95-000690 CONFORMED SUBMISSION TYPE: POS AM PUBLIC DOCUMENT COUNT: 3 FILED AS OF DATE: 19951208 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENRON CORP CENTRAL INDEX KEY: 0000072859 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION & DISTRIBUTION [4923] IRS NUMBER: 470255140 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: POS AM SEC ACT: 1933 Act SEC FILE NUMBER: 033-64057 FILM NUMBER: 95600159 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138536161 MAIL ADDRESS: STREET 1: PO BOX 1188 CITY: HOUSTON STATE: TX ZIP: 77002 FORMER COMPANY: FORMER CONFORMED NAME: INTERNORTH INC DATE OF NAME CHANGE: 19860429 FORMER COMPANY: FORMER CONFORMED NAME: NORTHERN NATURAL GAS CO DATE OF NAME CHANGE: 19800328 POS AM 1 POST-EFFECTIVE AMEND #1 TO FORM S-3 AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON DECEMBER 8, 1995 REGISTRATION NO. 33-64057 ============================================================================== SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 ------------------------ POST-EFFECTIVE AMENDMENT NO. 1 TO FORM S-3 REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933 ------------------------ ENRON CORP. (EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER) DELAWARE 47-0255140 (STATE OR OTHER JURISDICTION (I.R.S. EMPLOYER OF INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.) 1400 SMITH STREET, HOUSTON, TEXAS 77002 TELEPHONE NO. (713) 853-6161 (ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE, OF REGISTRANT'S PRINCIPAL EXECUTIVE OFFICES) ------------------------ JAMES V. DERRICK, JR., ESQ. SENIOR VICE PRESIDENT AND GENERAL COUNSEL ENRON CORP. 1400 SMITH STREET HOUSTON, TEXAS 77002 (713) 853-6161 (NAME, ADDRESS, INCLUDING ZIP CODE, AND TELEPHONE NUMBER, INCLUDING AREA CODE, OF AGENT FOR SERVICE) ------------------------ COPIES TO: GARY W. ORLOFF, ESQ. REX R. ROGERS, ESQ. BRACEWELL & PATTERSON, L.L.P. ASSISTANT GENERAL COUNSEL SOUTH TOWER PENNZOIL PLACE ENRON CORP. 711 LOUISIANA STREET, SUITE 2900 1400 SMITH STREET, ROOM 4842 HOUSTON, TEXAS 77002 HOUSTON, TEXAS 77002 APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as practicable after this Registration Statement becomes effective. If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. ------------------------ CALCULATION OF REGISTRATION FEE ============================================================================== PROPOSED MAXIMUM TITLE OF EACH AGGREGATE CLASS OF SECURITIES OFFERING AMOUNT OF TO BE REGISTERED PRICE(1) REGISTRATION FEE - ------------------------------------------------------------------------------ Exchangeable Notes...................... $218,625,000 $75,388(2) ============================================================================== > (1) Estimated pursuant to Rule 457 solely for the purpose of calculating the registration fee. (2) Previously paid. THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A), MAY DETERMINE. ============================================================================== 10,000,000 EXCHANGEABLE NOTES ENRON CORP. 6 1/4% EXCHANGEABLE NOTES DUE December 13, 1998 (SUBJECT TO EXCHANGE INTO SHARES OF COMMON STOCK, PAR VALUE $.01 PER SHARE, OF ENRON OIL & GAS COMPANY) ------------------------ The principal amount of each of the 6 1/4% Exchangeable Notes due December 13, 1998 (the "Exchangeable Notes") of Enron Corp. ("Enron") being offered hereby (the "Exchangeable Notes Offering") is $21.75 (the public offering price of the common stock, par value $.01 per share (the "Common Stock"), of Enron Oil & Gas Company ("EOG") in the concurrent Common Stock Offerings referred to below) (the "Initial Price"). The Exchangeable Notes will mature on December 13, 1998. Interest on the Exchangeable Notes, at the rate of 6 1/4% of the principal amount per annum, is payable quarterly in arrears on January 31, April 30, July 31, and October 31, beginning January 31, 1996. The Exchangeable Notes are not subject to redemption, defeasance or any sinking fund prior to maturity. At maturity, including as a result of acceleration or otherwise ("Maturity"), each Exchangeable Note will be mandatorily exchanged by Enron into a number of shares of EOG Common Stock (or, at Enron's option, which may be exercised with respect to all, but not less than all, outstanding Exchangeable Notes, cash with an equal value) at the Exchange Rate. The Exchange Rate is equal to, subject to certain adjustments, (a) if the Maturity Price is greater than or equal to $26.32 per share of EOG Common Stock (the "Threshold Appreciation Price"), .8264 shares of EOG Common Stock per Exchangeable Note, (b) if the Maturity Price is less than the Threshold Appreciation Price but is greater than the Initial Price, a fractional share of EOG Common Stock per Exchangeable Note so that the value thereof, determined at the Maturity Price, equals the Initial Price and (c) if the Maturity Price is less than or equal to the Initial Price, one share of EOG Common Stock per Exchangeable Note. The "Maturity Price" means the average Closing Price (as defined herein) per share of EOG Common Stock for the 20 Trading Days (as defined herein) immediately prior to Maturity. Accordingly, the amount received upon exchange may be less than the principal amount of the Exchangeable Note, in which case an investment in the Exchangeable Notes will result in a loss. The Exchangeable Notes will be unsecured obligations of Enron ranking PARI PASSU with all of its other unsecured and unsubordinated indebtedness. At September 30, 1995, Enron had $2.32 billion of outstanding debt which is PARI PASSU to the Exchangeable Notes and its subsidiaries had $755 million of outstanding debt ($246 million of the subsidiaries' outstanding debt is guaranteed by Enron). The right of Enron, and hence the right of creditors of Enron (including the holders of the Exchangeable Notes), to participate in any distribution of assets of any subsidiary of Enron upon its liquidation or reorganization will be subject to the prior claims of creditors of such subsidiary, except to the extent that the claims of Enron itself as a creditor of such subsidiary may be recognized. See "Capitalization". Enron may only exercise its option to pay outstanding Exchangeable Notes in cash from the proceeds of its sale of Enron common stock. EOG will have no obligations with respect to the Exchangeable Notes. See "Description of the Exchangeable Notes". Concurrently with the Exchangeable Notes Offering, Enron is offering 27,000,000 shares of EOG Common Stock (31,050,000 shares if the Underwriters' over-allotment options are exercised in full in such offerings) in concurrent U.S. and international offerings (collectively, the "Stock Offerings"). The consummation of the Exchangeable Notes Offering is not contingent upon the consummation of the Stock Offerings or vice versa. Assuming the Underwriters' over-allotment options in the Exchangeable Notes Offering and the Stock Offerings are exercised in full and the maximum number of shares of EOG Common Stock is delivered upon mandatory exchange of the Exchangeable Notes at Maturity, Enron, which currently owns 80% of the outstanding shares of EOG Common Stock, would own approximately 54% of the outstanding EOG Common Stock. Attached hereto as Appendix A and included as part of this Prospectus is a prospectus of EOG covering the shares of EOG Common Stock which may be received by a holder of Exchangeable Notes at Maturity. The EOG prospectus relates to an aggregate of 11,000,000 shares of EOG Common Stock. For a discussion of certain United States federal income tax consequences for holders of Exchangeable Notes, see "Certain United States Federal Income Tax Considerations". The Exchangeable Notes have been approved for listing on the New York Stock Exchange ("NYSE") under the symbol "EXG", subject to official notice of issuance. EOG Common Stock (including the shares which may be received by a holder of Exchangeable Notes at Maturity) is listed on the NYSE under the symbol "EOG". PROSPECTIVE INVESTORS ARE ADVISED TO CONSIDER CAREFULLY THE INFORMATION CONTAINED UNDER "RISK FACTORS RELATING TO EXCHANGEABLE NOTES" BEGINNING ON PAGE 5. ------------------------ 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. ------------------------ INITIAL PUBLIC UNDERWRITING PROCEEDS TO OFFERING PRICE(1) DISCOUNT(2) ENRON(1)(3) ------------------ ------------ ----------- Per Exchangeable Note..... $21.75 $.66 $21.09 Total (4)................. $217,500,000 $6,600,000 $210,900,000 - ------------ (1) Plus accrued interest, if any, from December 13, 1995. (2) Enron and EOG have agreed to indemnify the Underwriters against certain liabilities, including liabilities under the Securities Act of 1933. (3) Before deducting expenses payable by Enron, estimated to be $425,000. (4) Enron has granted the Underwriters an option for 30 days to purchase up to an additional 1,000,000 Exchangeable Notes at the initial public offering price, less the underwriting discount, solely to cover over-allotments. If such over-allotment option is exercised in full, the total initial public offering price, underwriting discount and proceeds to Enron will be $239,250,000, $7,260,000 and $231,990,000, respectively. See "Underwriting". ------------------------ The Exchangeable Notes offered hereby are offered severally by the Underwriters, as specified herein, subject to receipt and acceptance by them, and subject to their right to reject any order in whole or in part. It is expected that the Exchangeable Notes will be ready for delivery in New York, New York, on or about December 13, 1995. GOLDMAN, SACHS & CO. MERRILL LYNCH & CO. SALOMON BROTHERS INC ------------------------ The date of this Prospectus is December 8, 1995. AVAILABLE INFORMATION Enron, a Delaware corporation, is subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance therewith files reports, proxy statements and other information with the Securities and Exchange Commission (the "Commission"). Such reports, proxy statements and other information can be inspected and copied at the public reference facilities maintained by the Commission at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549; and at the following Regional Offices of the Commission: Midwest Regional Office, Citicorp Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661-2511; and Northeast Regional Office, Seven World Trade Center, Suite 1300, New York, New York 10048. Copies of such material can also be obtained from the Public Reference Section of the Commission at 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549, at prescribed rates. Enron's Common Stock and Cumulative Second Preferred Convertible Stock are listed on the New York and Midwest Stock Exchanges, and Enron's Common Stock is also listed on the Pacific Stock Exchange. Reports, proxy statements and other information concerning Enron can be inspected and copied at the respective offices of these exchanges at 20 Broad Street, New York, New York 10005; 120 South LaSalle Street, Chicago, Illinois 60603; and 301 Pine Street, San Francisco, California 94014. This Prospectus constitutes a part of a Registration Statement on Form S-3 (together with all amendments and exhibits thereto, the "Registration Statement") filed with the Commission under the Securities Act of 1933, as amended (the "Securities Act"), with respect to the Exchangeable Notes. This Prospectus does not contain all of the information set forth in such Registration Statement, certain parts of which are omitted in accordance with the rules and regulations of the Commission. Reference is made to such Registration Statement and to the exhibits relating thereto for further information with respect to Enron and the Exchangeable Notes. Any statements contained herein concerning the provisions of any document filed as an exhibit to the Registration Statement or otherwise filed with the Commission or incorporated by reference herein are not necessarily complete, and in each instance reference is made to the copy of such document so filed for a more complete description of the matter involved. Each such statement is qualified in its entirety by such reference. ------------------------ INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The following documents filed with the Commission by Enron (File No. 1-3423) pursuant to Section 13(a) of the Exchange Act are incorporated herein by reference: (a) Annual Report on Form 10-K for the year ended December 31, 1994; (b) Quarterly Report on Form 10-Q for the quarter ended March 31, 1995; (c) Quarterly Report on Form 10-Q for the quarter ended June 30, 1995; and (d) Quarterly Report on Form 10-Q for the quarter ended September 30, 1995 Each document filed by Enron 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 Exchangeable Notes pursuant hereto shall be deemed to be incorporated herein by reference and to be a part hereof from the date of filing of such document. Any statement contained herein or in a document all or a portion of which is incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained herein or in any other subsequently filed document which also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. Enron will provide without charge to each person to whom a copy of this Prospectus is delivered, on the request of any such person, a copy of any or all of the foregoing documents incorporated herein by reference other than exhibits to such documents (unless such exhibits are specifically incorporated by reference into the documents that this Prospectus incorporates). Requests should be directed to Secretary Division, Enron Corp., at its principal executive offices, 1400 Smith Street, Houston, Texas 77002 (telephone: 713-853-6161). ------------------------ IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE EXCHANGEABLE NOTES OR THE EOG 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, IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. 2 PROSPECTUS SUMMARY THE FOLLOWING IS A SUMMARY OF CERTAIN INFORMATION CONTAINED IN THIS PROSPECTUS. IT IS NOT INTENDED TO BE COMPLETE AND IS QUALIFIED IN ITS ENTIRETY BY THE MORE DETAILED INFORMATION CONTAINED ELSEWHERE IN THIS PROSPECTUS. CAPITALIZED TERMS WHICH ARE NOT DEFINED IN THIS SUMMARY ARE USED AS DEFINED ELSEWHERE IN THIS PROSPECTUS. ENRON CORP. Enron, organized in 1930, is an integrated natural gas company with headquarters in Houston, Texas. Essentially all of Enron's operations are conducted through its subsidiaries and affiliates which are principally engaged in the gathering, transportation and wholesale marketing of natural gas to markets throughout the United States and internationally through approximately 44,000 miles of natural gas pipelines; the exploration for and production of natural gas and crude oil in the United States and internationally; the production, purchase, transportation and worldwide marketing of natural gas liquids and refined petroleum products; the independent (i.e., non-utility) development, promotion, construction and operation of power plants, natural gas liquids facilities and pipelines in the United States and internationally; and the non-price regulated purchasing and marketing of energy related commitments. ENRON OIL & GAS COMPANY EOG, together with its subsidiaries, is one of the largest independent (non-integrated) oil and gas companies in the United States in terms of domestic proved reserves. It is engaged, directly and through its subsidiaries, in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad and India, and to a lesser extent, selected other international areas. THE EXCHANGEABLE NOTES OFFERING EXCHANGEABLE NOTES OFFERED.... 10,000,000 Exchangeable Notes. PRINCIPAL AMOUNT.............. $21.75 per Exchangeable Note. STATED MATURITY............... December 13, 1998. INTEREST RATE................. 6 1/4% per annum, or $.34 per Exchangeable Note per quarter, payable quarterly in arrears. INTEREST PAYMENT DATES........ January 31, April 30, July 31, and October 31, beginning January 31, 1996. EXCHANGE AT MATURITY.......... At Maturity, the principal amount of each Exchangeable Note will be mandatorily exchanged by Enron into a number of shares of EOG Common Stock (or, at Enron's option, which may be exercised with respect to all, but not less than all, of the outstanding Exchangeable Notes, cash with an equal value) at the Exchange Rate. The Exchange Rate is equal to, subject to certain adjustments, (a) if the Maturity Price is greater than or equal to the Threshold Appre- ciation Price, .8264 shares of EOG Common Stock per Exchangeable Note, (b) if the Maturity Price is less than the Threshold Appreciation Price but is greater than the Initial Price, a fractional share of EOG Common Stock per Exchangeable Note so that the value thereof (determined at the Maturity Price) equals the Initial Price and (c) if the Maturity Price is less than or equal to the Initial Price, one share of EOG Common Stock per Exchangeable Note. The "Maturity Price" means the average Closing Price per share of EOG Common Stock for the 20 Trading Days immediately prior to Maturity. Accordingly, holders of the Exchangeable Notes will not necessarily receive an amount equal to the principal 3 amount thereof. The Exchangeable Notes are not exchangeable for EOG Common Stock at the option of the holder. Enron may only exercise its option to pay outstanding Exchangeable Notes in cash from the proceeds of its sale of Enron common stock. See "Description of the Exchangeable Notes-- General." NO REDEMPTION OR SINKING FUND. The Exchangeable Notes are not subject to redemption, defeasance or any sinking fund prior to Maturity. RANKING........................ The Exchangeable Notes will be unsecured obligations of Enron ranking PARI PASSU with all of its other unsecured and unsubordinated indebtedness. RELATIONSHIP OF EXCHANGEABLE NOTES TO EOG COMMON STOCK... The Exchangeable Notes will bear interest at 6 1/4% per annum, a yield substantially in excess of the 0.6% anticipated dividend yield of EOG Common Stock based on the Initial Price of $21.75 and the current quarterly dividend payable on EOG Common Stock. However, the opportunity for equity appreciation afforded by an investment in the Exchangeable Notes is less than the opportunity for equity appreciation afforded by an investment in EOG Common Stock because the amount receivable by a holder of an Exchangeable Note upon exchange at Maturity will only exceed the principal amount of such Exchangeable Note if the Maturity Price exceeds the Threshold Appreciation Price (which represents an appreciation of 21% over the Initial Price). Moreover, holders of the Exchangeable Notes will only be entitled to receive upon exchange at Maturity 82.64% (the percentage equal to the Ini- tial Price divided by the Threshold Appreciation Price) of any appreciation of the value of EOG Common Stock in excess of the Threshold Appreciation Price. Holders of the Exchangeable Notes will not be entitled to any rights with respect to EOG Common Stock (including, without limitation, voting rights and rights to receive any dividends or other distributions in respect thereof) until such time, if any, as Enron shall have exchanged shares of EOG Common Stock for Exchangeable Notes at Maturity thereof and unless the applicable record date, if any, for the exercise of such rights occurs after such exchange. USE OF PROCEEDS............... The net proceeds will be added to Enron's general funds and are expected to be used to retire existing indebtedness and for general corporate purposes. See "Use of Proceeds." RELATIONSHIP BETWEEN ENRON AND EOG..................... Enron currently owns 80% of the outstanding shares of EOG Common Stock. Assuming the Underwriters' over-allotment options in this offering and the concurrent Stock Offerings are exercised in full and the maximum number of shares of EOG Common Stock is delivered upon the mandatory exchange of the Exchangeable Notes at Maturity, Enron would own approximately 54% of the outstanding shares of EOG Common Stock. See "Relationship Between Enron and EOG." 4 RISK FACTORS RELATING TO EXCHANGEABLE NOTES As described in more detail below, the trading price of the Exchangeable Notes may vary considerably prior to Maturity due to, among other things, fluctuations in the price of EOG Common Stock and other events that are difficult to predict and beyond Enron's control. COMPARISON TO OTHER DEBT SECURITIES; RELATIONSHIP OF EXCHANGEABLE NOTES TO EOG COMMON STOCK The terms of the Exchangeable Notes differ from those of ordinary debt securities in that the amount that a holder of the Exchangeable Notes will receive upon mandatory exchange at Maturity is not fixed, but is based on the price of the EOG Common Stock as specified in the Exchange Rate. There can be no assurance that the amount received by such holder upon exchange at Maturity (whether in stock or cash) will be equal to or greater than the principal amount of an Exchangeable Note because the price of the EOG Common Stock is subject to market fluctuations, and the value of the EOG Common Stock (or, at the option of Enron, the amount of cash) received by a holder of an Exchangeable Note upon exchange at Maturity, determined as described herein, may be more or less than the principal amount of the Exchangeable Note. For example, if the Maturity Price of the EOG Common Stock is less than the Initial Price, the amount received upon exchange will be less than the principal amount paid for the Exchangeable Note, in which case an investment in Exchangeable Notes will result in a loss. In addition, the opportunity for equity appreciation afforded by an investment in the Exchangeable Notes is less than the opportunity for equity appreciation afforded by an investment in the EOG Common Stock because the amount received by a holder of an Exchangeable Note upon exchange at Maturity will only exceed the principal amount of such Exchangeable Note if the Maturity Price exceeds the Threshold Appreciation Price (which represents an appreciation of 21% over the Initial Price). Holders of the Exchangeable Notes will only be entitled to receive upon exchange at Maturity 82.64% of any appreciation of the value of EOG Common Stock in excess of the Threshold Appreciation Price. It is impossible to predict whether the price of EOG Common Stock will rise or fall. Trading prices of EOG Common Stock will be influenced by EOG's operational results and by complex and interrelated political, economic, financial and other factors that can affect natural gas and crude oil commodity markets generally. See the prospectus relating to EOG and to EOG Common Stock attached hereto as Appendix A and included as part of this Prospectus. In addition, in the event Enron does not exercise its option to deliver cash, holders of the Exchangeable Notes will not be entitled to any rights with respect to the EOG Common Stock (including, without limitation, voting rights and rights to receive any dividends or other distributions in respect thereof) until such time as Enron shall have exchanged shares of EOG Common Stock for Exchangeable Notes at Maturity thereof and unless the applicable record date, if any, for the exercise of such rights occurs after such exchange. The Exchangeable Notes will be unsecured obligations of Enron ranking PARI PASSU with all of its other unsecured and unsubordinated indebtedness. The terms of the Exchangeable Notes do not limit the amount of indebtedness which may be incurred by Enron. DILUTION OF EOG COMMON STOCK The amount that holders of the Exchangeable Notes are entitled to receive upon the mandatory exchange at Maturity is subject to adjustment for certain events arising from stock splits and combinations, stock dividends and certain other actions of EOG that modify its capital structure. See "Description of the Exchangeable Notes -- Dilution Adjustments." The amount to be received by holders of Exchangeable Notes upon mandatory exchange at Maturity may not be adjusted for other events, such as offerings of EOG Common Stock for cash or in connection with acquisitions, that 5 may adversely affect the price of the EOG Common Stock and, because of the relationship of such amount to be received upon exchange to the price of EOG Common Stock, such other events may adversely affect the trading price of the Exchangeable Notes. There can be no assurance that EOG will not make offerings of EOG Common Stock or take other action in the future. POSSIBLE ILLIQUIDITY OF THE SECONDARY MARKET It is not possible to predict how the Exchangeable Notes will trade in the secondary market or whether such market will be liquid or illiquid. Exchangeable Notes are novel securities and there is currently no secondary market for the Exchangeable Notes. The Underwriters currently intend, but are not obligated, to make a market in the Exchangeable Notes. There can be no assurance that a secondary market will develop or, if a secondary market does develop, that it will provide the holders of the Exchangeable Notes with liquidity of investment or that it will continue for the life of the Exchangeable Notes. The Exchangeable Notes have been approved for listing on the NYSE, subject to official notice of issuance. However, there can be no assurance that the Exchangeable Notes will not later be delisted or that trading in the Exchangeable Notes on the NYSE will not be suspended. If the Exchangeable Notes are not listed or traded on any securities exchange or trading market, or if trading of the Exchangeable Notes is suspended, pricing information for the Exchangeable Notes may be more difficult to obtain, and the liquidity of the Exchangeable Notes may be adversely affected. NO OBLIGATION ON THE PART OF EOG WITH RESPECT TO THE EXCHANGEABLE NOTES EOG has no obligations with respect to the Exchangeable Notes or amounts to be paid to holders thereof, including any obligation to take the needs of holders of the Exchangeable Notes into consideration for any reason. EOG will not receive any of the proceeds of the offering of the Exchangeable Notes made hereby and is not responsible for the determination of the timing of, prices for or quantities of the Exchangeable Notes to be issued or the determination or calculation of the amount to be paid upon mandatory exchange at Maturity. TAX UNCERTAINTIES The Indenture (as defined herein) requires that any holder subject to U.S. federal income tax include currently in income, for U.S. federal income tax purposes, payments denominated as interest that are made with respect to the Exchangeable Notes, in accordance with such holder's method of accounting, and the amount of original issue discount ("OID"), if any, attributable to the Exchangeable Notes as it accrues. The Indenture also requires holders to treat the Exchangeable Notes as a unit consisting of (i) an exchange note, which is a debt obligation with a fixed principal amount unconditionally payable at Maturity equal to the principal amount of the Exchangeable Notes, and (ii) a forward purchase contract pursuant to which the holder agrees to use the principal payment due on the Exchangeable Notes to purchase at Maturity the EOG Common Stock that the holder is entitled to receive at that time (subject to Enron's right to deliver cash in lieu of the EOG Common Stock). It is contemplated that, upon a holder's sale or other disposition of the Exchangeable Notes prior to Maturity, the amount realized will be allocated between these two components of the Exchangeable Notes on the basis of their then relative fair market values. Because of an absence of authority as to the proper characterization of the Exchangeable Notes for tax purposes, these tax characterizations and results are uncertain. This uncertainty extends to characterization of any gain or loss recognized with respect to the Exchangeable Notes at Maturity as capital gain or loss or ordinary income or loss and, in the event Enron delivers EOG Common Stock at Maturity, as to whether any gain or loss can be deferred until a sale or disposition of such stock. As a result of these uncertainties, Enron has not received an opinion of counsel with respect to the specific tax consequences of owning or disposing of the Exchangeable Notes. See "Certain United States Federal Income Tax Considerations." 6 ENRON CORP. Enron, a Delaware corporation organized in 1930, is an integrated natural gas company with headquarters in Houston, Texas. Essentially all of Enron's operations are conducted through its subsidiaries and affiliates which are principally engaged in the gathering, transportation and wholesale marketing of natural gas to markets throughout the United States and internationally through approximately 44,000 miles of natural gas pipelines; the exploration for and development and production of natural gas and crude oil in the United States and internationally; the production, purchase, transportation and worldwide marketing of natural gas liquids and refined petroleum products; the independent (i.e., non-utility) development, promotion, construction and operation of power plants, natural gas liquids facilities and pipelines in the United States and internationally; and the non-price regulated purchasing and marketing of energy related commitments. TRANSPORTATION AND OPERATION. Enron's operations include the interstate and intrastate transmission of natural gas, construction, management and operation of natural gas and natural gas liquids pipelines, liquids plants, clean fuel plants and power facilities. Enron and its subsidiaries operate domestic interstate pipelines extending from Texas to the Canadian border and across the southern United States from Florida to California. Included in Enron's domestic interstate natural gas pipeline operations are Northern Natural Gas Company ("Northern"), Transwestern Pipeline Company ("Transwestern"), and Florida Gas Transmission Company ("Florida Gas") (indirectly 50% owned by Enron), and all such pipelines are subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission. Each pipeline serves customers in a specific geographical area: Northern, the upper Midwest; Florida Gas, the State of Florida; and Transwestern, principally the California market. In addition, Enron holds a 13% interest in Northern Border Partners, L.P., which owns a 70% interest in the Northern Border Pipeline system. An Enron subsidiary operates the Northern Border Pipeline system, which transports gas from western Canada to delivery points in the midwestern United States. Also, Enron has an approximate 15% interest in Enron Liquids Pipeline, L.P., which is engaged in pipeline transportation of natural gas liquids, refined petroleum products and carbon dioxide, operates coal terminalling, gas processing and natural gas liquids fractionation facilities, and is operated by a wholly owned subsidiary of Enron. DOMESTIC GAS AND POWER SERVICES. Enron Capital & Trade Resources Corp. and its affiliated companies ("ECT") purchase natural gas, natural gas liquids and power through a variety of contractual arrangements, including both short- and long-term contracts, the arrangement of production payment and other financing transactions, and other contractual arrangements. ECT markets these energy products to local distribution companies, electric utilities, cogenerators, and both commercial and industrial end-users. ECT also provides price risk management services in connection with natural gas, gas liquids and power transactions through both physical delivery and financial arrangements. ECT offers a broad range of non-price regulated natural gas merchant services by tailoring a variety of supply and marketing options to its customers' specific needs. ECT's strategy is to provide predictable pricing, reliable delivery and low cost capital to its customers. ECT provides these services through a variety of instruments, including forward contracts, swap agreements and other contractual commitments. Certain Enron subsidiaries are engaged domestically in the extraction of natural gas liquids (ethane, propane, normal butane, isobutane and natural gasoline), which are typically extracted from natural gas in liquid form under low temperature and high pressure conditions. Ethane, propane, normal butane, isobutane and natural gasoline are used as feedstocks for petrochemical plants in the production of plastics, synthetic rubber and other products. Normal butane and natural gasoline are used by refineries in the blending of motor gasoline. Isobutane is used in the alkylation process to enhance the octane content of motor gasoline and is also used in the production of MTBE, which is used to produce cleaner burning motor gasoline. Propane is used as fuel for home heating and 7 cooking, crop drying and industrial facilities and as an engine fuel for vehicles, and ethane is used as a feedstock for synthetic fuels production. INTERNATIONAL GAS AND POWER SERVICES. Enron's international activities principally involve the independent (non-utility) development, acquisition, promotion and operation of natural gas and power projects and the marketing of natural gas liquids. As is the case in the United States, Enron's emphasis is on businesses in which natural gas or its components play a significant role. Development projects are focused on power plants, gas processing and terminalling facilities, and gas pipelines, while marketing activities center on fuels used by or transported through such facilities. Enron's international activities include management of direct and indirect ownership interests in and operation of power plants in England, Germany, Guatemala and the Philippines; a pipeline system in southern Argentina; retail gas and propane sales in the Caribbean basin; processing of natural gas liquids at Teesside, England; and marketing of natural gas liquids worldwide. Enron is also involved in power and pipeline projects in varying stages of development in China, the Dominican Republic, Colombia, Turkey, Bolivia, Brazil, Indonesia and elsewhere. Enron Global Power & Pipelines L.L.C., a Delaware limited liability company ("EPP"), was formed in November 1994 by Enron to own and manage Enron's operating power plant and natural gas pipeline business conducted outside the United States, Canada and Western Europe, and to expand such business through acquisitions. EPP's initial assets consist of interests contributed by Enron in two power plants in the Philippines (with 226 megawatts of aggregate net generating capacity), a power plant in Guatemala (with 110 megawatts of net generating capacity) and a 6,548 kilometer (4,069 mile) natural gas pipeline system in Argentina. The public offering of common shares of EPP was completed in November 1994. Enron owns approximately 52% of the common shares of EPP. Enron formed EPP to attract public equity capital to emerging market infrastructure projects, to enable public investors to better evaluate and participate directly in the growth of Enron's operating power plant and natural gas pipeline activities in emerging markets and to generate additional capital for Enron to reinvest in future development efforts and for other corporate purposes. EXPLORATION AND PRODUCTION. Substantially all of Enron's natural gas and crude oil exploration and production operations are conducted by its subsidiary EOG. EOG is engaged in the exploration for, and development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad, India and to a lesser extent, selected other international areas. At December 31, 1994, EOG had estimated net proved natural gas reserves of 1,910 billion cubic feet and estimated net proved crude oil, condensate and natural gas liquids reserves of 37 million barrels, and at such date, approximately 70% of EOG's reserves (on a natural gas equivalent basis) was located in the United States, 16% in Canada, 11% in Trinidad and 3% in India. A limited partnership in which ECT owns a 50% general partner interest has entered into an agreement to acquire a controlling interest in Coda Energy, Inc. ("Coda"). Coda is engaged in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in North Texas and Oklahoma. Crude oil accounts for approximately 86% of Coda's proved reserves. At December 31, 1994, Coda reported estimated proved natural gas reserves of 39,808 million cubic feet ("MMcf") and estimated proved crude oil, condensate and natural gas liquids reserves of 39,207 thousand barrels ("MBbls"). See "Relationship Between Enron and EOG -- Conflicts of Interest." RECENT EVENTS In connection with a Power Purchase Agreement dated December 8, 1993, as amended, between Dabhol Power Company, Enron's 80%-owned subsidiary, and the Maharashtra State Electricity Board (the "MSEB"), Dabhol Power Company has been developing Phase I (approximately 695 megawatts) of a 2,015 megawatt electricity generating power plant south of Bombay, State of Maharashtra, India (the "Project"). Financial closing occurred and Project construction 8 began on March 1, 1995. After construction had begun, and following elections to the Maharashtra Legislative Assembly, a new coalition government took office in the State of Maharashtra. The new coalition government appointed a review committee to study the Project, and on August 3, 1995, announced the State government's intention to terminate the Project. Work on the Project was ordered stopped by the MSEB, and construction ceased on August 8, 1995. Enron believes that such actions were in clear violation of the contract and in response to these actions, Dabhol Power Company is pursuing two courses of action. First, pursuant to Dabhol Power Company's remedies in the agreements with the State government, arbitration has commenced in London against the State government for the actions it has taken to terminate the Project. Dabhol Power Company seeks to recover all of its construction and other expenses, in addition to lost profits. The arbitration tribunal has been appointed and one arbitration hearing has occurred in London. Second, Dabhol Power Company has both orally and in writing communicated to the Maharashtra State government its desire to go forward with construction of the Project and its willingness to resolve any outstanding issues, and discussions to resolve outstanding issues have begun. Although the outcome of neither the arbitration nor the renegotiation process can be predicted with certainty, based on currently available information, Enron believes that the ultimate outcome of the Project will not have a materially adverse effect on its financial position. In March 1993, Enron entered into long-term gas contracts with Phillips Petroleum Company United Kingdom Limited, British Gas Exploration and Production Limited and Agip (U.K.) Limited to purchase all of the future gas production from the J-Block field which is located in the North Sea offshore the United Kingdom (the "J-Block Contracts"). Such agreements provide for Enron to take or pay for the gas at a fixed price (with possible escalations throughout the contract period). Gas paid for, but not taken, may be recovered in later contract years. The J-Block Contracts provide for a first delivery date of not later than October 1, 1996. The contract price for such natural gas is in excess of current spot market prices in the United Kingdom. In September 1995, Enron announced that, in accordance with its contractual rights, it had notified the J-Block sellers that Enron's nominations for gas from the J-Block field were estimated to be zero from the first delivery date through September 30, 1997. In addition, in accordance with its contractual rights, Enron has made no estimated nominations for J-Block gas to date under the J-Block Contracts for the contract year ending September 30, 1998. Enron continues its good faith efforts to develop mutually beneficial solutions regarding pricing terms so that production from J-Block can begin as soon as possible. Enron believes that there are many commercial reasons for the parties to resolve any contract issues, but efforts have not been successful to date. Enron has advised the J-Block sellers that it intends to assert all legal rights, exercise all available commercial flexibility and pursue all available commercial and legal remedies under the J-Block Contracts, and stands ready and able to perform all legal obligations under the J-Block Contracts, including potential prepayments for gas to be taken in later years. The long-term market demand for J-Block gas supply remains favorable and Enron anticipates being able to meet all of its various short- and long-term market commitments. Although no assurances can be given, based upon the foregoing and other information currently available, Enron does not at this time anticipate that the J-Block Contracts will have a materially adverse effect on Enron's financial position. 9 SELECTED FINANCIAL DATA OF ENRON The financial information set forth below has been derived from the audited and unaudited consolidated financial statements of Enron. The information should be read in connection with, and is qualified in its entirety by reference to, Enron's financial statements and notes thereto incorporated by reference herein. See "Incorporation of Certain Documents by Reference." The interim data reflects all adjustments which, in the opinion of the management of Enron, are necessary to present fairly such information for the interim periods. The results of operations for the nine-month periods are not necessarily indicative of the results expected for a full year or any other interim period.
NINE MONTHS YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30, ----------------------------------------------------- -------------------- 1990 1991 1992 1993 1994 1994 1995 --------- --------- --------- --------- --------- --------- --------- (IN MILLIONS) INCOME STATEMENT DATA: Revenues............................. $ 5,460 $ 5,698 $ 6,415 $ 7,985 $ 8,984 $ 6,397 $ 6,639 Costs and expenses Cost of gas and other products sold........................... 3,528 3,646 4,222 5,567 6,517 4,631 4,726 Operating expenses............... 861 914 936 1,057 1,033 714 751 Amortization of deferred contract reformation costs.............. 102 125 101 89 91 65 19 Oil and gas exploration costs.... 68 59 59 76 84 58 61 Depreciation, depletion and amortization................... 356 366 376 458 441 328 321 Taxes, other than income taxes... 82 75 101 108 102 78 85 --------- --------- --------- --------- --------- --------- --------- 4,997 5,185 5,795 7,355 8,268 5,874 5,963 --------- --------- --------- --------- --------- --------- --------- Operating income..................... 463 513 620 630 716 523 676 Other income and deductions Equity in earnings of unconsolidated subsidiaries....................... 56 55 56 73 112 74 49 Other, net........................... 143 147 91 95 116 112 116 --------- --------- --------- --------- --------- --------- --------- Income before interest, minority interest and income taxes.......... 662 715 767 798 944 709 841 Interest and related charges, net.... 395 373 330 300 273 202 214 Dividends on preferred stock of subsidiary company................. -- -- -- 2 20 14 24 Minority interest.................... 7 7 18 28 31 21 34 Income taxes......................... 58 103 90 135 167 127 180 --------- --------- --------- --------- --------- --------- --------- Income before extraordinary items.... 202 232 329 333 453 345 389 Extraordinary items.................. -- -- (23) -- -- -- -- --------- --------- --------- --------- --------- --------- --------- Net income(1)........................ 202 232 306 333 453 345 389 Preferred stock dividends............ 25 25 22 17 15 11 11 --------- --------- --------- --------- --------- --------- --------- Earnings on Common Stock............. $ 177 $ 207 $ 284 $ 316 $ 438 $ 334 $ 378 ========= ========= ========= ========= ========= ========= =========
DECEMBER 31, ----------------------------------------------------- SEPTEMBER 30, 1990 1991 1992 1993 1994 1995 --------- --------- --------- --------- --------- --------------- (IN MILLIONS) BALANCE SHEET DATA: Total assets......................... $ 9,849 $ 10,070 $ 10,312 $ 11,504 $ 11,966 $ 13,029 Short-term debt...................... -- -- -- -- -- -- Long-term debt (including amounts reclassified from short-term debt).............................. 2,983 3,109 2,459 2,661 2,805 3,425 Preferred stock of subsidiary company............................ -- -- -- 214 377 396 Minority interest.................... 97 101 179 196 290 316 Shareholders' equity................. 1,838 1,901 2,518 2,623 2,880 3,107
- ------------ (1) Net income for the year ended December 31, 1993 includes a primarily non-cash charge of $54 million to adjust for the increase in the corporate federal income tax rate from 34 percent to 35 percent. 10 CAPITALIZATION The following table sets forth the capitalization of Enron and its consolidated subsidiaries as of September 30, 1995, and as adjusted to give effect to the issuance on October 11, 1995 of $100 million aggregate principal amount of 6 7/8% Notes due 2007, and the issuance of the Exchangeable Notes offered hereby and, in each case, the use of the proceeds therefrom. ACTUAL AS ADJUSTED ------------- ------------ (IN THOUSANDS) Short-term debt Notes payable................... $ -- $ -- Current maturities of long-term debt............................ -- -- ------------- ------------ Total short-term debt...... -- -- ------------- ------------ Long-term debt Enron: Amount reclassified from short-term debt............... 587,032 277,566 Notes due 1996-2023 (6 3/4% to 10.75%)....................... 1,753,139 1,753,139 Exchangeable Notes due 1998 (6 1/4%)...................... -- 217,500 Notes due 2007 (6 7/8%)......... -- 100,000 Subsidiary companies: Notes due 1998-2005 (4.52% to 9.2%)......................... 636,000 636,000 Notes due 1998-1999 (floating rates)........................ 55,000 55,000 Other........................... 53,674 53,674 Enron: Senior subordinated debentures due 2005-2012 (6.75%-8.25%)... 350,000 350,000 Unamortized debt discount and premium......................... (9,641) (9,875) ------------- ------------ Total long-term debt....... 3,425,204 3,433,004 ------------- ------------ Minority interests................... 315,821 315,821 ------------- ------------ Preferred stock of subsidiary companies.......................... 395,750 395,750 ------------- ------------ Shareholders' equity Convertible preferred stock..... 138,605 138,605 Common stock.................... 25,373 25,373 Additional paid-in capital...... 1,792,544 1,792,544 Retained earnings............... 1,574,335 1,574,335 Cumulative foreign currency translation adjustment........ (149,570) (149,570) Common stock held in treasury... (62,827) (62,827) Other, including Flexible Equity Trust......................... (210,969) (210,969) ------------- ------------ Total shareholders' equity................... 3,107,491 3,107,491 ------------- ------------ Total capitalization.. $ 7,244,266 $ 7,252,066 ============= ============ 11 RELATIONSHIP BETWEEN ENRON AND EOG OWNERSHIP OF COMMON STOCK Through its ability to elect all directors of EOG, Enron has the ability to control all matters relating to the management of EOG, including any determination with respect to acquisition or disposition of EOG assets, future issuance of Common Stock or other securities of EOG and any dividends payable on the Common Stock. Enron also has the ability to control EOG's exploration, development, acquisition and operating expenditure plans. The sale by Enron of EOG Common Stock pursuant to the Stock Offerings will cause Enron's ownership interest in EOG to fall below 80% with the result that EOG will cease to be included in the consolidated federal income tax return filed by Enron. There is no agreement between Enron and EOG that would prevent Enron from acquiring additional shares of Common Stock of EOG. CONTRACTUAL ARRANGEMENTS EOG entered into a Services Agreement (the "Services Agreement") with Enron effective January 1994, pursuant to which Enron provides various services, such as maintenance of certain employee benefit plans, provision of telecommunications and computer services, lease of office space and the provision of purchasing and operating services and certain other corporate staff and support services. Such services historically have been supplied to EOG by Enron, and the Services Agreement provides for the further delivery of such services substantially identical in nature and quality to those services previously provided. EOG has agreed to a fixed rate for the rental of office space and to reimburse Enron for all other direct costs incurred in rendering services to EOG under the contract and to pay Enron for allocated indirect costs incurred in rendering such services up to a maximum of $6.7 million for 1994, such cap to be increased in subsequent years for inflation and certain changes in EOG's allocation bases with any increase not to exceed 7.5% per year. Approximately $6.6 million was paid under the Services Agreement by EOG to Enron in 1994. The Services Agreement is for an initial term of five years through December 1998 and will continue thereafter until terminated by either party. In March 1995, in a series of transactions with Enron and an affiliate of Enron, EOG exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with the Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements (the "Swap Agreements") of equivalent value. As a result of the transactions, EOG has been relieved of all performance obligations associated with the Cogen Contracts. EOG will realize net operating revenues and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999 under the terms of the Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received. The net of this series of transactions will result in increases in net operating revenues and cash receipts for EOG during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. EOG has been included in the consolidated federal income tax return filed by Enron as the common parent for itself and its subsidiaries and affiliated companies, excluding any foreign subsidiaries. Consistent therewith and pursuant to a Tax Allocation Agreement between EOG, EOG's subsidiaries and Enron, either Enron has paid to EOG and each subsidiary an amount equal to the tax benefit realized in the Enron consolidated federal income tax return resulting from the utilization of EOG's or the subsidiary's net operating losses and/or tax credits, or EOG and each subsidiary has paid to Enron an amount equal to the federal income tax computed on its separate taxable income less the tax benefits associated with any net operating losses and/or tax credits generated by EOG or the subsidiary which were utilized in the Enron consolidated return. Enron has paid EOG and each subsidiary for the tax benefits associated with their net operating losses and tax credits utilized in the Enron consolidated return, provided that a tax benefit was realized except as discussed below, even if such benefits could not have been used by EOG or the subsidiary on a separately filed tax return. EOG entered into an agreement with Enron providing for EOG to be paid for all realizable benefits associated with tight gas sand federal income tax credits concurrent with tax reporting and settlement for the periods in which they were generated. The Tax Allocation 12 Agreement applies to EOG and each of its subsidiaries for all years in which EOG or any of its subsidiaries are or were included in the Enron consolidated return. To the extent a state or other taxing jurisdiction requires or permits a consolidated, combined, or unitary tax return to be filed and such return includes EOG or any of its subsidiaries, the principles expressed with respect to consolidated federal income tax allocation shall apply. The Tax Allocation Agreement will cease to be effective from the time at which deconsolidation occurs. EOG and Enron have entered into a new tax agreement pursuant to which, among other things, Enron has agreed (in exchange for the payment of $8.0 million by EOG) to be liable for, and to indemnify EOG against, all federal income taxes and state taxes measured by net income imposed on EOG for periods through the date Enron reduces its ownership in EOG to less than 80%. Enron and EOG do not believe that the cessation of consolidated tax reporting and effectiveness of the Tax Allocation Agreement concurrently with deconsolidation or the terms of the new tax agreement will have a material adverse effect on the financial condition or results of operations of either Enron or EOG. CONFLICTS OF INTEREST The nature of the respective businesses of EOG and Enron and its affiliates is such as to potentially give rise to conflicts of interest between the two companies. Conflicts could arise, for example, with respect to transactions involving purchases, sales and transportation of natural gas and other business dealings between EOG and Enron and its affiliates, potential acquisitions of businesses or oil and gas properties, the issuance of additional shares of voting securities, the election of directors or the payment of dividends by EOG. Circumstances may also arise that would cause Enron to engage in the exploration for and/or development and production of natural gas and crude oil in competition with EOG. For example, opportunities might arise which would require financial resources greater than those available to EOG, which are located in areas or countries in which EOG does not intend to operate or which involve properties that EOG would be unwilling to acquire. Also, Enron might acquire a competing oil and gas business as part of a larger acquisition. In addition, as part of Enron's strategy of securing supplies of natural gas or capital, Enron may from time to time acquire producing properties or interests in entities owning producing properties, and thereafter engage in exploration, development and production activities with respect to such properties or indirectly engage in such activities through such companies. Enron subsidiaries provide or arrange financing, including debt or equity financing, for exploration and production companies that compete with EOG. In connection with such activities, Enron affiliates may make investments in the debt or equity of such companies. There are currently no such transactions under consideration that would result in voting control by Enron or any of its affiliates, other than the transaction described in the next paragraph. In its financing activities Enron or any entity in which it has an interest may also make loans secured by oil and gas properties or securities of oil and gas companies, may acquire production payments or may receive interests in oil and gas properties as equity components of lending transactions. As a result of its lending activities, Enron may also acquire oil and gas properties or companies upon foreclosure of secured loans or as part of a borrower's rearrangement of its obligations. Such acquisition, exploration, development and production activities may directly or indirectly compete with EOG's business. There can be no assurance that Enron will not engage, directly or indirectly through entities other than EOG, in the natural gas and crude oil exploration, development and production business in competition with EOG. Joint Energy Development Investments Limited Partnership ("JEDI"), a limited partnership in which ECT owns a 50% general partner interest, has entered into an agreement to acquire a controlling interest in Coda. Coda is engaged in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in North Texas and Oklahoma. Crude oil accounts for approximately 86% of Coda's proved reserves. At December 31, 1994, Coda reported estimated proved natural gas reserves of 39,808 MMcf and estimated proved crude oil, condensates and natural gas liquids reserves of 39,207 MBbls. Enron anticipates that the transaction will be consummated in early 1996, subject to Coda stockholder approval and other conditions. Conflicts may arise between Coda and EOG, and if the acquisition of Coda occurs Enron will be required to resolve such conflicts in a manner that is consistent with its fiduciary and contractual duties to other 13 investors in Coda and JEDI and its fiduciary duties to EOG. ECT has entered into an agreement with JEDI and other investors in Coda designed to minimize certain conflicts of interest that may arise and providing, among other things, that EOG has no obligation to offer any business opportunities to Coda. EOG and Enron and its affiliates have in the past entered into significant intercompany transactions and agreements incident to their respective businesses, and EOG and Enron and its affiliates may be expected to enter into material transactions and agreements from time to time in the future. Such transactions and agreements have related to, among other things, the purchase and sale of natural gas and crude oil, the financing of exploration and development efforts by EOG, and the provision of certain corporate services. Enron believes that its existing transactions and agreements with EOG have been at least as favorable to Enron as could be obtained from third parties, and Enron intends that the terms of any future transactions and agreements between Enron and EOG and its affiliates will be at least as favorable to Enron as could be obtained from third parties. USE OF PROCEEDS The net proceeds from the sale of the Exchangeable Notes will be added to Enron's general funds and are expected to be used to retire existing indebtedness and for general corporate purposes. At December 6, 1995 the weighted average interest rate on such indebtedness was approximately 6.0%. RATIO OF ENRON'S EARNINGS TO FIXED CHARGES
YEAR ENDED DECEMBER 31, NINE MONTHS ----------------------------------------------------- ENDED 1990 1991 1992 1993 1994 SEPTEMBER, 1995 --------- --------- --------- --------- --------- ------------------- Ratio of Earnings to Fixed Charges... 1.58 1.66 1.74 1.98 2.40 2.87
The ratio of earnings to fixed charges is based on continuing operations. "Earnings" represent the aggregate of (a) the pre-tax income of Enron and its majority owned subsidiaries, (b) Enron's share of pre-tax income of its 50% owned companies, (c) any income actually received from less than 50% owned companies, and (d) fixed charges, net of interest capitalized. "Fixed Charges" represent interest (whether expensed or capitalized), amortization of debt discount and expense and that portion of rentals considered to be representative of the interest factor. PRICE RANGE OF EOG COMMON STOCK AND CASH DIVIDENDS The following table sets forth, for the periods indicated, the high and low sale prices per share for the EOG Common Stock, as reported on the New York Stock Exchange Composite Tape, and the amount of cash dividends paid per share. The 1993 and First and Second Quarter 1994 sales prices and cash dividends per share have been restated to reflect the two-for-one stock split on May 31, 1994. PRICE RANGE -------------------- CASH HIGH LOW DIVIDENDS --------- --------- ---------- 1993 First Quarter................... $ 20.31 $ 13.38 $.03 Second Quarter.................. 22.50 17.88 .03 Third Quarter................... 26.81 19.88 .03 Fourth Quarter.................. 27.00 17.06 .03 1994 First Quarter................... $ 23.75 $ 19.31 $.03 Second Quarter.................. 24.63 22.38 .03 Third Quarter................... 23.00 18.50 .03 Fourth Quarter.................. 22.75 17.38 .03 1995 First Quarter................... $ 24.88 $ 17.12 $.03 Second Quarter.................. 24.75 20.25 .03 Third Quarter................... 25.38 20.00 .03 Fourth Quarter (through December 7, 1995)............. 22.75 18.75 The last reported sale price of the EOG Common Stock on December 7, 1995 as reported on the New York Stock Exchange Composite Tape was $22. 14 As of November 1, 1995, there were approximately 270 record holders of EOG's Common Stock, including individual participants in security position listings. There are an estimated 5,100 beneficial owners of EOG's Common Stock, including shares held in street name. Following the initial public offering and sale of its Common Stock in October 1989, EOG paid quarterly dividends of $0.025 per share beginning with an initial dividend paid in January 1990 with respect to the fourth quarter of 1989. Beginning in January 1993 with respect to the fourth quarter of 1992, EOG has paid quarterly dividends of $0.03 per share. The determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration and development expenditure opportunities and future business prospects of EOG. Enron makes no representation as to the amount of dividends, if any, that EOG will pay in the future. In any event, holders of the Exchangeable Notes will not be entitled to receive any dividends that may be payable on the EOG Common Stock until such time as Enron, if it so elects, delivers EOG Common Stock at Maturity of the Exchangeable Notes and the record date for such dividend occurs after such exchange. See "Description of the Exchangeable Notes." DESCRIPTION OF THE EXCHANGEABLE NOTES The Exchangeable Notes are one series of debt securities to be issued under an Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank, as trustee, as supplemented by a First Supplemental Indenture dated as of December 1, 1995, between Enron and Harris Trust and Savings Bank, as trustee (the "Trustee") (the Indenture dated as of November 1, 1985, as supplemented from time to time, the "Indenture"). All references herein to "Indenture Securities" shall refer to debt securities issued under the Indenture. The following summary of certain provisions of the Indenture does not purport to be complete and is qualified in its entirety by reference to the Indenture, a copy of which is filed as an exhibit to the Registration Statement of which this Prospectus is a part. All capitalized terms have the meanings specified in the Indenture. GENERAL The aggregate number of Exchangeable Notes to be issued will be 10,000,000, plus such additional number of Exchangeable Notes as may be issued pursuant to the over-allotment option granted by Enron to the Underwriters (see "Underwriting"). The Stated Maturity of the Exchangeable Notes is December 13, 1998. The Indenture does not limit the amount of Indenture Securities which may be issued thereunder. The Exchangeable Notes will be unsecured and will rank on a parity with all other unsecured and unsubordinated indebtedness of Enron. The right of Enron, and hence the right of creditors of Enron (including the holders of the Exchangeable Notes), to participate in any distribution of assets of any subsidiary of Enron upon its liquidation or reorganization will be subject to the prior claims of creditors of such subsidiary, except to the extent that the claims of Enron itself as a creditor of such subsidiary may be recognized. Each Exchangeable Note, which will be issued with a principal amount of $21.75, will bear interest at the rate of 6 1/4% of the principal amount per annum (or $1.36 per annum) from December 13, 1995, or from the most recent Interest Payment Date (as defined below) to which interest has been paid or provided for until the principal amount thereof is exchanged at Maturity pursuant to the terms of the Exchangeable Notes. Interest on the Exchangeable Notes will be payable quarterly in arrears on January 31, April 30, July 31, and October 31, commencing January 31, 1996, (each, an "Interest Payment Date"), to the persons in whose names the Exchangeable Notes are registered at the close of business on the January 15, April 15, July 15, and October 15 immediately preceding such Interest Payment Date; provided that interest payable at Maturity is payable to the person to whom the principal is payable. Interest on the Exchangeable Notes will be computed on the basis of a 360-day year of twelve 30-day months. If an Interest Payment Date falls on a day that is not a Business Day (as defined below) the interest payment to be made on such Interest Payment Date will be made on the next succeeding Business Day with the same force and effect as if made on such Interest Payment Date, and no additional interest will accrue as a result of such delayed payment. 15 At Maturity, the principal amount of each Exchangeable Note will be mandatorily exchanged by Enron into a number of shares of EOG Common Stock at the Exchange Rate (as defined below) or, at Enron's option with respect to all, but not less than all, of the Exchangeable Notes, cash with an equal value. Accordingly, Holders of the Exchangeable Notes will not necessarily receive an amount equal to the principal amount thereof. The "Exchange Rate" is equal to, subject to adjustment as a result of certain dilution events (see "Dilution Adjustments" below), (a) if the Maturity Price (as defined below) of EOG Common Stock is greater than or equal to $26.32 per share of EOG Common Stock (the "Threshold Appreciation Price"), .8264 shares of EOG Common Stock per Exchangeable Note, (b) if the Maturity Price is less than the Threshold Appreciation Price but is greater than the Initial Price, a fractional share of EOG Common Stock per Exchangeable Note so that the value thereof (determined at the Maturity Price) is equal to the Initial Price and (c) if the Maturity Price is less than or equal to the Initial Price, one share of EOG Common Stock per Exchangeable Note. No fractional shares of EOG Common Stock will be issued at Maturity as provided under "Fractional Shares" below. Notwithstanding the foregoing, Enron may, at its option, deliver cash at Maturity in lieu of delivering shares of EOG Common Stock, in an amount equal to the value of such number of shares of EOG Common Stock at the Maturity Price. Such option, if exercised, must be exercised with respect to all of the outstanding Exchangeable Notes. If Enron elects to deliver cash in lieu of shares of EOG Common Stock upon the mandatory exchange of the Exchangeable Notes, on or prior to seven Business Days preceding the Stated Maturity, Enron will so notify the Trustee and publish a notice to that effect in a daily newspaper of national circulation. If Enron elects to deliver shares of EOG Common Stock, Holders of the Exchangeable Notes will be responsible for the payment of any and all brokerage costs upon the Holder's subsequent sale of such stock. The "Maturity Price" is defined as the average Closing Price per share of EOG Common Stock for the 20 Trading Days immediately prior to (but not including) Maturity. The "Closing Price" of any security on any date of determination means the closing sale price (or, if no closing price is reported, the last reported sale price) of such security on the NYSE on such date or, if such security is not listed for trading on the NYSE on any such date, as reported in the composite transactions for the principal United States securities exchange on which such security is so listed, or if such security is not so listed on a United States national or regional securities exchange, as reported by the National Association of Securities Dealers, Inc. Automated Quotation System, or, if such security is not so reported, the last quoted bid price for such security in the over-the-counter market as reported by the National Quotation Bureau or similar organization, or, if such bid price is not available, the market value of such security on such date as determined by a nationally recognized independent investment banking firm retained for this purpose by Enron. A "Trading Day" is defined as a Business Day on which the security the Closing Price of which is being determined (A) is not suspended from trading on any national or regional securities exchange or association or over-the-counter market at the close of business and (B) has traded at least once on the national or regional securities exchange or association or over-the-counter market that is the primary market for the trading of such security. "Business Day" means any day that is not a Saturday or Sunday or a day on which the NYSE, banking institutions or trust companies in The City of New York are authorized or obligated by law or executive order to close. The Indenture pursuant to which the Exchangeable Notes are issued contains a covenant by Enron to the effect that should Enron exercise its option to pay all outstanding Exchangeable Notes in cash, such cash must be provided by the proceeds from a sale by Enron of its common stock. Such sale of common stock by Enron must have occurred not more than 540 days prior to the notice by Enron to Holders of Exchangeable Notes of its election to deliver cash in lieu of EOG Common Stock. 16 For illustrative purposes only, the following chart shows the number of shares of EOG Common Stock or the amount of cash that a Holder of Exchangeable Notes would receive for each Exchangeable Note at various Maturity Prices. The table assumes that there will be no adjustments to the Exchange Rate described under "-- Dilution Adjustments" below. There can be no assurance that the Maturity Price will be within the range set forth below. Given the Initial Price of $21.75 per Exchangeable Note and the Threshold Appreciation Price of $26.32, a Holder of an Exchangeable Note would receive at Maturity the following number of shares of EOG Common Stock or amount of cash (if Enron elects to pay the Exchangeable Notes in cash): MATURITY PRICE NUMBER OF OF EOG SHARES OF EOG COMMON STOCK COMMON STOCK AMOUNT OF CASH ------------- ------------- --------------- $20.00 1.0000 $20.00 21.75 1.0000 21.75 24.00 0.9063 21.75 26.32 0.8264 21.75 28.00 0.8264 23.14 Interest on the Exchangeable Notes will be payable, and delivery of EOG Common Stock (or, at the option of Enron, its cash equivalent) in exchange for the Exchangeable Notes at Maturity will be made upon surrender of such Exchangeable Notes, at the office or agency of Enron maintained for such purposes, which will initially be the principal corporate trust office of the Trustee, currently 311 West Monroe, 12th Floor, Chicago, Illinois 60609 or at the Trustee's office maintained for such purpose in New York, New York, provided that payment of interest may be made at the option of Enron by check mailed to the persons in whose names the Exchangeable Notes are registered at the close of business on each January 15, April 15, July 15, and October 15. The Exchangeable Notes will be transferable on the books of Enron at any time and from time to time. No service charge will be made to the Holder for any such transfer except for any tax or governmental charge incidental thereto. The Indenture does not contain any restriction on the ability of Enron to sell, pledge or otherwise convey all or any portion of the EOG Common Stock held by it, and no such shares of EOG Common Stock will be pledged or otherwise held in escrow for use at Maturity of the Exchangeable Notes. Consequently, in the event of a bankruptcy, insolvency or liquidation of Enron, the EOG Common Stock, if any, owned by Enron will be subject to the claims of the creditors of Enron. In addition, as described herein, Enron will have the option, exercisable in its sole discretion, to satisfy its obligations pursuant to the mandatory exchange for the principal amount of each Exchangeable Note at Maturity by delivering to Holders of the Exchangeable Notes either the specified number of shares of EOG Common Stock or cash in an amount equal to the value of such number of shares at the Maturity Price. In the event that Enron does sell, pledge or convey all or a portion of the EOG Common Stock held by it, Enron may be more likely to deliver cash in lieu of EOG Common Stock. As a result, there can be no assurance that Enron will elect at Maturity to deliver EOG Common Stock or, if it so elects, that it will use all or a portion of its current holdings of EOG Common Stock to make such delivery. Holders of the Exchangeable Notes will not be entitled to any rights with respect to the EOG Common Stock (including without limitation voting rights and rights to receive any dividends or other distributions in respect thereof) until such time, if any, as Enron shall have delivered shares of EOG Common Stock to holders of the Exchangeable Notes at Maturity thereof and the applicable record date, if any, for the exercise of such rights occurs after such date. DILUTION ADJUSTMENTS The Exchange Rate is subject to adjustment if EOG shall (i) pay a stock dividend or make a distribution with respect to EOG Common Stock in shares of such stock, (ii) subdivide or split the outstanding shares of EOG Common Stock, (iii) combine the outstanding shares of EOG Common Stock into a smaller number of shares, (iv) issue by reclassification of shares of EOG Common Stock any shares of common stock of EOG, (v) issue rights or warrants to all holders of EOG Common Stock entitling them to subscribe for or purchase shares of EOG Common Stock at a price 17 per share less than the market price of the EOG Common Stock (other than rights to purchase EOG Common Stock pursuant to a plan for the reinvestment of dividends or interest); or (vi) pay a dividend or make a distribution to all holders of EOG Common Stock of evidences of indebtedness or other assets (excluding any dividends or distributions referred to in clause (i) above or any cash dividends other than any Extraordinary Cash Dividends (as defined below) or issue to all holders of EOG Common Stock rights or warrants to subscribe for or purchase any of its securities (other than those referred to in clause (v) above). In the case of the events referred to in clauses (i), (ii), (iii) and (iv) above, the Exchange Rate in effect immediately prior to such event shall be adjusted so that the holder of any Exchangeable Note shall thereafter be entitled to receive, upon mandatory exchange of the principal amount of the Exchangeable Note at Maturity, the number of shares of EOG Common Stock that such holder would have owned or been entitled to receive immediately following any event described above had such Exchangeable Note been exchanged immediately prior to such event on any record date with respect thereto. In the case of the event referred to in clause (v) above, the Exchange Rate shall be adjusted by multiplying the Exchange Rate in effect immediately prior to the date of issuance of the rights or warrants referred to in clause (v) above, by a fraction, the numerator of which shall be the number of shares of EOG Common Stock outstanding on the date of issuance of such rights or warrants, immediately prior to such issuance, plus the number of additional shares of EOG Common Stock offered for subscription or purchase pursuant to such rights or warrants, and the denominator of which shall be the number of shares of EOG Common Stock outstanding on the date of issuance of such rights or warrants, immediately prior to such issuance, plus the number of additional shares of EOG Common Stock that the aggregate offering price of the total number of shares of EOG Common Stock so offered for subscription or purchase pursuant to such rights or warrants would purchase at the market price (determined as the average Closing Price per share of EOG Common Stock for the 20 Trading Days immediately prior to the date such rights or warrants are issued), which shall be determined by multiplying such total number of shares by the exercise price of such rights or warrants and dividing the product so obtained by such market price. To the extent that shares of EOG Common Stock are not delivered after the expiration of such rights or warrants, the Exchange Rate shall be readjusted to the Exchange Rate which would then be in effect had such adjustments for the issuance of such rights or warrants been made upon the basis of delivery of only the number of shares of EOG Common Stock actually delivered. In the case of the event referred to in clause (vi) above, the Exchange Rate shall be adjusted by multiplying the Exchange Rate in effect on the record date by a fraction, the numerator of which shall be the market price per share of the EOG Common Stock on the record date for the determination of stockholders entitled to receive the dividend or distribution referred to in clause (vi) above (such market price being determined as the average Closing Price per share of EOG Common Stock for the 20 Trading Days immediately prior to such record date), and the denominator of which shall be such market price per share of EOG Common Stock less the fair market value (as determined by the Board of Directors of Enron, whose determination shall be conclusive, and described in a resolution adopted with respect thereto) as of such record date of the portion of the assets or evidences of indebtedness so distributed or of such subscription rights or warrants applicable to one share of EOG Common Stock. An "Extraordinary Cash Dividend" means, with respect to any 365-day period, all cash dividends on the EOG Common Stock during such period to the extent such dividends exceed on a per share basis 10% of the average Closing Price of the EOG Common Stock over such period (less any such dividends for which a prior adjustment to the Exchange Rate was previously made). All adjustments to the Exchange Rate will be calculated to the nearest 1/10,000th of a share of EOG Common Stock (or if there is not a nearest 1/10,000th of a share to the next lower 1/10,000th of a share). No adjustment in the Exchange 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. In the event of (i) any consolidation or merger of EOG, or any surviving entity or subsequent surviving entity of EOG (an "EOG Successor"), with or into another entity (other than a merger or consolidation in which EOG is the continuing corporation and in which the EOG Common Stock outstanding immediately prior to the merger or consolidation is not exchanged for cash, securities or 18 other property of EOG or another Person), (ii) any sale, transfer, lease or conveyance to another Person of the property of EOG or any EOG Successor as an entirety or substantially as an entirety, (iii) any statutory exchange of securities of EOG, or any EOG Successor with another Person (other than in connection with a merger or acquisition); or (iv) any liquidation, dissolution or winding up of EOG or any EOG Successor (any such event being a "Reorganization Event"), the Exchange Rate used to determine the amount payable upon exchange at Maturity for each Exchangeable Note will be adjusted to provide that each Holder of Exchangeable Notes will receive at Maturity cash in an amount equal to (a) if the Transaction Value (as defined below) is greater than or equal to the Threshold Appreciation Price, .8264 multiplied by the Transaction Value, (b) if the Transaction Value is less than the Threshold Appreciation Price but greater than the Initial Price, the Initial Price and (c) if the Transaction Value is less than or equal to the Initial Price, the Transaction Value. "Transaction Value" means (i) for any cash received in any such Reorganization Event, the amount of cash received per share of EOG Common Stock, (ii) for any property other than cash or securities received in any such Reorganization Event, an amount equal to the market value at Maturity of such property received per share of EOG Common Stock as determined by a nationally recognized independent investment banking firm retained for this purpose by Enron and (iii) for any securities received in any such Reorganization Event, an amount equal to the average Closing Price per share of such securities for the 20 Trading Days immediately prior to Maturity multiplied by the number of such securities received for each share of EOG Common Stock. Notwithstanding the foregoing, in lieu of delivering cash as provided above, Enron may at its option deliver an equivalent value of securities or other property received in such Reorganization Event, determined in accordance with clause (ii) or (iii) above, as applicable. If Enron elects to deliver securities or other property, holders of the Exchangeable Notes will be responsible for the payment of any and all brokerage and other transaction costs upon the sale of such securities or other property. The kind and amount of securities into which the Exchangeable Notes shall be exchangeable after consummation of such transaction shall be subject to adjustment as described in the immediately preceding paragraph following the date of consummation of such transaction. Enron is required, within ten Business Days following the occurrence of an event that requires an adjustment to the Exchange Rate (or if Enron is not aware of such occurrence, as soon as practicable after becoming so aware), to provide written notice to the Trustee for distribution to all Holders of Exchangeable Notes of the occurrence of such event and a statement in reasonable detail setting forth the method by which the adjustment to the Exchange Rate was determined and setting forth the revised Exchange Rate. FRACTIONAL SHARES No fractional shares of EOG Common Stock will be issued if Enron exchanges the Exchangeable Notes for shares of EOG Common Stock. If more than one Exchangeable Note shall be surrendered for exchange at one time by the same holder, the number of full shares of EOG Common Stock which shall be delivered upon exchange shall be computed on the basis of the aggregate number of Exchangeable Notes so surrendered at Maturity. In lieu of any fractional share otherwise issuable in respect of all Exchangeable Notes of any Holder which are exchanged at Maturity, such Holder shall be entitled to receive an amount in cash equal to the value of such fractional share at the Maturity Price. REDEMPTION AND DEFEASANCE The Exchangeable Notes are not subject to redemption or defeasance prior to Maturity and do not contain any sinking fund or other mandatory redemption provisions. LIMITATIONS ON MORTGAGES AND LIENS The Indenture provides that so long as any of the Indenture Securities issued under the Indenture (including the Exchangeable Notes) are outstanding, Enron will not, and will not permit any Subsidiary (as defined in the Indenture and herein) to, pledge, mortgage or hypothecate, or permit to exist, except in favor of Enron or any Subsidiary, any mortgage, pledge or other lien upon, any Principal Property (as defined in the Indenture and herein) at any time owned by it, to secure any 19 indebtedness (as defined in the Indenture), unless effective provision is made whereby outstanding Indenture Securities (including the Exchangeable Notes) will be equally and ratably secured with any and all such indebtedness and with any other indebtedness similarly entitled to be equally and ratably secured. This restriction does not apply to prevent the creation or existence of: (a) mortgages, pledges, liens or encumbrances on any property held or used by Enron or a Subsidiary in connection with the exploration for, development of or production of, oil, gas, natural gas (including liquefied gas and storage gas), other hydrocarbons, helium, coal, metals, minerals, steam, timber, geothermal or other natural resources or synthetic fuels, such properties to include, but not be limited to, Enron's or a Subsidiary's interest in any mineral fee interests, oil, gas or other mineral leases, royalty, overriding royalty or net profits interests, production payments and other similar interests, wellhead production equipment, tanks, field gathering lines, leasehold or field separation and processing facilities, compression facilities and other similar personal property and fixtures; (b) mortgages, pledges, liens or encumbrances on oil, gas, natural gas (including liquefied gas and storage gas), other hydrocarbons, helium, coal, metals, minerals, steam, timber, geothermal or other natural resources or synthetic fuels produced or recovered from any property, an interest in which is owned or leased by Enron or a Subsidiary; (c) mortgages, pledges, liens or encumbrances (or certain extensions, renewals or refundings thereof) upon any property acquired before or after the date of the Indenture, created at the time of acquisition or within one year thereafter to secure all or a portion of the purchase price thereof, or existing thereon at the date of acquisition, whether or not assumed by Enron or a Subsidiary, provided that every such mortgage, pledge, lien or encumbrance applies only to the property so acquired and fixed improvements thereon; (d) mortgages, pledges, liens or encumbrances upon any property acquired before or after the date of the Indenture by any corporation that is or becomes a Subsidiary after the date of the Indenture ("Acquired Entity"), provided that every such mortgage, pledge, lien or encumbrance (1) shall either (i) exist prior to the time the Acquired Entity becomes a Subsidiary or (ii) be created at the time the Acquired Entity becomes a Subsidiary or within one year thereafter to secure all or a portion of the acquisition price thereof and (2) shall only apply to those properties owned by the Acquired Entity at the time it becomes a Subsidiary or thereafter acquired by it from sources other than Enron or any other Subsidiary; (e) pledges of current assets, in the ordinary course of business, to secure current liabilities; (f) deposits to secure public or statutory obligations; (g) liens to secure indebtedness other than Funded Debt (as defined in the Indenture and herein); (h) mortgages, pledges, liens or encumbrances upon any office, data processing or transportation equipment; (i) mortgages, pledges, liens or encumbrances created or assumed by Enron or a Subsidiary in connection with the issuance of debt securities the interest on which is excludable from gross income of the holder of such security pursuant to the Internal Revenue Code of 1986, as amended, for the purpose of financing the acquisition or construction of property to be used by Enron or a Subsidiary; (j) pledges or assignments of accounts receivable or conditional sales contracts or chattel mortgages and evidences of indebtedness secured thereby received in connection with the sale by Enron or a Subsidiary of goods or merchandise to customers; or (k) certain other liens or encumbrances. Notwithstanding the foregoing, Enron or a Subsidiary may issue, assume or guarantee indebtedness secured by a mortgage which would otherwise be subject to the foregoing restrictions in an aggregate amount which, together with all other indebtedness of Enron or a Subsidiary secured by a mortgage which (if originally issued, assumed or guaranteed at such time) would otherwise be subject to the foregoing restrictions (not including secured indebtedness permitted under the foregoing exceptions), does not at the time exceed 10% of the Consolidated Net Tangible Assets (total assets less (a) total current liabilities, excluding indebtedness due within 12 months, and (b) goodwill, patents and trademarks) of Enron, as shown on the audited consolidated financial statements of Enron as of the end of the fiscal year preceding the date of determination. The holders of at least 50% in principal amount of the outstanding Indenture Securities under the Indenture (including the Exchangeable Notes) may waive compliance by Enron with the covenant described above (and certain other covenants of Enron). The Indenture defines the term "Subsidiary" to mean a corporation all of the voting shares (that is, shares entitled to vote for the election of directors, but excluding shares entitled so to vote only 20 upon the happening of some contingency unless such contingency shall have occurred) of which shall be owned by Enron or by one or more Subsidiaries or by Enron and one or more Subsidiaries. The term "Principal Property" is defined to mean any oil or gas pipeline, gas processing plant or chemical plant located in the United States, except any such property, pipeline or plant that in the opinion of the Board of Directors of Enron is not of material importance to the total business conducted by Enron and its Subsidiaries. "Principal Property" does not include any oil or gas property or the production or any proceeds of production from an oil or gas producing property or the production or any proceeds of production of gas processing plants or oil or gas or petroleum products in any pipeline. The term "indebtedness", as applied to Enron or any Subsidiary, is defined to mean bonds, debentures, notes and other instruments representing obligations created or assumed by any such corporation for the repayment of money borrowed (other than unamortized debt discount or premium). All indebtedness secured by a lien upon property owned by Enron or any Subsidiary and upon which indebtedness any such corporation customarily pays interest, even though such corporation has not assumed or become liable for the payment of such indebtedness, is also deemed to be indebtedness of any such corporation. All indebtedness for money borrowed incurred by other persons which is directly guaranteed as to payment of principal by Enron or any Subsidiary is for all purposes of the Indenture deemed to be indebtedness of any such corporation, but no other contingent obligation of any such corporation in respect to indebtedness incurred by other persons is for any purpose deemed indebtedness of such corporation. Indebtedness of Enron or any Subsidiary does not include (i) amounts which are payable only out of all or a portion of the oil, gas, natural gas, helium, coal, metals, minerals, steam, timber or other natural resources produced, derived or extracted from properties owned or developed by such corporation; (ii) any amount representing capitalized lease obligations; (iii) any indebtedness incurred to finance oil, gas, natural gas, helium, coal, metals, minerals, steam, timber, hydrocarbons or geothermal or other natural resources or synthetic fuel exploration or development, payable, with respect to principal and interest, solely out of the proceeds of oil, gas, natural gas, helium, coal, metals, minerals, steam, timber, hydrocarbons or geothermal or other natural resources or synthetic fuel to be produced, sold and/or delivered by Enron or any Subsidiary; (iv) indirect guarantees or other contingent obligations in connection with the indebtedness of others, including agreements, contingent or otherwise, with such other persons or with third persons with respect to, or to permit or ensure the payment of, obligations of such other persons, including without limitation, agreements to purchase or repurchase obligations of such other persons, agreements to advance or supply funds to or to invest in such other persons or agreements to pay for property, products or services of such other persons (whether or not conferred, delivered or rendered) and any demand charge, throughput, take-or-pay, keep-well, make-whole, cash deficiency, maintenance of working capital or earnings or similar agreements; and (v) any guarantees with respect to lease or other similar periodic payments to be made by other persons. The term "Funded Debt" as applied to any corporation means all indebtedness incurred, created, assumed or guaranteed by such corporation, or upon which it customarily pays interest charges, which matures, or is renewable by such corporation to a date, more than one year after the date as of which Funded Debt is being determined; provided, however, that the term "Funded Debt" shall not include (i) indebtedness incurred in the ordinary course of business representing borrowings, regardless of when payable, of such corporation from time to time against, but not in excess of the face amount of, its installment accounts receivable for the sale of appliances and equipment sold in the regular course of business or (ii) advances for construction and security deposits received by such corporation in the ordinary course of business. The foregoing limitations on mortgages, pledges and liens are intended to limit other creditors of Enron from obtaining preference or priority over holders of the Indenture Securities issued under the Indenture, but are not intended to prevent other creditors from sharing equally and ratably and without preference ("pari passu") over the holders of such Indenture Securities. While such limitations on mortgages and liens do provide protection to the holders of the Indenture Securities, there are a number of exceptions to such restrictions which could result in certain assets of Enron 21 and its Subsidiaries being encumbered without equally and ratably securing the Indenture Securities issued under the Indenture. Specifically, the restrictions apply only to pledges, mortgages or liens upon "Principal Property" (as defined in the Indenture and herein) to secure any "indebtedness" (as defined in the Indenture and herein), unless effective provision is made whereby outstanding Securities will be equally and ratably secured with any such indebtedness and with any other indebtedness similarly entitled to be equally and ratably secured. There are certain exceptions to the definition of "indebtedness," which are enumerated in the Indenture and herein. In addition, the restrictions do not apply to prevent the creation or existence of mortgages, pledges, liens or encumbrances on certain types of properties or pursuant to certain types of transactions, all as enumerated in the Indenture and above. Also, up to 10% of Consolidated Net Tangible Assets (as defined in the Indenture and herein) is not subject to the mortgage and lien limitations contained in the Indenture. MODIFICATION OF THE INDENTURE With certain exceptions, the Indenture provides that, with the consent of the holders of not less than 50% in principal amount of all outstanding Indenture Securities (including, where applicable, the Exchangeable Notes) affected thereby, Enron and the Trustee may enter into a supplemental indenture for the purpose of adding to, changing or eliminating any of the provisions of the Indenture or of modifying in any manner the rights of the holders of Indenture Securities under the Indenture. Notwithstanding the foregoing, the consent of the holder of each outstanding Indenture Security affected thereby will be required to: (a) change the Stated Maturity (as defined in the Indenture) of the principal of, or any installment of principal of or interest on, any Indenture Security, or reduce the principal amount thereof or the rate of interest thereon or any premium payable upon the redemption thereof, or change any Place of Payment (as defined in the Indenture) where, or change the coin or currency in which, any Indenture Security or any premium or the interest thereon is payable, or impair the right to institute suit for the enforcement of any such payment on or after the Stated Maturity thereof (or, in the case of redemption, on or after the Redemption Date, as defined in the Indenture) or change the terms under which any Exchangeable Notes are exchangeable; (b) reduce the percentage in principal amount of the outstanding Indenture Securities of any series, the consent of whose holders is required for any supplemental indenture or for any waiver provided for in the Indenture; or (c) with certain exceptions, modify any of the provisions of the sections of the Indenture which concern waivers of past defaults, waivers of certain covenants or consent to supplemental indentures, except to increase the percentage of principal amount of Indenture Securities of any series, the holders of which are required to effect such waiver or consent, or to provide that certain other provisions of the Indenture cannot be modified or waived without the consent of the holder of each outstanding Indenture Security affected thereby. The Indenture provides that a supplemental indenture which changes or eliminates any covenant or other provision of the Indenture which has expressly been included solely for the benefit of one or more particular series of Indenture Securities, or which modifies the rights of the holders of Indenture Securities of such series with respect to such covenant or other provision, shall be deemed not to affect the rights under the Indenture of the holders of Indenture Securities of any other series. EVENTS OF DEFAULT AND RIGHTS UPON DEFAULT Under the Indenture, the term "Event of Default" with respect to any series of Indenture Securities, means any one of the following events which shall have occurred and is continuing: (a) default in the payment of any interest upon any Indenture Security of that series when it becomes due and payable or default in the payment of any mandatory sinking fund payment provided for by the terms of any series of Indenture Securities, and continuance of such default for a period of 30 days; (b) default in the payment of the principal of (or premium, if any, on) any Indenture Security of that series at its maturity; (c) default in the performance, or breach, of any covenant or warranty of Enron in the Indenture (other than a covenant or warranty a default in the performance of which or the breach of which is otherwise specifically dealt with in the Indenture or which has been expressly included in the Indenture solely for the benefit of one or more series of Indenture Securities other than that series), and continuance of such default or breach for 60 days after there has been given to 22 Enron by the Trustee, or to Enron and the Trustee by the holders of at least 25% in principal amount of all outstanding Indenture Securities, a written notice specifying such default or breach and requiring it to be remedied and stating that such notice is a "Notice of Default" under the Indenture; or (d) certain events involving Enron in bankruptcy, receivership or other insolvency proceedings or an assignment for the benefit of creditors. If an Event of Default described in clause (a) or (b) in the foregoing paragraph has occurred and is continuing with respect to Indenture Securities of any series, the Indenture provides that the Trustee or the holders of not less than 25% in principal amount of the outstanding Indenture Securities of that series may declare the principal amount of all of the Indenture Securities of that series to be due and payable immediately, and upon any such declaration such principal amount shall become immediately due and payable. If an Event of Default described in clause (c) or (d) of the foregoing paragraph occurs and is continuing, the Trustee or the holders of not less than 25% in principal amount of all of the Indenture Securities then outstanding may declare the principal amount of all of the Indenture Securities to be due and payable immediately, and upon any such declaration such principal amount shall become immediately due and payable. A default under other indebtedness of Enron is not an Event of Default under the Indenture, and an Event of Default under one series of Indenture Securities will not necessarily be an Event of Default under another series. At any time after such a declaration of acceleration with respect to Indenture Securities of any series (or of all series, as the case may be) has been made and before judgment or decree for payment of the money due has been obtained by the Trustee, the holders of a majority in principal amount of the outstanding Indenture Securities of that series (or of all series, as the case may be) may rescind and annul such declaration and its consequences, if, subject to certain conditions, all Events of Default with respect to Indenture Securities of that series (or of all series, as the case may be), other than the non-payment of the principal of the Indenture Securities due solely by such declaration of acceleration, have been cured or waived and all payments due (other than by acceleration) have been paid or deposited with the Trustee. With certain exceptions, the holders of not less than a majority in principal amount of the outstanding Indenture Securities of any series, on behalf of the holders of all the Indenture Securities of such series, may waive any past default described in clause (a) or (b) of the first paragraph of this heading "Events of Default and Rights Upon Default" (or, in the case of a default described in clause (c) or (d) of such paragraph, the holders of a majority in principal amount of all outstanding Indenture Securities may waive any such past default), and its consequences, except a default (a) in the payment of the principal of (or premium, if any) or interest on any Indenture Security, or (b) in respect of a covenant or provision of the Indenture which under the Indenture cannot be modified or amended without the consent of the holder of each outstanding Indenture Security of such series affected. The holders of not less than a majority in principal amount of the Indenture Securities of any series at the time outstanding are empowered under the terms of the Indenture, subject to certain limitations, to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or exercising any trust or power conferred on the Trustee. The Indenture further provides that no holder of an Indenture Security of any series may enforce the Indenture except in the case of failure by the Trustee to act for 60 days after notice of a continuing Event of Default with respect to the Indenture Securities of that series and after request by the holders of not less than 25% in principal amount of the outstanding Indenture Securities of such series and the offer to the Trustee of reasonable indemnity, but this provision will not prevent a holder of any Indenture Security from enforcing the payment of the principal of, and interest on, such holder's Indenture Security. The Indenture requires that Enron deliver to the Trustee, within 120 days after the end of each fiscal year, an Officer's Certificate, stating whether to the best knowledge of the signers thereof, Enron is in default in the performance and observance of certain of the terms of the Indenture and, if so, specifying each such default and the nature and status thereof of which the signers may have knowledge. 23 CONCERNING THE TRUSTEE Harris Trust and Savings Bank is the Trustee under the Indenture. Such bank also acts as a depository of funds for, makes loans to, and performs other services for, Enron in the normal course of business, including acting as trustee under other indentures of Enron. The Indenture contains the provisions required by the Trust Indenture Act of 1939 with reference to the disqualification of the Trustee if it shall have or acquire any "conflicting interest", as therein defined. The Indenture also contains certain limitations on the right of the Trustee, as a creditor of Enron, to obtain payment of claims in certain cases, or to realize on certain property received by it in respect of any such claims, as security or otherwise. CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS The following is a summary of certain U.S. federal income tax consequences that may be relevant to a citizen or resident of the United States, a corporation, partnership or other entity created or organized under the laws of the United States, or an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source (any of the foregoing, a "U.S. Person") who is the beneficial owner of Exchangeable Notes (a "U.S. Holder"), which in the opinion of Vinson & Elkins L.L.P. is accurate insofar as it expresses conclusions of law. All references to "holders" (including U.S. Holders) are to beneficial owners of the Exchangeable Notes. This discussion, which was prepared by Vinson & Elkins L.L.P., is based on current U.S. federal income tax law and is for general information only. This summary deals only with holders who are initial holders of the Exchangeable Notes and who will hold the Exchangeable Notes as capital assets. It does not address tax considerations applicable to investors that may be subject to special U.S. federal income tax treatment, such as dealers in securities or persons holding the Exchangeable Notes as a position in a "straddle" for U.S. federal income tax purposes or as part of a "synthetic security" or other integrated investment, and does not address the consequences under state, local or foreign law. No statutory, judicial or administrative authority directly addresses the characterization of the Exchangeable Notes or instruments similar to the Exchangeable Notes for U.S. federal income tax purposes. As a result, significant aspects of the U.S. federal income tax consequences of an investment in the Exchangeable Notes are not certain. No ruling is being requested from the Internal Revenue Service (the "IRS") with respect to the Exchangeable Notes and no assurance can be given that the IRS will agree with the characterization and tax treatment of the Exchangeable Notes described herein. In addition, Vinson & Elkins L.L.P. has stated in its opinion that it could give no opinion with respect to the specific tax consequences of owning or disposing of the Exchangeable Notes, including the characterization of the Exchangeable Notes. ACCORDINGLY, A PROSPECTIVE INVESTOR (INCLUDING A TAX-EXEMPT INVESTOR) IN THE EXCHANGEABLE NOTES SHOULD CONSULT ITS TAX ADVISOR IN DETERMINING THE TAX CONSEQUENCES OF AN INVESTMENT IN THE EXCHANGEABLE NOTES, INCLUDING THE APPLICATION OF STATE, LOCAL OR OTHER TAX LAWS AND THE POSSIBLE EFFECTS OF CHANGES IN FEDERAL OR OTHER TAX LAWS. Pursuant to the terms of the Indenture, Enron and all holders of the Exchangeable Notes will agree to treat an Exchangeable Note as a unit (the "Unit") consisting of (i) an exchange note ("Exchange Note") which is a debt obligation with a fixed principal amount unconditionally payable at Maturity equal to the principal amount of the Exchangeable Note, bearing interest at the stated interest rate on the Exchangeable Note, and (ii) a forward purchase contract (the "Purchase Contract") pursuant to which the holder agrees to use the principal payment due on the Exchange Note to purchase at Maturity the EOG Common Stock which the holder is entitled to receive at that time (subject to Enron's right to deliver cash in lieu of EOG Common Stock). The Indenture will require that a U.S. Holder include currently in income payments denominated as interest that are made with respect to the Exchangeable Notes, in accordance with such holder's method of accounting, and the amount of OID, if any, attributable to the Exchangeable Notes. Pursuant to the agreement to treat the Exchangeable Notes as a Unit, a holder will be required to allocate the purchase price of the Exchangeable Note between the two components of the Unit (the Exchange Note and the Purchase Contract) on the basis of their relative fair market values. The purchase price so allocated will generally constitute the tax basis for each component. Pursuant to the terms of the Indenture, Enron and the holders agree to allocate the entire purchase price of an 24 Exchangeable Note to the Exchange Note unless the stated interest on the Exchangeable Note represents a yield that is lower than Enron's normal cost of issuing debt with a similar term to the Exchangeable Note ("Enron's Mid-Term Borrowing Rate"). If the stated interest on the Exchangeable Note represents a yield that is lower than Enron's Mid-Term Borrowing Rate of 5.90 percent, Enron and the holders agree to allocate to the Exchange Note an amount, less than the principal amount of the Exchange Note, calculated by discounting the cash flows relating to the Exchange Note at a rate equal to Enron's Mid-Term Borrowing Rate, and to allocate to the Purchase Contract the remainder of the purchase price of the Exchangeable Note. If the amount allocated to the Exchange Note (its deemed issue price) is less than the stated principal amount of the Exchangeable Note, the Exchange Note will be treated as having OID. In that event, a U.S. Holder will be required to include in income OID as it accrues, in accordance with a constant-yield method, in an aggregate amount equal to the difference between the stated principal amount of the Exchangeable Note and the deemed issue price of the Exchange Note. However, if the amount of OID relating to an Exchange Note is less than three-fourths of one percent of the stated principal amount of the Exchangeable Note, no amount of OID will be deemed to exist with respect to the Exchange Note. A U.S. Holder's tax basis in the Exchange Note will increase over its term by the amount of OID included in such holder's income with respect to the Exchangeable Note. Upon the sale or other disposition of an Exchangeable Note, a U.S. Holder generally will be required to allocate the amount realized between the two components of the Exchangeable Note on the basis of their then relative fair market values. A U.S. Holder will recognize gain or loss with respect to each component equal to the difference between the amount realized on the sale or other disposition for each such component and the U.S. Holder's tax basis in such component. Such gain or loss generally will be long-term capital gain or loss if the U.S. Holder has held the Exchangeable Note for more than a year at the time of disposition. At Maturity, pursuant to the agreement to treat the Exchangeable Note as a Unit, on the repayment of the Exchange Note a U.S. Holder will recognize capital gain or loss which will be long-term capital gain or loss unless Maturity occurs within one year of issuance of the Exchangeable Note (as a result of acceleration or otherwise) equal to any difference between its tax basis and the principal amount of the Exchange Note. If Enron delivers EOG Common Stock at Maturity, a U.S. Holder will recognize no additional gain or loss on the exchange, pursuant to the Purchase Contract, of the principal payment due on the Exchange Note for the EOG Common Stock. However, a U.S. Holder will recognize additional capital gain or loss, which should be short-term capital gain or loss, equal to the difference between the cash received in lieu of fractional shares and the portion of the principal amount of the Exchange Note allocable to fractional shares. A U.S. Holder will have a tax basis in such shares of EOG Common Stock equal to the principal amount of the Exchange Note less the amount of the portion of the principal amount of the Exchange Note allocable to any fractional shares. The U.S. Holder will have a holding period for the EOG Common Stock that begins on the day after the Maturity date, and will realize short- or long-term capital gain or loss upon the subsequent sale or disposition of such stock. Alternatively, at Maturity, if Enron pays the Exchangeable Note in cash, a U.S. Holder will have additional gain or loss (which might be ordinary income or loss rather than capital gain or loss) equal to the difference between the principal amount of the Exchangeable Note and the amount of cash received from Enron. Due to the absence of authority as to the proper characterization of the Exchangeable Note, no assurance can be given that the IRS will accept or that a court will uphold the characterization agreed to in the Indenture or the tax treatment described above. Proposed Treasury regulations with respect to "contingent payment" debt instruments (the "Proposed Regulations") would provide for a different tax result under some circumstances for instruments having characteristics similar to the Exchangeable Notes, but the Proposed Regulations would be effective only for instruments issued 60 days or more after their publication as final regulations. Under the Proposed Regulations, the amount of interest included in a holder's taxable income for any year would generally be determined by projecting the amounts of contingent payments (which might include the value of the EOG Common Stock to be delivered at Maturity) and the yield on the instrument. Taxable interest income would be measured with reference to the projected yield, which might be less than or greater than 25 the stated interest rate under the instrument. In the event that the amount of an actual contingent payment differed from the projected amount of that payment, the difference would generally increase or reduce taxable interest income, or create a loss. Because of their prospective effective date, the Proposed Regulations, if finalized in their current form, would not apply to the Exchangeable Notes. Even in the absence of regulations applicable to the Exchangeable Notes, the Exchangeable Notes may be characterized under current law in a manner that results in tax consequences different from those reflected in the agreement pursuant to the Indenture and as described above. Under alternative characterizations of the Exchangeable Notes, it is possible, for example, that (i) a U.S. Holder may be taxed upon the receipt of EOG Common Stock with a value in excess of the principal amount of the Exchange Note, rather than upon the sale of such stock, (ii) any gain recognized at Maturity (whether a U.S. Holder received EOG Common Stock or cash) may be treated as ordinary income rather than capital gain, (iii) all or part of the interest income on the Exchange Note may be treated as nontaxable, increasing the gain (or decreasing the loss) at Maturity or upon disposition of the Exchangeable Note (or disposition of the EOG Common Stock) or (iv) if the stated interest rate exceeds Enron's Mid-Term Borrowing Rate, the Exchange Notes could be considered as issued at a premium which, if amortized, would reduce the amount of interest income currently includible in income by a holder and increase the taxable gain (or decrease the loss) realized at Maturity or upon disposition of the Exchangeable Notes (or disposition of the EOG Common Stock). The Revenue Reconciliation Act of 1993 added Section 1258 to the Code, which may require certain holders of the Exchangeable Notes who have entered into hedging transactions or offsetting positions with respect to the Exchangeable Notes to recognize ordinary income rather than capital gain upon the disposition of the Exchangeable Notes. Holders should consult their tax advisors regarding the applicability of this provision to an investment in the Exchangeable Notes. NON-UNITED STATES PERSON In the case of a holder of the Exchangeable Notes that is not a U.S. Person, payments made with respect to the Exchangeable Notes should not be subject to U.S. withholding tax; PROVIDED that such holder complies with applicable certification requirements. Any capital gain realized upon the sale or other disposition of the Exchangeable Notes by a holder that is not a U.S. Person will generally not be subject to U.S. federal income tax if (i) such gain is not effectively connected with a U.S. trade or business of such holder and (ii) in the case of an individual, such individual is not present in the United States for 183 days or more in the taxable year of the sale or other disposition and either such individual does not have a "tax home" in the United States or the gain is not attributable to a fixed place of business maintained by such individual in the United States. BACKUP WITHHOLDING AND INFORMATION REPORTING A holder of the Exchangeable Notes may be subject to information reporting requirements and to backup withholding at a rate of 31 percent of certain amounts paid to the holder unless such holder provides proof of an applicable exemption or a correct taxpayer identification number, and otherwise complies with applicable requirements of the backup withholding rules. 26 UNDERWRITING Subject to the terms and conditions of the Underwriting Agreement, Enron has agreed to sell to each of the Underwriters named below (the "Underwriters"), and each of such Underwriters, for whom Goldman, Sachs & Co. are acting as representatives, has severally agreed to purchase from Enron, the respective number of Exchangeable Notes set forth opposite its name below: NUMBER OF EXCHANGEABLE UNDERWRITER NOTES - ------------------------------------- ------------ Goldman, Sachs & Co. ................ 3,333,334 Merrill Lynch, Pierce, Fenner & Smith Incorporated ............ 3,333,333 Salomon Brothers Inc ................ 3,333,333 ------------ Total ..................... 10,000,000 ============ Under the terms and conditions of the Underwriting Agreement, the Underwriters are committed to take and pay for all of the Exchangeable Notes offered hereby, if any are taken. The Underwriters propose to offer the Exchangeable Notes in part directly to the public at the initial public offering price set forth on the cover page of this Prospectus, and in part to certain securities dealers at such price less a concession of $.40 per Exchangeable Note. The Underwriters may allow, and each of such dealers may reallow, a concession not exceeding $.10 per Exchangeable Note to certain dealers and brokers. After the Exchangeable Notes are released for sale to the public, the offering price and the other selling terms may from time to time be varied by the representatives. Enron has granted the Underwriters an option exercisable for 30 days after the date of this Prospectus to purchase up to 1,000,000 additional Exchangeable Notes solely to cover over-allotments, if any. If the Underwriters exercise their over-allotment option, the Underwriters have severally agreed, subject to certain conditions, to purchase approximately the same percentage thereof that the number of Exchangeable Notes to be purchased by each of them, as shown in the foregoing table, bears to the 10,000,000 Exchangeable Notes offered. Enron, EOG and EOG's Chief Executive Officer have agreed that during the period beginning from the date of this Prospectus and continuing to and including the date 270 days after the date of this Prospectus, subject to certain exceptions set forth in the Underwriting Agreement, they will not offer, sell, contract to sell or otherwise dispose of any EOG Common Stock, any securities of EOG which are substantially similar to shares of EOG Common Stock or any securities which are convertible into or exchangeable for EOG Common Stock or such substantially similar securities without the prior written consent of Goldman, Sachs & Co., except for the shares of EOG Common Stock offered in connection with the concurrent Stock Offering. The Exchangeable Notes have been approved for listing on the NYSE, subject to official notice of issuance. The EOG Common Stock (including the shares of EOG Common Stock which may be received by a holder of Exchangeable Notes at Maturity) is listed on the NYSE. The Underwriters and/or their affiliates have provided investment banking and financial advisory services to Enron, its subsidiaries or affiliates in the past, for which they have received customary compensation and expense reimbursement, and may do so again in the future. Enron and EOG have agreed to indemnify the several Underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the Underwriters may be required to make in respect thereof. 27 VALIDITY OF THE EXCHANGEABLE NOTES The validity of the Exchangeable Notes will be passed upon for Enron by James V. Derrick, Jr., Senior Vice President and General Counsel of Enron. Mr. Derrick owns substantially less than 1% of the outstanding shares of Common Stock of Enron. Certain matters will be passed upon for Enron by Vinson & Elkins L.L.P. The validity of the Exchangeable Notes will be passed upon for the Underwriters by Bracewell & Patterson, L.L.P. Bracewell & Patterson, L.L.P. currently provides services to Enron and certain of its subsidiaries and affiliates as outside counsel on matters unrelated to the issuance of the Exchangeable Notes. EXPERTS The consolidated financial statements and schedules included in Enron's Annual Report on Form 10-K for the year ended December 31, 1994, incorporated by reference in this Prospectus, have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their reports with respect thereto and are incorporated by reference herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said reports. The letter report of DeGolyer and MacNaughton, independent petroleum consultants, included as an exhibit to Enron's Annual Report on Form 10-K for the year ended December 31, 1994, and the estimates from the reports of that firm appearing in such Annual Report, are incorporated by reference herein on the authority of said firm as experts in petroleum engineering and in giving such reports. 28 APPENDIX A ENRON OIL & GAS COMPANY COMMON STOCK (PAR VALUE $.01 PER SHARE) ------------------------ This Prospectus relates to up to 11,000,000 shares of common stock, par value $.01 per share (the "Common Stock"), of Enron Oil & Gas Company (the "Company"), which may be delivered by Enron Corp. upon mandatory exchange of the 6 1/4% Exchangeable Notes due December 13, 1998 (the "Exchangeable Notes") of Enron Corp., subject to Enron Corp.'s right to deliver cash in lieu of such shares. This Prospectus is Appendix A to a prospectus of Enron Corp. covering the sale of the Exchangeable Notes (the "Exchangeable Notes Prospectus"). The Company will not receive any of the proceeds from the sale of the Exchangeable Notes or the delivery of shares of Common Stock upon mandatory exchange of the Exchangeable Notes at maturity. Enron Corp. has granted the underwriters of the Exchangeable Notes a 30-day option to purchase up to an additional 1,000,000 Exchangeable Notes at the initial offering price per Exchangeable Note, less the underwriting discount, which may be exchangeable at their maturity for additional shares of Common Stock. Such option has been granted solely to cover over-allotments, if any. Concurrently with the offering of the Exchangeable Notes made by the Exchangeable Notes Prospectus (the "Exchangeable Notes Offering"), Enron Corp. is offering for sale 27,000,000 shares of Common Stock (31,050,000 shares if the underwriters' over-allotment options in such offerings are exercised in full) in concurrent U.S. and international offerings (collectively, the "Stock Offerings"). The consummation of the Exchangeable Notes Offering is not contingent upon the consummation of the Stock Offerings, or vice versa. The Common Stock is listed on the New York Stock Exchange under the symbol "EOG". On December 7, 1995, the last reported sale price of Common Stock on the New York Stock Exchange Composite Tape was $22 per share. See "Price Range of Common Stock and Cash Dividends". ------------------------ 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. ------------------------- The date of this Prospectus is December 8, 1995. AVAILABLE INFORMATION The Company is subject to the informational requirements of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and in accordance therewith files reports, proxy statements and other information with the Securities and Exchange Commission (the "Commission"). Such reports, proxy statements and other information can be inspected and copied at the public reference facilities maintained by the Commission at Room 1024, 450 Fifth Street, N.W., Washington, D.C. 20549; and at the following Regional Offices of the Commission: Midwest Regional Office, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661; and Northeast Regional Office, Seven World Trade Center, Suite 1300, New York, New York 10048. Copies of such material can also be obtained from the Public Reference Section of the Commission at 450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549, at prescribed rates. The Company's Common Stock is listed on the New York Stock Exchange, Inc. ("NYSE"), and reports, proxy statements and other information concerning the Company can be inspected and copied at the offices of the New York Exchange at 20 Broad Street, New York, New York 10005. This Prospectus constitutes a part of a Registration Statement on Form S-3 (together with all amendments and exhibits thereto, the "Registration Statement") filed by the Company with the Commission under the Securities Act of 1933, as amended (the "Securities Act"), with respect to the shares of Common Stock offered hereby. This Prospectus does not contain all of the information set forth in such Registration Statement, certain parts of which are omitted in accordance with the rules and regulations of the Commission. Reference is made to such Registration Statement and to the exhibits relating thereto for further information with respect to the Company and the shares of Common Stock offered hereby. Any statements contained herein concerning the provisions of any document filed as an exhibit to the Registration Statement or otherwise filed with the Commission or incorporated by reference herein are not necessarily complete, and in each instance reference is made to the copy of such document so filed for a more complete description of the matter involved. Each such statement is qualified in its entirety by such reference. ------------------------ INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE The Company's Annual Report on Form 10-K for the year ended December 31, 1994, Quarterly Reports on Form 10-Q for the quarters ended March 31, 1995, June 30, 1995 and September 30, 1995 and the description of the Common Stock contained in the Registration Statement on Form 8-A declared effective on October 3, 1989, are incorporated herein by reference. Each document filed by the Company pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to the termination of the offering of the shares of Common Stock pursuant hereto shall be deemed to be incorporated herein by reference and to be a part hereof from the date of filing of such document. Any statement contained herein or in a document all or a portion of which is incorporated or deemed to be incorporated by reference herein shall be deemed to be modified or superseded for purposes of this Prospectus to the extent that a statement contained herein or in any other subsequently filed document which also is or is deemed to be incorporated by reference herein modifies or supersedes such statement. Any statement so modified or superseded shall not be deemed, except as so modified or superseded, to constitute a part of this Prospectus. The Company will provide without charge to each person to whom a copy of this Prospectus is delivered, on the request of any such person, a copy of any or all of the foregoing documents incorporated herein by reference, other than exhibits to such documents (unless such exhibits are specifically incorporated by reference into the documents that this Prospectus incorporates). Requests should be directed to Secretary Division, Enron Oil & Gas Company, at its principal executive offices, 1400 Smith Street, Houston, Texas 77002 (telephone: 713-853-6161). ------------------------ IN CONNECTION WITH THE OFFERING OF THE EXCHANGEABLE NOTES AND COMMON STOCK OF THE COMPANY BY ENRON CORP., THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE EXCHANGEABLE NOTES OR THE COMMON STOCK OF THE COMPANY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE, IN THE OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME. 2 PROSPECTUS SUMMARY THE FOLLOWING IS A SUMMARY OF CERTAIN INFORMATION CONTAINED IN THIS PROSPECTUS. IT IS NOT INTENDED TO BE COMPLETE AND IS QUALIFIED IN ITS ENTIRETY BY THE MORE DETAILED INFORMATION CONTAINED ELSEWHERE IN THIS PROSPECTUS. CERTAIN TERMS ARE DEFINED IN THIS SUMMARY UNDER "CERTAIN DEFINITIONS." CAPITALIZED TERMS WHICH ARE NOT DEFINED IN THIS SUMMARY ARE USED AS DEFINED ELSEWHERE IN THIS PROSPECTUS. THE COMPANY Enron Oil & Gas Company (together with its subsidiaries, "the Company") is one of the largest independent (non-integrated) oil and gas companies in the United States in terms of domestic proved reserves. It is engaged, directly and through its subsidiaries, in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad and India and to a lesser extent, selected other international areas. At December 31, 1994, the Company's estimated net proved natural gas reserves were 1,910 Bcf and estimated net proved crude oil, condensate and natural gas liquids reserves were 37 MMBbl, a net increase of 8% and 78%, respectively, over year end 1993. The Company has increased its reserves for six consecutive years. At December 31, 1994, approximately 70% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 16% in Canada, 11% in Trinidad and 3% in India. At such date, approximately 90% of the Company's total proved reserves was classified as developed. While year end reserve evaluations will not be available for some time, based on the results of the Company's drilling program for the first nine months of 1995, it is expected that extensions, discoveries and other additions to reserves for the year will exceed production for both North America and Trinidad, as well as in total. Additionally, reserves acquired are expected to substantially exceed those sold, with the resulting replacement of production from all sources expected to exceed 150%. BUSINESS STRATEGY. The Company's strategy is to maximize the rate of return on investment of capital by controlling both operating and capital costs and enhancing the certainty of future revenues through the use of various marketing mechanisms. This strategy enhances the generation of both income and cash flow from each unit of production and allows for the growth of production on a cost-effective basis by optimizing the reinvestment of cash flow. Through this strategy, the Company has increased its net income in each of the last five years, despite the volatile natural gas price environment, and achieved a return on equity ranging from 8% in 1990 to 15% in 1994. For the first nine months of 1995, net income increased 5% compared to the same period for 1994. The Company refocused its 1995 drilling activity away from natural gas deliverability and toward natural gas reserve enhancement and crude oil exploitation in the United States in response to the decline in United States natural gas prices in recent periods. The Company also is focusing on the cost-effective utilization of advances in technology associated with gathering, processing and interpretation of 3-D seismic data, developing reservoir simulation models and drilling operations through the use of new and/or improved drill bits, mud motors, mud additives, formation logging techniques and reservoir fracturing methods. These advanced technologies are used, as appropriate, throughout the Company to reduce the risks associated with all aspects of oil and gas reserve exploration, exploitation and development. The Company implements its strategy by emphasizing the drilling of internally generated prospects in order to find and develop low cost reserves. By following this strategy, the Company 3 has increased production in each of the last four years with a compound annual growth rate of 13.1%, while increasing proved reserves approximately 32%, both on a natural gas equivalent basis. For 1994, net equivalent production reached a new high of 307 Bcfe, an increase of 9% over 1993. Natural gas delivered in 1994 averaged approximately 749 MMcf per day, which represents an increase of 6% over 1993. Crude oil and condensate production averaged 12.6 MBbl per day in 1994 which represents an increase of 42% over 1993. Natural gas production for the first nine months of 1995 averaged 719 MMcf per day, down 24 MMcf per day from the first nine months of 1994. Lower volumes in 1995 reflect the voluntary curtailment by the Company of United States production at a higher rate than in 1994 because United States natural gas prices were down by 26% period to period, the impact of the sale of reserves and related assets and the effect of the reduction and redirection of natural gas drilling activities early in 1995. Crude oil and condensate volumes for the first nine months of 1995 averaged 18.6 MBbl per day, an increase of 55% over the first nine months of 1994. Achieving and maintaining the lowest possible cost structure are also important goals in the implementation of the Company's strategy. Over the last five years, the Company has reduced total cash operating expenses, including lease and well, general and administrative, taxes other than income, and interest expenses from $.95/Mcfe in 1989 to $.49/Mcfe in 1994, a reduction of 48%. At the same time non-cash expenses (depreciation, depletion and amortization) have been reduced from $.93/Mcfe in 1989 to $.80/Mcfe in 1994, a reduction of 14%. For the first nine months of 1995, cash operating expenses averaged $.56/Mcfe compared to $.50/Mcfe for the first nine months of 1994 and non-cash expenses averaged $.69/Mcfe and $.81/Mcfe for the two periods, respectively. Consistent with the Company's desire to optimize the use of its assets, the Company also maintains a strategy of selling select oil and gas properties that for various reasons no longer fit into future operating plans, or which are not assessed to have sufficient future growth potential and when the economic value to be obtained by selling the properties and reserves in the ground is evaluated to be greater than what would be obtained by holding the properties and producing the reserves over time. As a result, the Company typically receives each year a varying but substantial level of proceeds related to such sales which proceeds are available for general corporate use. Proceeds from property sales in 1994 were $91 million ($71 million after tax) and in the first nine months of 1995 were $101 million ($77 million after tax). NORTH AMERICAN OPERATIONS. The Company's seven principal United States producing areas are the Big Piney area of Wyoming, South Texas area, East Texas area, Offshore Gulf of Mexico area, Canyon Trend area of West Texas, Pitchfork Ranch area of New Mexico and Vernal area of Utah. Properties in these areas comprised approximately 76% of the Company's United States reserves (on a natural gas equivalent basis) and 85% of the Company's United States net natural gas deliverability as of December 31, 1994 and are substantially all operated by the Company. The Company's other United States natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico and in Oklahoma. At December 31, 1994, 93% of the Company's proved United States reserves (on a natural gas equivalent basis) was natural gas and 7% was crude oil, condensate and natural gas liquids. A substantial portion of the Company's United States natural gas reserves is in long-lived fields with well-established production histories. The Company believes that opportunities exist to increase production in many of these fields through continued infill and other development drilling. The Company also has natural gas and crude oil producing properties located in Western Canada, primarily in the provinces of Alberta, Saskatchewan and Manitoba. The Company produces natural gas from seven major areas and crude oil from three major areas. The Sandhills area in 4 Southern Saskatchewan is the largest single producing area, contributing 51% of Canadian deliverability at September 30, 1995. Canadian natural gas deliverability net to the Company at September 30, 1995 was approximately 70 MMcf per day and the Company held approximately 350,000 net undeveloped acres in Canada. OUTSIDE NORTH AMERICA OPERATIONS. The Company has operations offshore Trinidad and India and is conducting exploration in selected other international areas. Properties offshore Trinidad and India comprise 100% of the Company's current reserves and production outside of North America. The Company's reserves at December 31, 1994 included 236 Bcf of natural gas and 12 MMBbl of liquids in these two areas. The Company's net production from offshore Trinidad was approximately 100 MMcf per day of natural gas and 6.2 MBbl per day of crude oil and condensate at September 30, 1995. The Company's net production from offshore India was approximately 3.5 MBbl per day of crude oil net to the Company at September 30, 1995. In addition, the Company is pursuing other exploitation opportunities in countries, including China, Mozambique and Qatar, where indigenous natural gas reserves have been identified, particularly where synergies in natural gas transportation, processing and power cogeneration can be optimized with other Enron Corp. affiliated companies. RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP. All of the shares of Common Stock offered hereby and in the Stock Offerings are being sold by Enron Corp., and the Company will receive no proceeds from such sales. Concurrently with the offering of the Exchangeable Notes, Enron Corp. is offering for sale 27,000,000 shares of Common Stock (31,050,000 shares if the Underwriters' over-allotment options in such Stock Offerings are exercised in full). Following the consummation of the Stock Offerings, Enron Corp. will own an aggregate of 101,000,000 shares of Common Stock or approximately 63% of the outstanding shares (or, assuming that the Underwriters' over-allotment options in the Stock Offerings are exercised in full, 96,950,000 shares of Common Stock or approximately 61% of the outstanding shares). At maturity, the Exchangeable Notes may be exchanged for no more than 10,000,000 shares of Common Stock (no more than 11,000,000 shares if the over-allotment option of the underwriters in the Exchangeable Notes Offering is exercised in full), subject to adjustment under certain circumstances and to Enron Corp.'s option to pay an amount of cash in lieu of such mandatory exchange. Assuming the underwriters' over-allotment options in the Stock Offerings and the Exchangeable Notes Offering are exercised in full and the maximum number of shares is mandatorily exchanged at maturity of the Exchangeable Notes, Enron Corp.'s remaining ownership of Common Stock would be approximately 54% of the outstanding shares. Any market that develops in the Exchangeable Notes is likely to influence, and be influenced by, the market for the Common Stock. For example, the price of the Common Stock could become more volatile and could be depressed by possible sales of Common Stock by investors who view the Exchangeable Notes as a more attractive means of equity participation in the Company and by hedging and arbitrage activity that may develop involving the Exchangeable Notes and the Common Stock. Neither the Stock Offerings nor the delivery of shares of Common Stock pursuant to the terms of the Exchangeable Notes will affect the existing agreements between the Company and Enron Corp. and their respective affiliates, except for the Tax Allocation Agreement which will cease to be effective from the time at which deconsolidation occurs (when Enron Corp. ceases to own 80% of the outstanding shares of Common Stock). The Company and Enron Corp. have entered into a new tax agreement pursuant to which, among other things, Enron Corp. has agreed (in exchange for the payment of $8.0 million by the Company) to be liable for, and to indemnify the Company against, all federal income taxes and state taxes measured by net income imposed on the Company for 5 periods through the date Enron Corp. reduces its ownership in the Company to less than 80%. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp. and effectiveness of the Tax Allocation Agreement concurrently with deconsolidation or the terms of the new agreement will have a material adverse effect on its financial condition or results of operations. See "Relationship Between the Company and Enron Corp." The nature of the respective businesses of the Company and Enron Corp. and its affiliates is such as to potentially give rise to conflicts of interest between the two companies. The Company's operations account for substantially all of Enron Corp.'s natural gas and crude oil exploration and production operations. An affiliate of Enron Corp. has entered into an agreement to acquire a controlling interest in Coda Energy, Inc. ("Coda"), a company engaged in domestic oil and gas exploration, development and production. Crude oil accounts for approximately 86% of Coda's proved reserves. At December 31, 1994, Coda reported estimated proved natural gas reserves of 39,808 MMcf and estimated proved crude oil, condensate and natural gas liquids reserves of 39,207 MBbls. If the transaction is consummated, conflicts of interest could arise between the Company and Coda. See "Relationship Between the Company and Enron Corp. -- Conflicts of Interest." 6 SUMMARY FINANCIAL AND OPERATING INFORMATION The following table sets forth a summary of selected consolidated financial and operating data for the Company for each of the five years in the period ended December 31, 1994 and for the nine-month periods ended September 30, 1994 and 1995. This information should be read in conjunction with the consolidated financial statements of the Company and related notes thereto incorporated by reference herein (see "Incorporation of Certain Documents by Reference") and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this Prospectus. Financial information for each of the five years in the period ended December 31, 1994 has been derived from audited financial statements. Financial information for the nine-month periods ended September 30, 1994 and 1995 has been derived from unaudited financial statements. The interim data reflects all adjustments which, in the opinion of the management of the Company, are necessary to present fairly such information for the interim periods. Results of the nine-month periods are not necessarily indicative of the results expected for a full year or any other interim period.
NINE MONTHS YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30, --------------------------------------------------------------- ------------------------ 1990 1991 1992 1993 1994 1994 1995 ----------- ----------- ----------- ----------- ----------- ----------- ----------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND OPERATING DATA) STATEMENT OF INCOME DATA: Net operating revenues(1)............ $ 403,137 $ 402,588 $ 459,026 $ 581,020 $ 625,823 $ 474,340 $ 492,342 Income before income taxes........... 34,614 45,669 79,844 112,273 153,935 126,166 144,175 Net income........................... 45,468 47,916 97,580 138,025 147,998 105,438 110,731 Earnings per share of common stock(2)........................... $.30 $.32 $.63 $.86 $.93 $.66 $.69 Average number of common shares(2)... 151,800 151,800 154,533 159,966 159,845 159,826 159,951 BALANCE SHEET DATA (AT PERIOD END): Net oil and gas properties........... $ 1,305,136 $ 1,339,666 $ 1,468,011 $ 1,546,045 $ 1,684,811 $ 1,637,762 $ 1,843,150 Total assets......................... 1,417,939 1,455,608 1,731,012 1,811,162 1,861,867 1,855,819 2,109,971 Long-term debt Affiliate........................ 277,918 132,836 --(3) -- 25,000 25,000 16,320 Other............................ 140,442 289,556 150,000(3) 153,000 165,337 158,862 247,552 Deferred revenue..................... -- -- 301,395 227,528 184,183 195,109 224,085 Shareholders' equity................. 610,042 643,185 826,986(3) 933,073 1,043,419 1,019,712 1,140,295 OPERATING DATA: Wellhead Volumes and Prices Natural Gas Volumes (MMcf per day)(4)............................ 455 491 564 709 749 743 719 Average Natural Gas Prices ($/Mcf)(5)......................... $1.51 $1.37 $1.58 $1.92 $1.62 $1.69 $1.23 Crude/Condensate Volumes (MBbl per day)............................... 8.2 8.2 8.5 8.9 12.6 12.0 18.6 Average Crude/Condensate Prices ($/Bbl)............................ $21.67 $18.78 $17.90 $16.37 $15.62 $15.24 $16.77
- ------------ (1) Net operating revenues for the years 1990 and 1991 and for the first nine months of 1994 have been revised to include gains from sales of reserves and related assets for consistency with current year reporting. (2) In May 1994, the Board of Directors declared a two-for-one split of the Company's Common Stock to be effected as a non-taxable dividend of one share for each share outstanding on May 31, 1994. All share and per share amounts presented herein are reflected on a post-split basis. (3) In August 1992, the Company completed the sale of 8.2 million shares of Common Stock resulting in aggregate net proceeds to the Company of approximately $112 million used primarily to repay long-term debt. In September 1992, the Company completed the sale of a volumetric production payment, resulting in net proceeds of approximately $327 million used to repay long-term debt and for other general corporate purposes. (4) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf per day in 1994 and in the nine-month periods ended September 30, 1994 and 1995 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (5) Includes an average equivalent wellhead value of $1.70 per Mcf in 1992, $1.57 per Mcf in 1993, $1.27 per Mcf in 1994 and $1.32 per Mcf and $.76 per Mcf in the nine-month periods ended September 30, 1994 and 1995, respectively, for the volumes described in note (4), net of transportation costs. 7 SUMMARY OIL AND GAS RESERVE INFORMATION The following table sets forth summary information with respect to the Company's estimates of its net proved natural gas, crude oil, condensate and natural gas liquids reserves at December 31, 1994. For additional information relating to reserves, see "Business -- Oil and Gas Exploration and Production Properties and Reserves."
NATURAL GAS NATURAL EQUIVALENTS (BCFE) GAS LIQUIDS ------------------------ (BCF) (MBBL)(1) DEVELOPED UNDEVELOPED -------- ----------- --------- ----------- Net proved reserves at December 31, 1994: United States.......................................... 1,307 17,787 1,229 185 Canada................................................. 297 7,237 330 10 Trinidad............................................... 206 4,429 233 -- India.................................................. 29 7,585 46 29 -------- ----------- --------- ----------- Total............................................. 1,839 37,038 1,838 224 ======== =========== ========= ===========
Reserve amounts set out above have been revised to exclude volumes attributable to a volumetric production payment from owned reserves. The Company's estimates of its net proved natural gas, crude oil, condensate and natural gas liquids reserves at December 31, 1994, including amounts attributable to a volumetric production payment, are shown below. This disclosure is presented as additional information and is not intended to represent required disclosure pursuant to Statement of Financial Accounting Standards ("SFAS") No. 69 -- "Disclosures about Oil and Gas Producing Activities."
NATURAL GAS NATURAL EQUIVALENTS (BCFE) GAS LIQUIDS ------------------------ (BCF) (MBBL)(1) DEVELOPED UNDEVELOPED -------- ----------- --------- ----------- Net proved reserves at December 31, 1994, including amounts attributable to volumetric production payment: United States.......................................... 1,378 17,787 1,300 185 Canada................................................. 297 7,237 330 10 Trinidad............................................... 206 4,429 233 -- India.................................................. 29 7,585 46 29 -------- ----------- --------- ----------- Total............................................. 1,910 37,038 1,909 224 ======== =========== ========= ===========
- ------------ (1) Includes crude oil, condensate and natural gas liquids. 8 CERTAIN DEFINITIONS Unless otherwise indicated in this Prospectus, natural gas volumes are stated at the legal pressure base of the state, area or country in which the reserves are located and at 60 Fahrenheit. Natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil, condensate or natural gas liquids. As used herein, the following terms have the specific meanings set out: "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel, "MBbl" means thousand barrels, "MMBbl" means million barrels, "Mcfe" means thousand cubic feet equivalent, "MMcfe" means million cubic feet equivalent, "Bcfe" means billion cubic feet equivalent, "MMBtu" means million British thermal units, "BBtu" means billion British thermal units and "TBtu" means trillion British thermal units. With respect to information on the Company's working interest in wells or acreage, "net" oil and gas wells or acreage are determined by multiplying "gross" oil and gas wells or acreage by the Company's working interest in the wells or acreage. "Exploration and development expenditures" include costs associated with exploratory and development drilling (including exploratory dry holes), leasehold acquisitions, seismic data acquisitions, geological and land related overhead expenditures, delay rentals, producing property acquisitions, capitalized interest and other miscellaneous capital expenditures. "Total finding costs" is the ratio of total exploration and development expenditures to reserves added as a result of the drilling and acquisition program. Reserves added include the total net natural gas equivalent volume of all natural gas, crude oil, condensate and natural gas liquids added from extensions, discoveries and other additions, purchases in place and revisions of previous estimates. "Infill drilling" means drilling for the development and production of net proved undeveloped reserves. 9 USE OF PROCEEDS The shares of Common Stock of the Company being offered hereby and the Exchangeable Notes are being sold by Enron Corp. Accordingly, the Company will not receive any of the proceeds from the Stock Offerings or the sale of the Exchangeable Notes or delivery of shares of Common Stock pursuant thereto. PRICE RANGE OF COMMON STOCK AND CASH DIVIDENDS The following table sets forth, for the periods indicated, the high and low sale prices per share for the Common Stock, as reported on the New York Stock Exchange Composite Tape, and the amount of cash dividends paid per share. The 1993 and First and Second Quarter 1994 sales prices and cash dividends per share have been restated to reflect the two-for-one stock split on May 31, 1994. PRICE RANGE -------------------- CASH HIGH LOW DIVIDENDS --------- --------- --------- 1993 First Quarter................... $ 20.31 $ 13.38 $ .03 Second Quarter.................. 22.50 17.88 .03 Third Quarter................... 26.81 19.88 .03 Fourth Quarter.................. 27.00 17.06 .03 1994 First Quarter................... $ 23.75 $ 19.31 $ .03 Second Quarter.................. 24.63 22.38 .03 Third Quarter................... 23.00 18.50 .03 Fourth Quarter.................. 22.75 17.38 .03 1995 First Quarter................... $ 24.88 $ 17.12 $ .03 Second Quarter.................. 24.75 20.25 .03 Third Quarter................... 25.38 20.00 .03 Fourth Quarter (through December 7, 1995)........................ 22.75 18.75 See the cover page of this Prospectus for the last reported sale price of the Common Stock on the NYSE as of a recent date. As of November 1, 1995, there were approximately 270 record holders of the Company's Common Stock, including individual participants in security position listings. There are an estimated 5,100 beneficial owners of the Company's Common Stock, including shares held in street name. Following the initial public offering and sale of its Common Stock in October 1989, the Company paid quarterly dividends of $0.025 per share beginning with an initial dividend paid in January 1990 with respect to the fourth quarter of 1989. Beginning in January 1993 with respect to the fourth quarter of 1992, the Company has paid quarterly dividends of $0.03 per share. The Company currently intends to continue to pay quarterly cash dividends on its outstanding shares of Common Stock. However, the determination of the amount of future cash dividends, if any, to be declared and paid will depend upon, among other things, the financial condition, funds from operations, level of exploration and development expenditure opportunities and future business prospects of the Company. 10 BUSINESS GENERAL The Company, a Delaware corporation organized in 1985, is engaged, either directly or through a marketing subsidiary with regard to domestic operations or through various subsidiaries with regard to international operations, in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad and India and to a lesser extent, selected other international areas. At December 31, 1994, the Company's estimated net proved natural gas reserves were 1,910 Bcf and estimated net proved crude oil, condensate and natural gas liquids reserves were 37 MMBbl. At such date, approximately 70% of the Company's reserves (on a natural gas equivalent basis) was located in the United States, 16% in Canada, 11% in Trinidad and 3% in India. The Company pursues its oil and gas exploration and development operations primarily by the acquisition, through various means including but not limited to leasing, purchasing and farming-in of acreage that is either undeveloped or lightly developed, and drilling of internally generated prospects. The Company also maintains a strategy of selling selected oil and gas properties that, for various reasons, no longer fit into future operating plans or which are not assessed to have sufficient future growth potential and when the economic value to be obtained by selling the properties and reserves in the ground is evaluated to be greater than what would be obtained by holding the properties and producing the reserves over time. As a result, the Company typically receives each year a varying but substantial level of proceeds related to such sales which proceeds are available for general corporate use. EXPLORATION AND PRODUCTION NORTH AMERICAN OPERATIONS The Company's seven principal United States producing areas are the Big Piney area, South Texas area, East Texas area, Offshore Gulf of Mexico area, Canyon Trend area, Pitchfork Ranch area and Vernal area. Properties in these areas comprised approximately 76% of the Company's United States reserves (on a natural gas equivalent basis) and 85% of the Company's United States net natural gas deliverability as of December 31, 1994 and are substantially all operated by the Company. At September 30, 1995, properties in these areas comprised approximately 87% of the Company's United States net natural gas deliverability. The Company's other United States natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico and in Oklahoma. At December 31, 1994, 93% of the Company's proved United States reserves (on a natural gas equivalent basis) was natural gas and 7% was crude oil, condensate and natural gas liquids. A substantial portion of the Company's United States natural gas reserves is in long-lived fields with well-established production histories. The Company believes that opportunities exist to increase production in many of these fields through continued infill and other development drilling. The Company also has natural gas and crude oil producing properties located in Western Canada, primarily in the provinces of Alberta, Saskatchewan and Manitoba. BIG PINEY AREA. The Company's largest reserve accumulation is located in the Big Piney area in Sublette and Lincoln counties in southwestern Wyoming. The Company is the holder of the largest productive acreage base in this area, with approximately 219,000 net acres under lease directly within field limits. The Company operates approximately 650 natural gas wells in this area in which it owns a 91% average working interest. Deliveries from the area net to the Company averaged 124 MMcf per day of natural gas and 1.5 MBbl per day of crude oil, condensate, and natural gas liquids in 1994. At September 30, 1995, natural gas deliverability net to the Company was approximately 138 MMcf per day. The current principal producing intervals are the Frontier and Mesaverde formations. The Frontier formation, which occurs at 6,500-10,000 feet, contains approximately 66% of the Company's current Big Piney reserves. The Company drilled 67 wells in the Big Piney area in 1994. Although natural gas drilling has been curtailed in this area during 1995 in response to market conditions, numerous drilling opportunities will be available for several years. 11 During the fourth quarter of 1995, the Company anticipates recording as proved undeveloped reserves approximately 1,100 Bcf of methane contained, along with high concentrations of carbon dioxide and nitrogen as well as small amounts of other gaseous substances, in the deep Wyoming Paleozoic formation located under acreage leased by the Company and held by production in the Big Piney area. The Company is actively pursuing the consummation of a market or markets from several different potential sources to facilitate realizing the value of these reserves. SOUTH TEXAS AREA. The Company's activities in South Texas are focused in the Wilcox, Expanded Wilcox, Frio and Lobo producing horizons. The principal area of activity is in the Lobo Trend which occurs primarily in Webb and Zapata counties. The Company operates approximately 470 wells in the South Texas area. Production is primarily from the Lobo sand of the Wilcox formation at depths ranging from 7,000 to 11,000 feet. The Company has approximately 250,000 net acres under lease in this area. Natural gas deliveries net to the Company averaged 181 MMcf per day in 1994. At September 30, 1995, natural gas deliverability from this area net to the Company was approximately 150 MMcf per day which was impacted during 1995 by the sale of selected properties. The Company drilled 56 wells in the South Texas area in 1994 and anticipates an active drilling program will continue for several years. EAST TEXAS AREA. The Company's activities in the East Texas area are primarily in the Carthage field, located in Panola County, and the North Milton field, located in northern Harris County. The Carthage field is the Company's newest area of concentration. This field is one of the most prolific fields in east Texas with production primarily from the Cotton Valley, Travis Peak and Pettit formations. In 1995, properties were acquired that doubled the Company's acreage position to 17,000 acres. An active drilling program is planned for the remainder of 1995 and for several years. The Company has an average 71% working interest in its holdings. The Company has continued its activity in the North Milton field where it now operates 19 wells and holds a 100% working interest in the acreage. Further drilling is planned for 1996. At September 30, 1995, deliverability from the East Texas area was approximately 35 MMcf per day of natural gas with almost 1.0 MBbl per day of condensate, both net to the Company. OFFSHORE GULF OF MEXICO AREA. At September 30, 1995, the Company held an interest in 191 blocks in the Offshore Gulf of Mexico area totaling 561,000 net acres. Of the 191 blocks, 133 are operated by the Company. These interests are located predominantly in federal waters offshore Texas and Louisiana. During 1995, the Company acquired a 50% interest in operations previously owned by Santa Fe Minerals complementing previously owned interests and adding significantly to the Company's offshore operations. Natural gas deliveries from this area averaged 83 MMcf per day during 1994 and 118 MMcf per day during the first nine months of 1995, both net to the Company. A substantial portion of such deliveries was from interests in the Matagorda trend with significant volumes also coming from the Mustang Island area. Deliverability from this area at September 30, 1995 was 160 MMcf per day net to the Company sourced principally as noted above. The Company has maintained an active drilling program in this area during 1994 and 1995 and anticipates a similar program to continue for several years. CANYON TREND AREA. The Company's activities in this area have been concentrated in Crockett, Sutton, Terrell and Val Verde Counties, Texas where the Company drilled 331 natural gas wells during the period 1992 through 1994. The Company holds approximately 91,800 net acres and now operates approximately 500 natural gas wells in this area in which it owns a 97% average working interest. Production is from the Canyon sands and Strawn limestone at depths from 5,500 to 11,500 feet. In 1994, natural gas deliveries from this area net to the Company averaged 65 MMcf per day. At September 30, 1995, natural gas deliverability from this area net to the Company was approximately 54 MMcf per day. The Company has maintained an active drilling program in the Canyon Trend area during 1995 and expects a similar program to continue for several years. PITCHFORK RANCH FIELD. The Pitchfork Ranch field located in Lea County, New Mexico, produces primarily from the Bone Spring, Atoka and Morrow formations. In 1994, deliveries net to the Company from this area averaged 36 MMcf per day of natural gas and approximately 2 MBbl per 12 day of crude oil, condensate and natural gas liquids. At September 30, 1995, deliverability from this area net to the Company was approximately 32 MMcf per day of natural gas and 3.6 MBbl per day of crude oil, condensate and natural gas liquids. The Company holds approximately 27,900 net acres and expects to maintain an active drilling program in this field for several years. VERNAL AREA. In the Vernal area, located primarily in Uintah County, Utah, the Company operates approximately 195 producing wells and presently controls approximately 79,000 net acres. For the first nine months of 1995, natural gas deliveries net to the Company from the Vernal area averaged 24 MMcf per day which represents deliverability. Production is from the Green River and Wasatch formations located at depths between 4,500-8,000 feet. The Company has an average working interest of approximately 60%. The Company drilled 20 wells in the Vernal area in 1994 and has maintained a comparable drilling program during 1995. CANADA. The Company is engaged in the exploration for and the development, production and marketing of natural gas and crude oil and the operation of natural gas processing plants in western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. The Company conducts operations from offices in Calgary. The Company produces natural gas from seven major areas and crude oil from three major areas. The Sandhills area in Southern Saskatchewan is the largest single producing area where 160 wells were drilled in 1994 resulting in deliverability net to the Company from the field of approximately 38 MMcf per day at December 31, 1994. Canadian natural gas deliverability net to the Company at September 30, 1995 was approximately 70 MMcf per day and the Company held approximately 350,000 net undeveloped acres in Canada. The Company expects to maintain an active drilling program in Canada for several years. OUTSIDE NORTH AMERICA OPERATIONS The Company has operations offshore Trinidad and India and is conducting exploration in selected other international areas. Properties offshore Trinidad and India comprised 100% of the Company's proved reserves and production outside of North America at year end 1994. TRINIDAD. In November 1992, the Company was awarded a 95% working interest concession in the South East Coast Consortium ("SECC") block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. The Kiskadee field has been developed, the Ibis field is under development and the Oil Bird field is anticipated to be developed over the next three to five years. Existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by Trinidad and Tobago government-owned companies is being used to process and transport the production. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. In 1994, deliveries net to the Company averaged 63 MMcf per day of natural gas and 2.6 MBbl per day of crude oil and condensate. At September 30, 1995, deliverability net to the Company was approximately 166 MMcf per day of natural gas and 8.0 MBbls per day of crude oil and condensate. The Company's net production from offshore Trinidad was approximately 100 MMcf per day of natural gas and 6.2 MBbl per day of crude oil and condensate at September 30, 1995. The Company held approximately 71,000 net undeveloped acres in Trinidad. The Company recently has been awarded the right to develop the U(a) block adjacent to the SECC block and is presently negotiating the terms of a production sharing contract with the Government of Trinidad and Tobago. INDIA. In December 1994, the Company signed agreements covering profit sharing, joint operations and product sales, and was granted a 30% working interest in, the Tapti, Panna and Mukta blocks located offshore Bombay, India. The Company is designated operator of all three areas. The blocks were previously operated by the Indian national oil company, Oil & Natural Gas Corporation Limited, which retained a 40% working interest. The 363,000 acre Tapti Block contains two major proved gas accumulations delineated by 22 expendable exploration wells that have been plugged. The Company has initiated a development plan for the Tapti Block accumulations. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with 30 wells producing from five producing platforms located in the Panna and Mukta fields. The fields were producing approximately 3.5 MBbl per day of crude oil net to the Company as of September 30, 13 1995; all associated natural gas was being flared. The Company intends to continue development of the accumulations and to expand processing capacity to allow crude oil production at full deliverability as well as to permit natural gas sales. OTHER INTERNATIONAL. The Company continues to evaluate other selected conventional natural gas and crude oil opportunities outside North America. The Company is pursuing other exploitation opportunities in countries where indigenous natural gas reserves have been identified, particularly where synergies in natural gas transportation, processing and power cogeneration can be optimized with other Enron Corp. affiliated companies. In early 1995, the Company and the Qatar General Petroleum Corporation signed a nonbinding letter of intent concerning the possible development of a liquefied natural gas project for natural gas to be produced from the North Dome Field. The Company and Enron Corp. may jointly hold up to a 40% working interest in the joint venture and drill and develop to-be-agreed-upon reserves. In addition, the Company signed letters of intent in early 1995 with the National Oil Corporation of Uzbekistan, and Gazprom, the Russian natural gas company, to pursue the feasibility of joint venture development and marketing of previously discovered conventional hydrocarbon reserves in Uzbekistan. The Company is also in discussions concerning the potential for conventional oil and gas development opportunities in China, Mozambique and Qatar. The Company holds nonoperating working interests in two conventional oil and gas exploration prospects in the U.K. North Sea. The Company continues evaluation and assessment of its international opportunity portfolio in the coalbed methane recovery arena, including projects in South Wales in the U.K., the Lorraine Basin in France, Galilee Basin in Queensland, Australia and Hedong basin in China. MARKETING WELLHEAD MARKETING The Company's North America wellhead natural gas production is currently being sold on the spot market and under long-term natural gas contracts at market responsive prices. In many instances, the long-term contract prices closely approximate the prices received for natural gas being sold on the spot market. Wellhead natural gas volumes from Trinidad are sold at prices that are based on a fixed price schedule with annual escalations. Natural gas volumes in India will be sold to the Gas Authority of India, Ltd. under a take-or-pay contract at a price linked to a basket of world market fuel oil quotations with floor and ceiling limits. Approximately 45% of the Company's wellhead natural gas production is currently being sold to pipeline and marketing subsidiaries of Enron Corp. The Company believes that the terms of its transactions and agreements with Enron Corp. and/or its affiliates are and intends that future such transactions and agreements will be at least as favorable to the Company as could be obtained from third parties. Substantially all of the Company's wellhead crude oil and condensate is sold under short-term contracts at market responsive prices. OTHER MARKETING Enron Oil & Gas Marketing, Inc. ("EOGM") is a wholly-owned subsidiary of the Company engaged in various marketing activities. Both the Company and EOGM contract to provide, under short and long-term agreements, natural gas to various purchasers and then aggregate the necessary supplies for the sales with purchases from various sources including third-party producers, marketing companies, pipelines or from the Company's own production. In addition, EOGM has purchased and constructed several small gathering systems in order to facilitate its entry into the gathering business on a strategic basis. Both the Company and EOGM utilize other short and long-term hedging and trading mechanisms including sales and purchases utilizing NYMEX-related commodity market transactions. All of these activities are currently conducted with companies affiliated with Enron Corp. These marketing activities have provided an effective balance in managing the Company's exposure to commodity price risks for both natural gas and crude oil and condensate wellhead prices. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Capital Resources and Liquidity -- Hedging Transactions." 14 WELLHEAD VOLUMES AND PRICES, AND LEASE AND WELL EXPENSES The following table sets forth certain information regarding the Company's wellhead volumes of and average prices for natural gas per Mcf, crude oil and condensate, and natural gas liquids per Bbl, and average lease and well expenses per Mcfe delivered during each of the three years in the period ended December 31, 1994 and the nine-month periods ended September 30, 1994 and 1995.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------------- -------------------- 1992 1993 1994 1994 1995 --------- --------- --------- --------- --------- VOLUMES (PER DAY) Natural Gas (MMcf) United States(1)........... 534 649 614 609 534 Canada..................... 30 58 72 71 75 Trinidad................... -- 2 63 63 110 --------- --------- --------- --------- --------- Total(1)................. 564 709 749 743 719 ========= ========= ========= ========= ========= Crude Oil and Condensate (MBbl) United States.............. 6.3 6.6 8.0 7.5 9.1 Canada..................... 2.2 2.2 2.0 1.9 2.4 Trinidad................... -- .1 2.5 2.6 4.8 India...................... -- -- .1 -- 2.3 --------- --------- --------- --------- --------- Total.................... 8.5 8.9 12.6 12.0 18.6 ========= ========= ========= ========= ========= Natural Gas Liquids (MBbl) United States.............. .3 .2 .3 .2 1.2 Canada..................... .4 .4 .4 .5 .3 --------- --------- --------- --------- --------- Total.................... .7 .6 .7 .7 1.5 ========= ========= ========= ========= ========= AVERAGE PRICES Natural Gas ($/Mcf) United States(2)........... $ 1.61 $ 1.97 $ 1.71 $ 1.79 $ 1.33 Canada..................... 1.18 1.34 1.42 1.51 .95 Trinidad................... -- .89 .93 .93 .97 Composite(2)............. 1.58 1.92 1.62 1.69 1.23 Crude Oil and Condensate ($/Bbl) United States.............. $ 18.29 $ 16.96 $ 16.06 $ 15.64 $ 17.20 Canada..................... 16.80 14.63 14.05 13.72 16.31 Trinidad................... -- 14.36 15.50 15.20 16.16 India...................... -- -- 15.70 -- 16.82 Composite................ 17.90 16.37 15.62 15.24 16.77 Natural Gas Liquids ($/Bbl) United States.............. $ 11.56 $ 13.85 $ 12.45 $ 12.50 $ 11.76 Canada..................... 10.05 9.46 8.45 7.86 9.69 Composite................ 10.69 11.12 9.90 9.43 11.27 LEASE AND WELL EXPENSES ($/MCFE) United States.............. $ .20 $ .18 $ .19 $ .19 $ .20 Canada..................... .50 .48 .34 .35 .35 Trinidad................... -- 1.46 .17 .15 .14 India...................... -- -- .13 -- 1.59 Composite................ .22 .21 .20 .20 .23
- ------------ (1) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf per day in 1994 and in the nine-month periods ended September 30, 1994 and 1995 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $1.70 per Mcf in 1992, $1.57 per Mcf in 1993, $1.27 per Mcf in 1994 and $1.32 per Mcf and $.76 per Mcf in the nine-month periods ended September 30, 1994 and 1995, respectively, for the volumes described in note (1), net of transportation costs. 15 OTHER NATURAL GAS MARKETING VOLUMES AND PRICES The following table sets forth certain information regarding the Company's volumes of natural gas delivered under other marketing and volumetric production payment arrangements, and resulting average per unit gross revenue and per unit amortization of deferred revenues along with associated costs during each of the three years in the period ended December 31, 1994 and the nine-month periods ended September 30, 1994 and 1995.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ------------------------------- -------------------- 1992 1993 1994 1994 1995 --------- --------- --------- --------- --------- Volumes (MMcf per day)(1)............ 255 293 324 327 266 Average Gross Revenue ($/Mcf)(2)..... $ 2.62 $ 2.57 $ 2.38 $ 2.41 $ 1.87 Associated Costs ($/Mcf)(3)(4)....... 1.99 2.32 2.06 2.13 1.49 --------- --------- --------- --------- --------- Margin ($/Mcf)....................... $ 0.63 $ 0.25 $ 0.32 $ 0.28 $ 0.38 ========= ========= ========= ========= =========
- ------------ (1) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf per day in 1994 and in the nine-month periods ended September 30, 1994 and 1995 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (2) Includes per unit deferred revenue amortization for the volumes detailed in note (1) at an equivalent of $2.51 per Mcf in 1992, $2.50 per Mcf in 1993, $2.46 per Mcf in 1994 and $2.46 per Mcf and $2.47 per Mcf in the nine-month periods ended September 30, 1994 and 1995, respectively. (3) Includes an average value of $2.37 per Mcf in 1992, $2.20 per Mcf in 1993, $1.92 per Mcf in 1994 and $1.99 per Mcf and $1.50 per Mcf in the nine-month periods ended September 30, 1994 and 1995, respectively, including average equivalent wellhead value, any applicable transportation costs and exchange differentials, for the volumes detailed in note (1). (4) Including transportation and exchange differentials. OIL AND GAS EXPLORATION AND PRODUCTION PROPERTIES AND RESERVES The following tables set forth the Company's net proved and proved developed reserves at December 31, 1993 and 1994, and the changes in the net proved reserves for the year 1994 as estimated by the Company's engineering staff. The additional disclosures that include volumes attributable to a volumetric production payment set forth in the following tables are presented as additional information and are not intended to represent required disclosure pursuant to SFAS No. 69 -- "Disclosures about Oil and Gas Producing Activities."
UNITED STATES CANADA TRINIDAD INDIA TOTAL ------------- ------ -------- --------- --------- Natural Gas (Bcf) Net proved reserves at December 31, 1993...................... 1,313.2 271.0 100.5 -- 1,684.7 Additional disclosures: Volumes attributable to volumetric production payment.................. 87.5 -- -- -- 87.5 ------------- ------ -------- --------- --------- Net proved reserves at December 31, 1993, including volumes attributable to volumetric production payment............ 1,400.7 271.0 100.5 -- 1,772.2 ============= ====== ======== ========= ========= Net proved reserves at December 31, 1993...................... 1,313.2 271.0 100.5 -- 1,684.7 Revisions of previous estimates................ (17.1) (6.5) 15.0 -- (8.6) Purchases in place......... 18.8 9.2 -- 29.3 57.3 Extensions, discoveries and other additions.......... 233.8 50.2 113.9 -- 397.9 Sales in place............. (29.3) (1.0) -- -- (30.3) Production................. (212.0) (26.3) (23.2) -- (261.5) ------------- ------ -------- --------- --------- Net proved reserves at December 31, 1994...................... 1,307.4 296.6 206.2 29.3 1,839.5 16 UNITED STATES CANADA TRINIDAD INDIA TOTAL ------------- ------ -------- --------- --------- Additional disclosures: Volumes attributable to volumetric production payment.................. 70.9 -- -- -- 70.9 ------------- ------ -------- --------- --------- Net proved reserves at December 31, 1994, including volumes attributable to volumetric production payment............ 1,378.3 296.6 206.2 29.3 1,910.4 ============= ====== ======== ========= ========= Liquids (MBbl)(1) Net proved reserves at December 31, 1993...................... 13,172 5,471 2,218 -- 20,861 Revisions of previous estimates................ 2,179 (177) 455 -- 2,457 Purchases in place......... 358 -- -- 7,617 7,975 Extensions, discoveries and other additions.......... 5,332 2,848 2,687 -- 10,867 Sales in place............. (257) -- -- -- (257) Production................. (2,997) (905) (931) (32) (4,865) ------------- ------ -------- --------- --------- Net proved reserves at December 31, 1994...................... 17,787 7,237 4,429 7,585 37,038 ============= ====== ======== ========= ========= UNITED STATES CANADA TRINIDAD INDIA TOTAL ------------- ------ -------- --------- --------- Net proved developed reserves at Natural Gas (Bcf) December 31, 1993.......... 1,079.8 250.6 71.4 -- 1,401.8 December 31, 1994.......... 1,128.2 288.3 206.2 -- 1,622.7 Liquids (MBbl)(1) December 31, 1993.......... 11,165 5,409 1,591 -- 18,165 December 31, 1994.......... 16,770 7,073 4,429 7,585 35,857 UNITED STATES CANADA TRINIDAD INDIA TOTAL ------------- ------ -------- --------- --------- Net proved developed reserves, including amounts attributable to volumetric production payment at Natural Gas (Bcf) December 31, 1993.......... 1,167.3 250.6 71.4 -- 1,489.3 December 31, 1994.......... 1,199.1 288.3 206.2 -- 1,693.6 Liquids (MBbl)(1) December 31, 1993.......... 11,165 5,409 1,591 -- 18,165 December 31, 1994.......... 16,770 7,073 4,429 7,585 35,857
- ------------ (1) Includes crude oil, condensate and natural gas liquids. Estimates of proved and proved developed reserves at December 31, 1993 and 1994 were based on studies performed by the Company's engineering staff for reserves in the United States, Canada, Trinidad and India. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1993 and 1994 covering producing areas containing 65% and 59%, respectively, of proved reserves of the Company on a net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved reserves prepared by the Company's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net- equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by DeGolyer and MacNaughton. Such estimates by DeGolyer and MacNaughton in the aggregate varied by not more than 5% from those prepared by the Company's engineering staff. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by the Company. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth herein represent only estimates. Reserve engineering is a subjective process of estimating underground accumulations of 17 natural gas and liquids, including crude oil, condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties owned by the Company declines as reserves are depleted. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of the Company will decline as reserves are produced. Volumes generated from future activities of the Company are therefore highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so. ACREAGE The following tables summarize the Company's developed and undeveloped acreage at December 31, 1994 and September 30, 1995. Excluded is acreage in which the Company's interest is limited to owned royalty, overriding royalty and other similar interests.
DEVELOPED UNDEVELOPED TOTAL -------------------------- ---------------------------- ---------------------------- GROSS NET GROSS NET GROSS NET ------------ ------------ ------------- ------------- ------------- ------------- At December 31, 1994: United States................... 978,427 637,870 1,952,656 1,705,716 2,931,083 2,343,586 Canada.......................... 501,989 307,996 437,523 353,550 939,512 661,546 India........................... 60,000 18,000 602,207 180,662 662,207 198,662 Trinidad........................ 4,200 3,990 74,851 71,108 79,051 75,098 Other International............. -- -- 13,913,600 11,756,800 13,913,600 11,756,800 ------------ ------------ ------------- ------------- ------------- ------------- Total...................... 1,544,616 967,856 16,980,837 14,067,836 18,525,453 15,035,692 ============ ============ ============= ============= ============= ============= At September 30, 1995: United States................... 1,554,024 661,647 2,321,727 1,775,151 3,875,751 2,436,798 Canada.......................... 559,534 335,559 424,302 349,503 983,836 685,062 India........................... 60,000 18,000 602,207 180,662 662,207 198,662 Trinidad........................ 4,200 3,990 74,851 71,108 79,051 75,098 Other International............. -- -- 13,422,400 11,773,100 13,422,400 11,773,100 ------------ ------------ ------------- ------------- ------------- ------------- Total...................... 2,177,758 1,019,196 16,845,487 14,149,524 19,023,245 15,168,720 ============ ============ ============= ============= ============= =============
18 DRILLING AND ACQUISITION ACTIVITIES During the years ended December 31, 1992, 1993 and 1994 and the nine months ended September 30, 1995 the Company spent approximately $396, $430, $494 and $401 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. The Company drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated:
NINE MONTHS YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30, -------------------------------------------------------- ------------------- 1992 1993 1994 1995 ---------------- ---------------- ---------------- ------------------- GROSS NET GROSS NET GROSS NET GROSS NET ----- ------- ----- ------- ----- ------- ------ --------- Development Wells Completed Domestic Gas........................ 484 399.06 352 279.00 308 244.23 99 77.78 Oil........................ 19 10.80 45 19.01 34 29.57 36 32.06 Dry........................ 64 56.12 59 46.83 41 32.15 38 30.80 ----- ------- ----- ------- ----- ------- ----- ------- Total.................... 567 465.98 456 344.84 383 305.95 173 140.64 International Gas........................ 2 2.00 227 190.10 250 190.30 116 107.66 Oil........................ 13 11.70 4 3.50 11 5.10 13 8.21 Dry........................ 5 4.05 11 7.60 13 11.50 11 8.38 ----- ------- ----- ------- ----- ------- ----- ------- Total.................... 20 17.75 242 201.20 274 206.90 140 124.25 ----- ------- ----- ------- ----- ------- ----- ------- Total Development............... 587 483.73 698 546.04 657 512.85 313 264.89 ----- ------- ----- ------- ----- ------- ----- ------- Exploratory Wells Completed Domestic Gas........................ 11 8.72 14 10.03 13 9.80 4 2.52 Oil........................ 1 .40 3 2.50 3 2.57 3 2.63 Dry........................ 16 13.42 32 22.08 23 18.17 6 4.47 ----- ------- ----- ------- ----- ------- ----- ------- Total.................... 28 22.54 49 34.61 39 30.54 13 9.62 International Gas........................ 7 5.75 14 11.40 9 7.90 2 1.24 Oil........................ 4 3.69 2 .90 1 .50 2 2.00 Dry........................ 4 2.85 10 7.35 14 12.50 5 3.70 ----- ------- ----- ------- ----- ------- ----- ------- Total.................... 15 12.29 26 19.65 24 20.90 9 6.94 ----- ------- ----- ------- ----- ------- ----- ------- Total Exploratory............... 43 34.83 75 54.26 63 51.44 22 16.56 ----- ------- ----- ------- ----- ------- ----- ------- Total.................... 630 518.56 773 600.30 720 564.29 335 281.45 Wells in Progress at end of period... 82 60.75 82 61.09 45 28.79 53 38.72 ----- ------- ----- ------- ----- ------- ----- ------- Total.................... 712 579.31 855 661.39 765 593.08 388 320.17 ===== ======= ===== ======= ===== ======= ===== ======= Wells Acquired Gas............................. 641 597.29* 44 26.44* 41 40.90* 271 97.37* Oil............................. 28 25.80* -- 12.80* 60 38.99* 5 .93* ----- ------- ----- ------- ----- ------- ----- ------- Total.................... 669 623.09 44 39.24 101 79.89 276 98.30 ===== ======= ===== ======= ===== ======= ===== =======
- ------------ * Includes the acquisition of additional interests in certain wells in which the Company previously held an interest. All of the Company's drilling activities are conducted on a contract basis with independent drilling contractors. The Company owns no drilling equipment. 19 SELECTED CONSOLIDATED FINANCIAL AND OPERATING INFORMATION The following table sets forth a summary of selected consolidated financial and operating information for the Company for each of the five years in the period ended December 31, 1994 and the nine-month periods ended September 30, 1994 and 1995. This information should be read in conjunction with the consolidated financial statements of the Company and related notes thereto incorporated by reference herein (see "Incorporation of Certain Documents by Reference") and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere in this Prospectus. Financial information for each of the five years in the period ended December 31, 1994 has been derived from audited financial statements. Financial information for the nine-month periods ended September 30, 1994 and 1995 has been derived from unaudited financial statements. The interim data reflects all adjustments which, in the opinion of the management of the Company, are necessary to present fairly such information for the interim periods. Results of the nine-month periods are not necessarily indicative of the results expected for a full year or any other interim period.
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, --------------------------------------------------------------- ------------------------ 1990 1991 1992 1993 1994 1994 1995 ----------- ----------- ----------- ----------- ----------- ----------- ----------- (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) STATEMENT OF INCOME DATA: Net operating revenues Natural gas...................... $ 301,645 $ 321,603 $ 388,988 $ 505,162 $ 489,893 $ 365,654 $ 332,015 Crude oil, condensate and natural gas liquids.................... 66,165 62,836 58,927 55,834 76,338 52,632 90,342 Gains on sales of reserves and related assets................. 31,802 14,983 6,037 13,318 54,014 52,212 62,546 Other............................ 3,525 3,166 5,074 6,706 5,578 3,842 7,439 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total........................ 403,137 402,588 459,026 581,020 625,823 474,340 492,342 Operating expenses Lease and well................... 43,806 49,922 49,406 59,344 60,384 44,782 52,918 Exploration...................... 35,031 31,470 33,278 36,921 41,811 29,647 31,590 Dry hole......................... 12,986 14,698 10,764 18,355 17,197 10,803 8,586 Impairment of unproved oil and gas properties................. 20,571 12,791 15,136 20,467 24,936 17,364 20,453 Depreciation, depletion and amortization................... 155,877 160,885 179,839 249,704 242,182 181,645 157,875 General and administrative....... 38,254 36,216 36,648 45,274 51,418 38,050 41,186 Taxes other than income.......... 22,966 18,222 28,346 35,396 28,254 22,010 25,606 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total........................ 329,491 324,204 353,417 465,461 466,182 344,301 338,214 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Operating income..................... 73,646 78,384 105,609 115,559 159,641 130,039 154,128 Other income (expense)............... (2,153) (3,215) (3,476) 6,635 2,783 2,238 (1,143) Interest expense (net of interest capitalized)....................... 36,879 29,500 22,289 9,921 8,489 6,111 8,810 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Income before income taxes........... 34,614 45,669 79,844 112,273 153,935 126,166 144,175 Income tax provision (benefit)(1).... (10,854) (2,247) (17,736) (25,752)(2) 5,937(3) 20,728 33,444(4) ----------- ----------- ----------- ----------- ----------- ----------- ----------- Net income........................... $ 45,468 $ 47,916 $ 97,580 $ 138,025 $ 147,998 $ 105,438 $ 110,731 =========== =========== =========== =========== =========== =========== =========== Earnings per share of common stock(5)........................... $ .30 $ .32 $ .63 $ .86 $ .93 $ .66 $ .69 =========== =========== =========== =========== =========== =========== =========== Average number of common shares(5)... 151,800 151,800 154,533 159,996 159,845 159,826 159,951 =========== =========== =========== =========== =========== =========== =========== BALANCE SHEET DATA (AT PERIOD END): Net oil and gas properties........... $ 1,305,136 $ 1,339,666 $ 1,468,011 $ 1,546,045 $ 1,684,811 $ 1,637,762 $ 1,843,150 Total assets......................... 1,417,939 1,455,608 1,731,012 1,811,162 1,861,867 1,855,819 2,109,971 Long-term debt Affiliate........................ 277,918 132,836 --(6) -- 25,000 25,000 16,320 Other............................ 140,442 289,556 150,000(6) 153,000 165,337 158,862 247,552 Deferred revenue..................... -- -- 301,395 227,528 184,183 195,109 224,085 Shareholders' equity................. 610,042 643,185 826,986(6) 933,073 1,043,419 1,019,712 1,140,295 20 OPERATING DATA: Wellhead Volumes and Prices Natural Gas Volumes (MMcf per day) United States(7)................. 437 466 534 649 613 609 534 Canada........................... 18 25 30 58 73 71 75 Trinidad......................... -- -- -- 2 63 63 110 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total(7)..................... 455 491 564 709 749 743 719 =========== =========== =========== =========== =========== =========== =========== Average Natural Gas Prices ($/Mcf) United States.................... $ 1.51 $ 1.38 $ 1.61 $ 1.97 $ 1.71 $ 1.79 $ 1.33 Canada........................... 1.47 1.32 1.18 1.34 1.42 1.51 .95 Trinidad......................... -- -- -- .89 .93 .93 .97 Composite.................... 1.51 1.37 1.58 1.92 1.62 1.69 1.23 Crude/Condensate Volumes (MBbl per day) United States.................... 5.8 5.9 6.3 6.6 8.0 7.5 9.1 Canada........................... 2.4 2.3 2.2 2.2 2.0 1.9 2.4 Trinidad......................... -- -- -- .1 2.5 2.6 4.8 India............................ -- -- -- -- .1 -- 2.3 ----------- ----------- ----------- ----------- ----------- ----------- ----------- Total........................ 8.2 8.2 8.5 8.9 12.6 12.0 18.6 =========== =========== =========== =========== =========== =========== =========== Average Crude/Condensate Prices ($/Bbl) United States.................... $21.95 $19.24 $18.29 $16.96 $16.06 $15.64 $17.20 Canada........................... 21.01 17.58 16.80 14.63 14.05 13.72 16.31 Trinidad......................... -- -- -- 14.36 15.50 15.20 16.16 India............................ -- -- -- -- 15.70 -- 16.82 Composite.................... 21.67 18.78 17.90 16.37 15.62 15.24 16.77 Natural Gas Liquids Volumes (MBbl per day) United States.................... .4 .3 .3 .2 .3 .2 1.2 Canada........................... -- .3 .4 .4 .4 .5 .3 Total........................ .4 .6 .7 .6 .7 .7 1.5 Average Natural Gas Liquids Prices ($/Bbl) United States.................... $10.59 $10.79 $11.56 $13.85 $12.45 $12.50 $11.76 Canada........................... -- 12.48 10.05 9.46 8.45 7.86 9.69 Composite.................... 10.59 11.64 10.69 11.12 9.90 9.43 11.27
- ------------ (1) Includes benefits of approximately $17 million, $43 million, $65 million and $36 million in 1991, 1992, 1993 and 1994, respectively, and $29 million and $16 million in the nine-month periods ended September 30, 1994 and 1995, respectively, relating to tight gas sand federal income tax credits and $25 million and $7 million in 1990 and 1991, respectively, associated with the utilization of a net operating loss carryforward. (2) Includes a benefit of $12 million from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements partially offset by an approximate $7 million predominantly non-cash charge primarily to adjust the Company's accumulated deferred income tax liability for the increase in the corporate federal income tax rate from 34% to 35%. (3) Includes a benefit of approximately $8 million related to reduced estimated state income taxes and certain franchise taxes, a portion of which is treated as income tax under SFAS No. 109 -- "Accounting for Income Taxes", and a $5 million benefit from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements. (4) Includes a $12 million benefit associated with the successful resolution on audit of federal income taxes for certain prior years. (5) In May 1994, the Board of Directors declared a two-for-one split of the Company's Common Stock to be effected as a non-taxable dividend of one share for each share outstanding. Shares were issued on June 15, 1994 to shareholders of record as of May 31, 1994. All share and per share amounts presented herein are reflected on a post-split basis. (6) In August 1992, the Company completed the sale of an additional 8.2 million shares of Common Stock resulting in aggregate net proceeds to the Company of approximately $112 million used primarily to repay long-term debt. In September 1992, the Company completed the sale of a volumetric production payment, resulting in net proceeds of approximately $327 million used to repay long-term debt and for other general corporate purposes. (7) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf per day in 1994 and in the nine-month periods ended September 30, 1994 and 1995 delivered under the terms of a volumetric production payment effective October 1, 1992, as amended. 21 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of operations for each of the three years in the period ended December 31, 1994 and for the nine-month periods ended September 30, 1994 and 1995 should be read in conjunction with the consolidated financial statements of the Company and notes thereto and other financial data incorporated by reference herein. See "Incorporation of Certain Documents by Reference." RESULTS OF OPERATIONS NET OPERATING REVENUES Wellhead volume and price statistics for the specified periods were as follows:
NINE MONTHS ENDED YEAR ENDED DECEMBER 31, SEPTEMBER 30, ---------------------------------- -------------------- 1992 1993 1994 1994 1995 ---------- ---------- ---------- --------- --------- Natural Gas Volumes (MMcf per day) North America(1)........... 564 707 686 680 609 Trinidad................... -- 2 63 63 110 ---------- ---------- ---------- --------- --------- Total................. 564 709 749 743 719 ========== ========== ========== ========= ========= Average Natural Gas Prices ($/Mcf) North America(2)........... $ 1.58 $ 1.92 $ 1.68 $ 1.76 $ 1.28 Trinidad................... -- .89 .93 .93 .97 Composite............. 1.58 1.92 1.62 1.69 1.23 Crude/Condensate Volumes (MBbl per day) North America.............. 8.5 8.8 10.0 9.4 11.5 Trinidad................... -- .1 2.5 2.6 4.8 India...................... -- -- .1 -- 2.3 ---------- ---------- ---------- --------- --------- Total................. 8.5 8.9 12.6 12.0 18.6 ========== ========== ========== ========= ========= Average Crude/Condensate Prices ($/Bbl) North America.............. $ 17.90 $ 16.39 $ 15.65 $ 15.25 $ 17.01 Trinidad................... -- 14.36 15.50 15.20 16.16 India...................... -- -- 15.70 -- 16.82 Composite............. 17.90 16.37 15.62 15.24 16.77
- ------------ (1) Includes 28 MMcf per day in 1992, 81 MMcf per day in 1993 and 48 MMcf per day in 1994 and in the nine-month periods ended September 30, 1994 and 1995 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $1.70 per Mcf in 1992, $1.57 per Mcf in 1993, $1.27 per Mcf in 1994 and $1.32 per Mcf and $.76 per Mcf in the nine-month periods ended September 30, 1994 and 1995, respectively, for the volumes detailed in note (1), net of transportation costs. NINE MONTHS 1995 COMPARED TO NINE MONTHS 1994. During the first nine months of 1995, net operating revenues increased $18 million to $492 million as compared to the same period in 1994. Average wellhead natural gas prices for the first nine months of 1995 were down approximately 27% from the same period in 1994 reducing net operating revenues by approximately $90 million. In addition, a decrease of 3% in wellhead natural gas volumes from the first nine months of 1994 reduced net operating revenues by approximately $11 million. The Company voluntarily curtailed its United States wellhead natural gas delivered volumes by an average of approximately 140 MMcf per day during the first nine months of 1995 compared to approximately 110 MMcf per day during the 22 same period in 1994 due to significantly lower United States wellhead natural gas prices. In addition, the impact of the sales of oil and gas reserves and related assets (net of purchases of similar assets) resulted in a reduction of approximately 40 MMcf per day in delivered volumes for the first nine months of 1995 as compared to the first nine months of 1994. The Company refocused its 1995 drilling activity away from natural gas deliverability and toward natural gas reserve enhancement and crude oil exploitation in the United States in response to the significant decline in United States natural gas prices in recent periods. Wellhead crude oil and condensate average prices increased 10% adding approximately $8 million to net operating revenues compared to the first nine months of 1994. Crude oil and condensate wellhead volumes increased 55% adding approximately $27 million to net operating revenues compared to the same period a year ago primarily reflecting new production on stream offshore India, and higher volumes offshore Trinidad and in North America. Other marketing activities associated with sales and purchases of natural gas, natural gas price swap transactions, other commodity price hedging of natural gas and crude oil and condensate prices utilizing NYMEX-related commodity market transactions, and volumetric production payment related margins added approximately $91 million to net operating revenues during the first nine months of 1995, an increase of approximately $67 million from the same period in 1994. This increase primarily resulted from a gain of $51 million on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in the first nine months of 1995 compared to a $2 million loss during the same period in 1994 and increased margins associated with other natural gas marketing activities. The average associated costs of natural gas marketing, price swap and volumetric production payment transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, decreased $.64 per Mcf. The average price received for these transactions decreased $.54 per Mcf. Related other natural gas marketing volumes decreased 19%. The reduction in other natural gas marketing volumes and prices relates primarily to the exchange of the fuel contracts noted below, lower wellhead market prices and decreased other marketing activities. The $.10 per Mcf margin increase partially offset by the reduction in other natural gas marketing volumes increased net operating revenues by approximately $3 million compared to the first nine months of 1994. The Company realized an $11 million gain in the first nine months of 1995 related to certain NYMEX-related commodity market transactions with an Enron Corp. affiliated company that were designated for trading purposes in late 1994. The Company had no open trading positions at September 30, 1995. See "Trading Transactions." In March 1995, the Company exchanged existing fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant for certain natural gas price swap agreements of equivalent value issued by an Enron Corp. affiliated company. As a result of these transactions, the Company realized a $8.4 million increase in net operating revenues in the first nine months of 1995 over the amount realized from the exchanged fuel supply and purchase contracts in the same period of 1994. See "Relationship Between the Company and Enron Corp. -- Contractual Agreements." Gains on sales of reserves and related assets during the first nine months of 1995 increased $10 million to $63 million when compared to the same period in 1994 which increase was attributable to the Company's continuing efforts in optimizing the use of its assets. 1994 COMPARED TO 1993. During 1994, net operating revenues increased to $626 million, up $45 million as compared to 1993. Average wellhead natural gas volumes increased approximately 6% compared to 1993 primarily reflecting the effects of development activities offshore Trinidad and in Canada partially offset by voluntary curtailments of production in the United States in 1994. The volume reductions in the United States as a result of voluntary curtailments were more than offset by the new natural gas deliveries from the Kiskadee field offshore Trinidad and increased deliveries in Canada. The increase in wellhead natural gas volumes added $28 million to net operating revenues. Average wellhead natural gas prices were down significantly from 1993 reducing net operating revenues by 23 approximately $83 million. This 16% reduction in average wellhead natural gas prices reflects the overall decline in the United States natural gas markets during the last half of 1994 and increased volumes offshore Trinidad sold under a long-term contract at a price considerably below North America spot market prices. A 42% increase in wellhead crude oil and condensate volumes over 1993 added $22 million to net operating revenues primarily reflecting development activities offshore Trinidad and increased production in the United States. A 5% decrease in wellhead crude oil and condensate average prices decreased net operating revenues by approximately $3 million. Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price swap transactions, other commodity price hedging of natural gas and crude oil prices utilizing NYMEX-related commodity market transactions, and margins relating to the volumetric production payment added $50 million to net operating revenues during 1994. This increase of $41 million from the same period in 1993 primarily results from a gain of $11 million on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in 1994 versus an $18 million loss during 1993 and increased margins associated with other natural gas marketing activities. The average associated costs of natural gas marketing, price swap and volumetric production payment transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, decreased $.26 per Mcf. The average price received for these transactions decreased $.19 per Mcf. Related other natural gas marketing volumes increased 10%. Gains on sales of selected oil and gas reserves and related assets were $54 million in 1994 as compared to $13 million in 1993. While the quantity of equivalent reserves sold in 1994 was slightly less than 1993, higher average proceeds received per equivalent unit in 1994 as compared to 1993 primarily contributed to the increased gain recognition. In continuing its strategy of fully utilizing its assets in optimizing profitability, cash flow and return on investments, the Company expects to continue the sale of similar properties from time to time. 1993 COMPARED TO 1992. During 1993, net operating revenues increased to $581 million, up $122 million as compared to 1992. Average wellhead natural gas volumes increased approximately 26% compared to 1992 primarily reflecting the effects of exploration and development activities relating to tight gas sand formations. Wellhead natural gas delivered volumes were curtailed less during portions of 1993 than for the comparable periods in 1992 due to the significant increases realized in wellhead natural gas prices in 1993. Average wellhead natural gas prices were up approximately 22% in 1993 over those received in 1992, adding approximately $87 million to net operating revenues. Increases in wellhead natural gas volumes in 1993 added $83 million to net operating revenues compared to 1992. Average wellhead crude oil and condensate prices in 1993 were down 9% compared to 1992, reducing net operating revenues by $5 million. Increases in wellhead crude oil and condensate volumes in 1993 added approximately $2 million to net operating revenues compared to 1992. Other marketing activities associated with sales and purchases of natural gas, natural gas price swap transactions, other commodity price hedging of natural gas and crude oil and condensate prices utilizing NYMEX-related commodity market transactions, and margins relating to the volumetric production payment added $8 million to net operating revenues during 1993. This decrease of $54 million from 1992 primarily results from shrinking margins associated with sales under long-term fixed price contracts and amortization of volumetric production payment deferred revenue due to increases in market responsive natural gas prices associated with volumes supplying these dispositions and losses on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions. The average associated costs of natural gas marketing, price swap and volumetric production payment transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, increased $.33 per Mcf. Related other natural gas marketing volumes increased 15%. 24 The impact of the other marketing activities, a substantial portion of which serve as hedges of commodity price risks for a portion of wellhead deliveries for the respective periods, were more than offset by reductions in revenues associated with market responsive prices for wellhead deliveries during those periods. OPERATING EXPENSES NINE MONTHS 1995 COMPARED TO NINE MONTHS 1994. During the first nine months of 1995, operating expenses of $338 million were $6 million lower than the $344 million incurred in the same period in 1994. Lease and well expenses increased approximately $8 million to $53 million primarily due to expanded international operations including the initiation of operations in India in late December 1994 partially offset by reductions in United States lease and well expenses. Exploration expenses increased $2 million to $32 million due to increased exploration activities. Impairment of unproved oil and gas properties for the first nine months of 1995 increased $3 million from the comparable period a year ago primarily due to impairments associated with certain offshore Gulf of Mexico leases. Depreciation, depletion and amortization ("DD&A") expense decreased $24 million to $158 million reflecting a decrease in the average DD&A rate from $.81 per Mcfe in the first nine months of 1994 to $.69 per Mcfe in the first nine months of 1995. The DD&A rate decrease is primarily attributable to increased production from international operations with lower average DD&A rates than incurred for North America operations. General and administrative expenses increased approximately $3 million to $41 million due to expanded international activities and overall higher costs associated with certain employee related expenses. Taxes other than income were $4 million higher in the first nine months of 1995 compared to the same period in 1994 primarily due to a reduction included in 1994 associated with state franchise taxes and higher production related taxes associated with new production in India in the first nine months of 1995 partially offset by decreases in state severance taxes due to lower taxable North America wellhead volumes and average prices in 1995. The Company reduced its total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income by $.06 per Mcfe, averaging $1.25 per Mcfe during the first nine months of 1995 compared to $1.31 per Mcfe during the same period in 1994. This decrease is primarily attributable to the reduction in the average DD&A rate as noted above partially offset by increases in per unit lease and well, general and administrative expenses, and taxes other than income. 1994 COMPARED TO 1993. During 1994, total operating expenses of $466 million were approximately $1 million higher than the $465 million incurred in 1993. Lease and well expenses of $60 million were approximately $1 million higher than 1993 primarily due to increased expenses related to new operations offshore Trinidad partially offset by cost reductions in North America. Exploration expenses of $42 million increased $5 million from the previous year primarily due to an increased level of exploration activities. Impairment of unproved oil and gas properties increased $4 million from 1993 primarily due to impairments associated with certain offshore Gulf of Mexico leases. DD&A expense decreased from $250 million in 1993 to $242 million in 1994 reflecting a $.09 per Mcfe decrease in the average DD&A rate to $.80 per Mcfe. The rate decrease is primarily due to increased production from offshore Trinidad at an average DD&A rate significantly less than the North America operations DD&A rate and a $.03 per Mcfe reduction in the North America operations DD&A rate. General and administrative expenses increased $6 million to $51 million primarily due to overall higher costs associated with expanded international and domestic operations. Taxes other than income decreased approximately $7 million from 1993 primarily due to lower taxable United States wellhead volumes and prices and reductions included in 1994 related to revisions of certain prior year production taxes. Included in 1994 and 1993 are benefits associated with reductions in state franchise taxes of $4 million and $3 million, respectively. The Company continues to benefit from certain state severance tax exemptions allowed on high cost natural gas volumes. 25 Total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income decreased $.14 per Mcfe, averaging $1.29 per Mcfe during 1994 compared to $1.43 per Mcfe for 1993. The decrease was primarily due to per unit reductions in DD&A and taxes other than income as discussed above. 1993 COMPARED TO 1992. During 1993, total operating expenses of $465 million were $112 million higher than the $353 million incurred in 1992. Lease and well expenses increased approximately $10 million primarily due to expanded domestic and international operations. Exploration expenses increased approximately $4 million primarily due to increased exploration activities in North America. An unsuccessful Gulf of Mexico well added nearly $4 million to dry hole expenses and a related $3 million to lease impairments in 1993. Dry hole expenses also reflect the impact of increased drilling activity outside North America. DD&A expense increased $70 million to $250 million reflecting an increase in production volumes and an average DD&A rate increase from $.79 per Mcfe in 1992 to $.89 per Mcfe for 1993. The DD&A rate increase is primarily due, as expected, to factors associated with the tight gas sands drilling program which costs are being more than offset by benefits realized in the form of tight gas sand federal income tax credits and certain state severance tax exemptions. General and administrative expenses increased almost $9 million to $45 million primarily reflecting cost reductions included in 1992 related to changes associated with certain employee compensation plans and overall higher costs in 1993 due to an expansion of domestic and international operations. Taxes other than income increased $7 million primarily due to increased production volumes and revenues in 1993, partially offset by continuing benefits associated with certain state severance tax exemptions allowed on high cost natural gas volumes and a $3 million reduction of state franchise taxes resulting from refunds of prior year payments received in 1993. Total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income increased $.03 per Mcfe, averaging $1.43 per Mcfe during 1993 compared to $1.40 per Mcfe for 1992. The total increase was associated with DD&A expense which was up $.10 per Mcfe as noted above being partially offset by a reduction of $.07 Mcfe in all other costs. OTHER INCOME Other income for 1993 includes $4 million in interest income associated with the investment of funds temporarily surplus to the Company and $4 million associated with settlements related to the termination of certain long-term natural gas contracts. INTEREST EXPENSE Net interest expense for the first nine months of 1995 was up $3 million as compared to the same period in 1994 reflecting primarily a higher level of debt outstanding during the 1995 period. Net interest expense in 1994 decreased approximately $1 million to $8 million as compared to 1993 primarily due to favorable interest rates on new financing acquired by a subsidiary of the Company for operations offshore Trinidad and the retirement of higher interest rate debt. The estimated fair value of outstanding interest rate swap agreements at December 31, 1994 was a negative $0.5 million based on termination values obtained from third parties. Net interest expense decreased $12 million, or 55%, to $10 million in 1993 as compared to 1992 reflecting the repayment of a substantial portion of the Company's long-term debt in 1992 with proceeds from the sale of common stock in August 1992 and the sale of a volumetric production payment in September 1992. The estimated fair value of outstanding interest rate swap agreements at December 31, 1993 was a negative $3.3 million based upon termination values obtained from third parties. 26 INCOME TAXES Income tax provision increased $13 million for the first nine months of 1995 as compared to the same period in 1994 primarily resulting from higher income before income taxes and lower benefits associated with tight gas sand federal income tax credits utilized in the first nine months of 1995 as compared to the same period in 1994 partially offset by a $12 million benefit associated with the successful resolution on audit of federal income taxes for certain prior years. Income tax provision in 1994 includes a benefit of approximately $36 million associated with tight gas sand federal income tax credit utilization, a benefit of approximately $8 million related to reduced estimated state income taxes and a portion of certain franchise taxes which is treated as income tax under SFAS No. 109, and a $5 million benefit from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements. Income tax benefit in 1993 includes a benefit of approximately $65 million associated with tight gas sand federal income tax credit utilization, an approximate $7 million predominantly one-time non-cash charge recorded in the third quarter of 1993 primarily to adjust the Company's accumulated deferred federal income tax liability for the increase in the corporate federal income tax rate from 34% to 35% and a $12 million benefit from the reduction of the Company's deferred federal income tax liability resulting from a reevaluation of deferred tax requirements. CAPITAL RESOURCES AND LIQUIDITY CASH FLOW The primary sources of cash for the Company during the nine-month period ended September 30, 1995 and for each of the years in the three-year period ended December 31, 1994 included funds generated from operations, the sale of Common Stock, the sale of a volumetric production payment, proceeds from the sale of selected oil and gas reserves and related assets and the issuance of debt. Primary cash outflows during these periods included funds used in operations, exploration and development expenditures, dividends and the repayment of debt. Discretionary cash flow, a frequently used measure of performance for exploration and production companies, is generally derived by adjusting net income to eliminate the effects of depreciation, depletion and amortization, impairment of unproved oil and gas properties, deferred taxes, gains on sales of oil and gas reserves and related assets, certain other miscellaneous non-cash amounts, except for amortization of deferred revenue, and exploration and dry hole expenses. However, based on the continuing practice of the Company of selling selected oil and gas reserves and related assets in furtherance of its strategy of fully utilizing its assets in optimizing profitability, cash flow and return on investments, it believes that net proceeds from these transactions should also be considered as available discretionary cash flow and accordingly is presenting those values for all periods shown. The Company generated discretionary cash flow of $387 million during the first nine months of 1995, a 3% decrease from the $401 million generated for the same period in 1994, primarily reflecting lower net operating revenues, higher cash expenses and a decrease in benefits associated with tight gas sand federal income tax credits. The Company generated discretionary cash flow of approximately $514 million in 1994, $521 million in 1993 and $346 million in 1992. The 1993 amount includes $50 million associated with a federal income tax refund resulting from the settlement on audit of federal income taxes paid in certain prior years. Net operating cash flows for the first nine months of 1995 and for each of the years in the three-year period ended December 31, 1994 have been revised to reflect proceeds from the sale of a volumetric production payment during 1992 and the elimination of the related amortization of deferred revenues as net operating cash flows rather than as investing cash flows as previously reported. Net operating cash flows of $229 million for the first nine months of 1995 decreased approximately $72 million as compared to the same period in 1994 primarily reflecting the same factors addressed above with regard to discretionary cash flow and higher working capital requirements. Net operating cash flows were approximately $383 million in 1994, $406 million in 1993, and 27 $608 million in 1992. Decreased 1994 net operating cash flows were primarily due to the receipt in 1993 of a refund on settlement on audit of federal income taxes paid in certain prior years. Decreased 1993 net operating cash flows were primarily due to the receipt in 1992 of $327 million of proceeds from the sale of a volumetric production payment, increased net operating revenues and a decrease in provision for current taxes resulting from both increased tight gas sand federal income tax credit utilization and the receipt of a refund on settlement on audit of federal income taxes paid in certain prior years. In accordance with the requirements of SFAS No. 95 -- "Statement of Cash Flows", net proceeds from the sale of selected oil and gas reserves and related assets are not included in the determination of net operating cash flows. SALE OF SELECTED OIL AND GAS RESERVES AND RELATED ASSETS During the first nine months of 1995, the Company received proceeds of $101 million from the sale of selected oil and gas reserves and related assets compared to $82 million received in the first nine months of 1994. Taxable gains from the first nine months of 1995 sales generated income taxes of $24 million leaving, net proceeds of $77 million. During 1994, the Company received proceeds of $91 million from the sale of selected oil and gas reserves and related assets compared to $42 million received in 1993. While the quantity of equivalent reserves sold in 1994 was slightly less than 1993, higher average proceeds received per equivalent unit of reserves sold in 1994 as compared to 1993 resulted in significantly higher 1994 proceeds. Taxable gains resulting from the 1994 sales generated income taxes of $20 million, leaving net proceeds of $71 million. Taxable gains resulting from such sales in 1993 generated federal income taxes of $8 million, leaving net proceeds of $34 million. SALE OF VOLUMETRIC PRODUCTION PAYMENT In September 1992, the Company sold a volumetric production payment for $326.8 million to a limited partnership. Under the terms of the production payment agreements, the Company conveyed a real property interest in approximately 124 Bcfe (136 TBtu) of certain natural gas and other hydrocarbons to the purchaser. Effective October 1, 1993, the agreements were amended providing for the extension of the original term of the volumetric production payment through March 31, 1999 and including a revised schedule of daily quantities of hydrocarbons to be delivered which is approximately one-half of the original schedule. The revised schedule will total approximately 89.1 Bcfe (97.8 TBtu) versus approximately 87.9 Bcfe (96.4 TBtu) remaining to be delivered under the original agreement. Daily quantities of hydrocarbons no longer required to be delivered under the revised schedule during the period from October 1, 1993 through June 30, 1996 are available for sale by the Company. The Company retains responsibility for its working interest share of the cost of operations. In accordance with generally accepted accounting principles, the Company accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue and income as natural gas and other hydrocarbons are produced and delivered to the purchaser during the term, as revised, of the volumetric production payment thereby matching those revenues with the depreciation of asset values which remained on the balance sheet following the sale and the operating expenses incurred for which the Company retained responsibility. The Company expects the above transaction, as amended, to have minimal direct impact on future earnings. However, cash made available by the sale of the volumetric production payment has provided considerable financial flexibility for the pursuit of investment alternatives. 28 EXPLORATION AND DEVELOPMENT EXPENDITURES The table below sets out components of actual exploration and development expenditures for the years ended December 31, 1992, 1993 and 1994, along with those estimated for the year 1995 and actual components of exploration and development expenditures for the nine-month periods ended September 30, 1994 and 1995.
NINE MONTHS ENDED SEPTEMBER 30, -------------------- EXPENDITURE CATEGORY 1992 1993 1994 1994 1995 - -------------------- --------- --------- --------- --------- --------- (IN MILLIONS) Capital Drilling and Facilities......... $ 260 $ 331 $ 342 $ 257 $ 225 Leasehold Acquisitions.......... 23 29 52 32 17 Producing Property Acquisitions.................. 65 9 34 14 114 Capitalized Interest and Other......................... 14 14 14 10 9 --------- --------- --------- --------- --------- Total...................... 362 383 442 313 365 Exploration Expenses................. 44 55 59 41 40 --------- --------- --------- --------- --------- Total................................ $ 406 $ 438 $ 501 $ 354 $ 405 ========= ========= ========= ========= =========
Exploration and development expenditures for the first nine months of 1995 increased $51 million compared to the same period in 1994, and primarily reflect the acquisitions of selected properties to complement existing United States producing areas. Exploration and development expenditures increased $63 million, or 14%, in 1994 compared to 1993. The increase primarily reflects the acquisitions of selected properties to compliment existing North America producing areas and the addition of new international activities in India. See "Business -- Exploration and Production" for additional information detailing the specific geographic locations of the Company's drilling programs and "-- Outlook" below for a discussion related to future exploration and development expenditure plans. Exploration and development expenditures in 1993 increased to $438 million, an 8% increase, as compared to the $406 million expended in 1992. The increase was attributable to increased domestic drilling activity with reduced emphasis on development drilling expenditures associated with tight gas sand formations. The Company also implemented its first development program outside of North America during 1993, installing a jacket, platform and production facilities and initiating natural gas production from the Kiskadee field offshore the southeast coast of Trinidad. HEDGING TRANSACTIONS With the objective of enhancing the certainty of future revenues, the Company has, as of October 23, 1995, entered into hedging transactions for approximately 400 BBtu per day (approximately 381 MMcf per day) and 529 BBtu per day (approximately 504 MMcf per day) of its North America natural gas volumes for the last three months of 1995 and the year 1996, respectively. A significant portion of the 1995 and substantially all of the 1996 hedge transactions involve NYMEX-based commodity price swap agreements totaling 260 BBtu per day at an average price of $1.98 per MMBtu and 447 BBtu per day at an average price of $2.00 per MMBtu for the last three months of 1995 and the year 1996, respectively. The remaining hedge transactions of 140 BBtu per day and 82 BBtu per day for the last three months of 1995 and the year 1996, respectively, include notional and physical transactions that involve fixed price sales contracts and volumetric production payment and exchange agreements. Included in the 1996 hedge transactions are commodity price swap agreements totaling 200 BBtu per day of notional volumes at a weighted average NYMEX-based price of $1.97 per MMbtu which include one-time options exercisable by the counterparty on or before December 17, 1996 totaling 200 BBtu per day of notional volumes in 1997 and 1998 at the same weighted average NYMEX-based price of $1.97 per MMBtu. The Company has also, as of October 16, 1995, hedged approximately 10,100 Bbl per day and 9,600 Bbl per day of its North 29 America crude oil and condensate volumes using commodity price swap agreements at NYMEX-based West Texas Intermediate Crude Oil ("WTI") prices averaging $18.77 per Bbl and $18.90 per Bbl for the last three months of 1995 and the year 1996, respectively. Included in the 1995 and 1996 hedge transactions are commodity price swap agreements totaling up to 3,000 Bbl per day at WTI prices ranging between $18.70 and $18.80 per Bbl each of which includes a one-time option exercisable by the counterparty at various times up to and including December 31, 1996 and for various periods some of which extend through December 31, 2000 at the same respective NYMEX-based prices as are applicable in the individual agreements for the 1995 and 1996 periods. The Company continues to evaluate the potential for entering into and may enter into, additional hedging transactions related to certain of the remaining months in 1995, and in future years. In addition, the Company also may close out any portion of the existing or yet to be entered into hedges as determined appropriate by management of the Company. TRADING TRANSACTIONS Subsequent to September 30, 1995, the Company sold call options with a notional volume of 50 BBtu per day at an average price of $2.10 per MMBtu for the period January through December, 1996. FINANCING The Company's long-term debt-to-total-capital ratio was 19%, 15% and 14% as of September 30, 1995 and December 31, 1994 and 1993, respectively. The Company has entered into an agreement with Enron Corp. pursuant to which the Company may borrow funds from Enron Corp. at a representative market rate of interest on a revolving basis. During 1994, there were no funds borrowed by the Company under this agreement. During the first nine months of 1995, the average of the daily balances of funds borrowed by the Company under the agreement was $2.3million, and the balance at September 30, 1995 was $16.3 million. Under a promissory note effective January 1, 1993 at a fixed interest rate of 7%, the Company may advance funds temporarily surplus to the Company to Enron Corp. for investment purposes. Daily outstanding balances of funds advanced to Enron Corp. under the note averaged $200,000 during the first nine months of 1995 and $69 million during 1994 with no balance outstanding at December 31, 1994 or September 30, 1995. There was a balance of $7 million outstanding at December 31, 1994 under a commercial paper program initiated in 1990. Proceeds from the commercial paper program were used to fund current transactions. During 1994, total long-term debt increased $37 million to $190 million as a result of $23 million of new borrowings related to certain international drilling activities, a $7 million increase in commercial paper, and the recording of an $8 million capital lease obligation. The estimated fair value of the Company's long-term debt, including current maturities of $2 million and $30 million, at December 31, 1994 and 1993 was $186 million and $192 million, respectively, based upon quoted market prices and, where such prices were not available, upon interest rates currently available to the Company at year end. OUTLOOK Uncertainty continues to exist as to the direction of future North America natural gas price trends and there is a wide divergence in the opinions held by some in the industry. However, recent history would tend to support, and it seems there is emerging among a larger number of industry representatives somewhat of a consensus, that natural gas prices will remain below parity with crude oil, condensate and natural gas liquids for some time. This situation is being impacted by improvements in the technology used in drilling and completing oil and gas wells that are tending to mitigate the impacts of fewer oil and gas wells being drilled, the deregulation of the natural gas market under Federal Energy Regulatory Commission Order 636 and subsequent related orders, and improvements being realized in the availability and utilization of natural gas storage capacity. However, the continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies should result 30 in further increases in demand and a supporting/strengthening of the overall natural gas market over time. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in crude oil and condensate prices. Based on the portion of the Company's anticipated natural gas volumes for which prices have not, in effect, been hedged using NYMEX-related commodity market transactions, long-term marketing contracts and the sale of a volumetric production payment, the Company's net income and cash flow sensitivity to changing natural gas prices is approximately $4.0 million for each $.10 per Mcf change in average wellhead natural gas prices. Using various commodity price hedging mechanisms, the Company has, in effect, locked in prices for an average of about 50% of its anticipated wellhead natural gas volumes and about 30% of its anticipated wellhead crude oil and condensate volumes for the year 1995 and about 65% of its anticipated wellhead natural gas volumes and about 40% of its anticipated wellhead crude oil and condensate volumes for the year 1996. The percentage of volumes hedged may change during the remainder of 1995 and will change in future years. Other factors representing positive impacts that are more certain continue to hold good potential for the Company in future periods. While the drilling qualification period for the tight gas sand federal income tax credit expired on December 31, 1992, the Company has continued in 1995, and should continue in the future, to realize significant benefits associated with production from wells drilled during the qualifying period as it will be eligible for the federal income tax credit through the year 2002. However, all other factors remaining equal, the annual benefit, which was $36 million in 1994 and is estimated to be approximately $21 million for 1995, is expected to continue to decline in future periods as production from the qualified wells declines. The drilling qualification period for a certain state severance tax exemption available on qualifying high-cost natural gas revenues continues through August 1996 in its current form and in a modified and somewhat reduced form from that point through August 2002. Consequently, new qualifying production will be added prospectively to that presently qualified. Other natural gas marketing activities are also expected to continue to contribute meaningfully to financial results. The Company completed a fairly significant restructure of its other natural gas marketing portfolio during 1992 with the sale of a volumetric production payment of approximately 124 Bcfe (136 TBtu) for $326.8 million that was subsequently revised in 1993 and elimination of most delivery obligations under four long-term fixed price marketing contracts. The proceeds from the sale of the volumetric production payment added substantially to the financial flexibility of the Company supporting future development while the combined effect of all elements of the restructuring on net income has not been, and will not in the future be, significant. These factors are expected to contribute significantly to earnings, cash flow, and the ability of the Company to pursue the continuation of an active exploration, development and selective acquisition program. The Company plans to continue to focus a substantial portion of its development and certain exploration expenditures in its major producing areas in North America. However, based on the continuing uncertainty associated with North America natural gas prices and the continuing weakness in that market, and as a result of the recent success realized offshore Trinidad and opportunities available to the Company in conjunction with the recent signing of agreements in India, the Company anticipates expending an increasing portion of its available funds in the further development of these opportunities. In addition, the Company expects to include limited but meaningful exploratory exposure in other areas outside of North America in its expenditure plans and will continue to evaluate the potential for involvement in other exploitation type opportunities. The continuation of expenditures in other areas outside of North America in the near term is expected to be primarily for the evaluation of conventional oil and gas exploration and exploitation opportunities in the U.K. North Sea and China, respectively, and coalbed methane recovery prospects in Australia and China. Other prospects in various locations will also attract the expenditure of some funds. (See "Business -- Exploration and Production" for additional information detailing the specific geographic locations of the related drilling programs). The Company continues to pursue a strategy of funding 31 exploration, development and acquisition activities primarily from available internally generated cash flow. The level of exploration and development expenditures will vary in future periods depending on energy market conditions and other related economic factors. Based upon existing economic and market conditions, the Company believes net operating cash flow and available financing alternatives will be sufficient to fund its net investing cash requirements for the near term. However, the Company has significant flexibility with respect to its financing alternatives and adjustment of its exploration and development expenditure plans as circumstances warrant. While the Company has certain continuing commitments associated with expenditure plans related to operations in India, they are not anticipated to be material when considered in relation to the total financial capacity of the Company. OTHER The cost of environmental compliance has not been material to the Company. In March 1995, the Financial Accounting Standards Board issued SFAS No. 121 -- "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (the "Standard"). The Standard requires, among other things, that long-lived assets and certain identifiable intangibles to be held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company is required to adopt the Standard no later than the first quarter of 1996. While the Company has not finalized its evaluation of the effect of adoption of the Standard, its evaluation to date indicates that application of the Standard to its current portfolio of assets could result in impairment charges ranging from $5 million to $60 million before federal income taxes ($3 million to $39 million after federal income taxes). However, such impairment charges would be non-cash. 32 MANAGEMENT The current directors and executive officers of the Company and their names and ages are as follows: NAME AGE POSITION ---- --- -------- Forrest E. Hoglund.................. 62 Chairman of the Board, President and Chief Executive Officer; Director Fred C. Ackman...................... 64 Director Richard D. Kinder................... 51 Director Kenneth L. Lay...................... 53 Director Edward Randall, III................. 68 Director Joe Michael McKinney................ 55 President-International Operations Mark G. Papa........................ 49 President-North American Operations Walter C. Wilson.................... 53 Senior Vice President and Chief Financial Officer Ben B. Boyd......................... 54 Vice President and Controller Dennis M. Ulak...................... 41 Vice President and General Counsel Forrest E. Hoglund joined the Company as Chairman of the Board, Chief Executive Officer and Director in September 1987. Since May 1990, he has also served as President of the Company. Mr. Hoglund was a director of USX Corporation from February 1986 until September 1987. He joined Texas Oil & Gas Corp. ("TXO") in 1977 as president, was named Chief Operating Officer in 1979, Chief Executive Officer in 1982, and served TXO in those capacities until September 1987. Mr. Hoglund is also an advisory director of Texas Commerce Bank National Association. Fred C. Ackman is the former Chairman, President and Chief Executive Officer of The Superior Oil Company. For over five years Mr. Ackman has been a consultant to the oil and gas industry and has interests in ranching and investments. Richard D. Kinder has been President and Chief Operating Officer of Enron Corp. since October 1990. From December 1988 until October 1990, he served Enron Corp. as Vice Chairman of the Board. For over five years prior to his election as Vice Chairman, Mr. Kinder served in various management and legal positions with Enron Corp. and its affiliates. Mr. Kinder is also a director of Enron Corp., Enron Global Power & Pipelines L.L.C., EOTT Energy Corp. (the general partner of EOTT Energy Partners, L.P.), Enron Liquids Pipeline Company (the general partner of Enron Liquids Pipeline, L.P.), Sonat Offshore Drilling Inc. and Baker Hughes Incorporated. Kenneth L. Lay has been Chairman of the Board and Chief Executive Officer of Enron Corp. for over five years. From February 1989 until October 1990, he also served as President of Enron Corp. Mr. Lay is also a director of Eli Lilly and Company, Compaq Computer Corporation, Trust Company of the West, EOTT Energy Corp. (the general partner of EOTT Energy Partners, L.P.), and Enron Corp. Edward Randall, III is principally involved in investments. Mr. Randall is also a director of KN Energy, Inc. and PaineWebber Group Inc. Joe Michael McKinney has been President-International Operations since February 1994 with responsibilities for all exploration, drilling, production and engineering activities for the Company's international ventures outside North America. Mr. McKinney joined Enron Oil & Gas International, Inc., a wholly-owned subsidiary of the Company, in December 1991 as Senior Vice President of Operations and was elected President and Chief Operating Officer of Enron Oil & Gas International, Inc. in April 1993, a capacity in which he continues to serve. Prior to joining the Company, Mr. McKinney held operations management positions with Union Texas Petroleum Company, The Superior Oil Company and Exxon Company, USA. 33 Mark G. Papa has been President-North American Operations since February 1994. From May 1986 through January 1994, Mr. Papa served as Senior Vice President-Operations. Mr. Papa joined Belco Petroleum Corporation, a predecessor of the Company, in 1981 as Division Production Coordinator and served as Senior Vice President-Drilling and Production, BelNorth Petroleum Corporation from May 1984 until May 1986. Walter C. Wilson has been Senior Vice President and Chief Financial Officer since May 1991. Mr. Wilson joined the Company in November 1987 as Vice President and Controller and was named Senior Vice President-Finance in October 1988. Prior to joining the Company Mr. Wilson held financial management positions with Exxon Company, USA for 16 years and The Superior Oil Company for four years. Ben B. Boyd has been Vice President and Controller since March 1991. Mr. Boyd joined the Company in March 1989 as Director of Accounting and was named Controller in May 1990. Prior to joining the Company, Mr. Boyd held financial management positions with DeNovo Oil & Gas, Inc., Scurlock Oil Company and Coopers & Lybrand. Dennis M. Ulak has been Vice President and General Counsel since March 1992. Mr. Ulak joined the Company in March 1987 as Senior Counsel and was named Assistant General Counsel in August 1990. Prior to joining the Company, Mr. Ulak held various legal positions with Enron Corp. and Northern Natural Gas Company. THE SELLING STOCKHOLDER
BENEFICIAL OWNERSHIP BENEFICIAL OWNERSHIP BEFORE STOCK OFFERINGS AFTER STOCK OFFERINGS(1)(2) ----------------------------- SHARES TO ----------------------------- SELLING STOCKHOLDER SHARES PERCENTAGE BE SOLD(1) SHARES PERCENTAGE - ------------------------------------- -------------- ---------- ------------- -------------- ---------- Enron Corp. 128,000,000 80% 27,000,000 101,000,000 63%
- ------------ (1) Assumes that the Underwriters' over-allotment options in the Stock Offerings are not exercised. If such options are exercised in full, Enron Corp. will sell 31,050,000 shares of Common Stock in the Stock Offerings and will beneficially own 96,950,000 shares of Common Stock (approximately 61% of the outstanding shares) after the Stock Offerings. (2) Concurrently with the Stock Offerings, Enron Corp. is offering Exchangeable Notes, which at maturity may be exchanged for no more than 10,000,000 shares of Common Stock (no more than 11,000,000 shares if the over-allotment option to the Underwriters in the Exchangeable Notes Offering is exercised in full) owned by Enron Corp., subject to adjustment under certain circumstances and to Enron Corp.'s option to pay an amount in cash in lieu of such mandatory exchange. Following consummation of the Exchangeable Notes Offering, the shares that may be delivered upon exchange therefor will continue to be beneficially owned by Enron Corp. until such time, if any, as they are delivered at maturity of the Exchangeable Notes. If the Underwriters' over-allotment options in the Stock Offerings and the Exchangeable Notes Offering are exercised in full and the maximum number of shares of Common Stock are delivered at maturity of the Exchangeable Notes, Enron Corp. will beneficially own 85,950,000 shares of Common Stock or approximately 54% of the outstanding shares. The registration related to the Stock Offerings and the Common Stock deliverable upon exchange of the Exchangeable Notes is being provided pursuant to the terms of a Stock Restriction and Registration Agreement with Enron Corp., under which the Company has agreed that upon the request of Enron Corp. (or certain assignees), the Company will register under the Securities Act and applicable state securities laws the sale of Common Stock owned by Enron Corp. The Company's obligation is subject to certain limitations relating to a minimum amount of Common Stock required for registration, the timing of registration and other similar matters. The Company is obligated to pay all expenses incidental to such registration, excluding underwriters' discounts and commissions and certain legal fees and expenses. 34 RELATIONSHIP BETWEEN THE COMPANY AND ENRON CORP. OWNERSHIP OF COMMON STOCK Through its ability to elect all of the directors of the Company, Enron Corp. has the ability to control all matters relating to the management of the Company, including any determination with respect to acquisition or disposition of Company assets, future issuance of Common Stock or other securities of the Company and any dividends payable on the Common Stock. Enron Corp. also has the ability to control the Company's exploration, development, acquisition and operating expenditure plans. There is no agreement between Enron Corp. and the Company that would prevent Enron Corp. from acquiring additional shares of Common Stock of the Company. The sale by Enron Corp. of the shares of Common Stock of the Company will cause Enron Corp.'s ownership interest in the Company to fall below 80% with the result that (i) the Company will cease to be included in the consolidated federal income tax return filed by Enron Corp. and (ii) the Tax Allocation Agreement between the Company and Enron Corp. described below will cease to be effective from the time at which deconsolidation occurs. The Company and Enron Corp. have entered into a new tax agreement pursuant to which, among other things, Enron Corp. has agreed (in exchange for the payment of $8.0 million by the Company) to be liable for, and to indemnify the Company against, all federal income taxes and state taxes measured by net income imposed on the Company for periods through the date Enron Corp. reduces its ownership in the Company to less than 80%. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp. and effectiveness of the Tax Allocation Agreement concurrently with deconsolidation or the terms of the new agreement will have a material adverse effect on its financial condition or results of operations. CONTRACTUAL ARRANGEMENTS The Company entered into a Services Agreement (the "Services Agreement") with Enron Corp. effective January 1994, pursuant to which Enron Corp. provides various services, such as maintenance of certain employee benefit plans, provision of telecommunications and computer services, lease of office space and the provision of purchasing and operating services and certain other corporate staff and support services. Such services historically have been supplied to the Company by Enron Corp., and the Services Agreement provides for the further delivery of such services substantially identical in nature and quality to those services previously provided. The Company has agreed to a fixed rate for the rental of office space and to reimburse Enron Corp. for all other direct costs incurred in rendering services to the Company under the contract and to pay Enron Corp. for allocated indirect costs incurred in rendering such services up to a maximum of $6.7 million for 1994, such cap to be increased in subsequent years for inflation and certain changes in the Company's allocation bases with any increase not to exceed 7.5% per year. Approximately $6.6 million was paid under the Services Agreement by the Company to Enron Corp. in 1994. The Services Agreement is for an initial term of five years through December 1998 and will continue thereafter until terminated by either party. In March 1995, in a series of transactions with Enron Corp. and an affiliate of Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements (the "Swap Agreements") of equivalent value. As a result of the transactions, the Company has been relieved of all performance obligations associated with the Cogen Contracts. The Company will realize net operating revenues and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999 under the terms of the Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received. The net of this series of transactions will result in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus that anticipated under the Cogen Contracts. 35 The Company has been included in the consolidated federal income tax return filed by Enron Corp. as the common parent for itself and its subsidiaries and affiliated companies, excluding any foreign subsidiaries. Consistent therewith and pursuant to a Tax Allocation Agreement between the Company, the Company's subsidiaries and Enron Corp., either Enron Corp. has paid to the Company and each subsidiary an amount equal to the tax benefit realized in the Enron Corp. consolidated federal income tax return resulting from the utilization of the Company's or the subsidiary's net operating losses and/or tax credits, or the Company and each subsidiary has paid to Enron Corp. an amount equal to the federal income tax computed on its separate taxable income less the tax benefits associated with any net operating losses and/or tax credits generated by the Company or the subsidiary which were utilized in the Enron Corp. consolidated return. Enron Corp. has paid the Company and each subsidiary for the tax benefits associated with their net operating losses and tax credits utilized in the Enron Corp. consolidated return, provided that a tax benefit was realized except as discussed below, even if such benefits could not have been used by the Company or the subsidiary on a separately filed tax return. The Company entered into an agreement with Enron Corp. providing for the Company to be paid for all realizable benefits associated with tight gas sand federal income tax credits concurrent with tax reporting and settlement for the periods in which they were generated. The Tax Allocation Agreement applies to the Company and each of its subsidiaries for all years in which the Company or any of its subsidiaries are or were included in the Enron Corp. consolidated return. To the extent a state or other taxing jurisdiction requires or permits a consolidated, combined, or unitary tax return to be filed and such return includes the Company or any of its subsidiaries, the principles expressed with respect to consolidated federal income tax allocation shall apply. The Tax Allocation Agreement will cease to be effective from the time at which deconsolidation occurs. The Company and Enron Corp. have entered into a new tax agreement pursuant to which, among other things, Enron Corp. has agreed (in exchange for the payment of $8.0 million by the Company) to be liable for, and to indemnify the Company against, all federal income taxes and state taxes measured by net income imposed on the Company for periods through the date Enron Corp. reduces its ownership in the Company to less than 80%. The Company does not believe that the cessation of consolidated tax reporting with Enron Corp. and effectiveness of the Tax Allocation Agreement concurrently with deconsolidation or the terms of the new agreement will have a material adverse effect on its financial condition or results of operations. For a discussion of transactions between the Company and Enron Corp. and its affiliates, see the Company's Annual Report on Form 10-K for the year ended December 31, 1994 incorporated herein by reference. See "Incorporation of Certain Documents by Reference." CONFLICTS OF INTEREST The nature of the respective businesses of the Company and Enron Corp. and its affiliates is such as to potentially give rise to conflicts of interest between the two companies. Conflicts could arise, for example, with respect to transactions involving purchases, sales and transportation of natural gas and other business dealings between the Company and Enron Corp. and its affiliates, potential acquisitions of businesses or oil and gas properties, the issuance of additional shares of voting securities, the election of directors or the payment of dividends by the Company. Circumstances may also arise that would cause Enron Corp. to engage in the exploration for and/or development and production of natural gas and crude oil in competition with the Company. For example, opportunities might arise which would require financial resources greater than those available to the Company, which are located in areas or countries in which the Company does not intend to operate or which involve properties that the Company would be unwilling to acquire. Also, Enron Corp. might acquire a competing oil and gas business as part of a larger acquisition. In addition, as part of Enron Corp.'s strategy of securing supplies of natural gas or capital, Enron Corp. may from time to time acquire producing properties or interests in entities owning producing 36 properties, and thereafter engage in exploration, development and production activities with respect to such properties or indirectly engage in such activities through such companies. Enron Corp. subsidiaries provide or arrange financing, including debt or equity financing, for exploration and production companies that compete with the Company. In connection with such activities, Enron Corp. affiliates may make investments in the debt or equity of such companies. There are currently no such transactions under consideration that would result in voting control by Enron Corp. or any of its affiliates, other than the transaction described in the next paragraph. In its financing activities Enron Corp. or any entity in which it has an interest may also make loans secured by oil and gas properties or securities of oil and gas companies, may acquire production payments or may receive interests in oil and gas properties as equity components of lending transactions. As a result of its lending activities, Enron Corp. may also acquire oil and gas properties or companies upon foreclosure of secured loans or as part of a borrower's rearrangement of its obligations. Such acquisition, exploration, development and production activities may directly or indirectly compete with the Company's business. There can be no assurances that Enron Corp. will not engage, directly or indirectly through entities other than the Company, in the natural gas and crude oil exploration, development and production business in competition with the Company. Joint Energy Development Investments Limited Partnership ("JEDI"), a limited partnership in which Enron Capital & Trade Resources Corp. ("ECT"), a wholly owned subsidiary of Enron Corp., owns a 50% general partner interest, has entered into an agreement to acquire a controlling interest in Coda. Coda is engaged in the exploration for, and the development, production and marketing of, natural gas and crude oil primarily in North Texas and Oklahoma. Crude oil accounts for approximately 86% of Coda's proved reserves. At December 31, 1994, Coda reported estimated proved natural gas reserves of 39,808 MMcf and estimated proved crude oil, condensate and natural gas liquids reserves of 39,207 MBbls. Enron anticipates that the transaction will be consummated in early 1996, subject to Coda stockholder approval and other conditions. Conflicts may arise between Coda and the Company, and if the acquisition of Coda occurs Enron will be required to resolve such conflicts in a manner that is consistent with its fiduciary and contractual duties to other investors in Coda and JEDI and its fiduciary duties to the Company. ECT has entered into an agreement with JEDI and other investors in Coda designed to minimize certain conflicts of interest that may arise and providing, among other things, that the Company has no obligation to offer any business opportunities to Coda. The Company and Enron Corp. and its affiliates have in the past entered into material intercompany transactions and agreements incident to their respective businesses, and the Company and Enron Corp. and its affiliates may be expected to enter into material transactions and agreements from time to time in the future. Such transactions and agreements have related to, among other things, the purchase and sale of natural gas and crude oil, the financing of exploration and development efforts by the Company, and the provision of certain corporate services. The Company believes that its existing transactions and agreements with Enron Corp. and its affiliates have been at least as favorable to the Company as could be obtained from third parties, and the Company intends that the terms of any future transactions and agreements between the Company and Enron Corp. and its affiliates will be at least as favorable to the Company as could be obtained from third parties. 37 DESCRIPTION OF COMMON STOCK AUTHORIZED AND OUTSTANDING CAPITAL STOCK The authorized capital stock of the Company consists of 160,000,000 shares of Common Stock, $.01 par value, of which 159,799,955 shares were outstanding on October 31, 1995. The following summary description of the capital stock of the Company is qualified in its entirety by reference to the Restated Certificate of Incorporation of the Company, as amended, a copy of which is filed as an exhibit to the Registration Statement of which this Prospectus is a part. The Common Stock possesses ordinary voting rights for the election of directors and in respect to other corporate matters, each share being entitled to one vote. 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 Common Stock carries no preemptive rights and is not convertible, redeemable or assessable, or entitled to the benefits of any sinking fund. The holders of Common Stock are entitled to dividends in such amounts and at such times as may be declared by the Board of Directors out of funds legally available therefor. 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 corporate debts. All outstanding shares of Common Stock are duly authorized, validly issued, fully paid and nonassessable. The transfer agent and registrar of the Common Stock is First Chicago Trust Company of New York, Jersey City, New Jersey. LIMITATION ON DIRECTORS' LIABILITY Delaware corporation law authorizes corporations to limit or eliminate the personal liability of directors to corporations and their stockholders for monetary damages for breach of directors' fiduciary duty of care. The duty of care requires that, when acting on behalf of the corporation, directors must exercise an informed business judgment based on all material information reasonably available to them. Absent the limitations authorized by such laws, directors are accountable to corporations and their stockholders for monetary damages for conduct constituting gross negligence in the exercise of their duty of care. The Delaware laws enable corporations to limit available relief to equitable remedies such as injunction or rescission. The Restated Certificate of Incorporation, as amended, of the Company limits the liability of directors of the Company to the Company or its stockholders (in their capacity as directors but not in their capacity as officers) to the fullest extent permitted by the Delaware law. Specifically, directors of the Company will not be personally liable for monetary damages for breach of a director's fiduciary duty as a director, except for liability (i) for any breach of the director's duty of loyalty to the Company or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) for unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the Delaware General Corporation Law, or (iv) for any transaction from which the director derived an improper personal benefit. This provision in the Restated Certificate of Incorporation may have the effect of reducing the likelihood of derivative litigation against directors, and may discourage or deter stockholders or management from bringing a lawsuit against directors for breach of their duty of care, even though such an action, if successful, might otherwise have benefited the Company and its stockholders. 38 CERTAIN UNITED STATES FEDERAL TAX CONSEQUENCES FOR NON-UNITED STATES HOLDERS OF COMMON STOCK The following is a summary of certain United States federal income tax consequences of the acquisition, ownership and disposition of Common Stock by a holder that, for United States federal income and estate tax purposes, is a Non-United States Holder. For purposes of this discussion, a "Non-United States Holder" means a corporation, individual or partnership that is, as to the United States, a foreign corporation, a non-resident alien individual or a foreign partnership, or a trust or estate other than one the income of which is subject to United States federal income tax regardless of its source. This summary does not address all aspects of United States federal income and estate taxation and does not deal with foreign, state and local tax consequences that may be relevant to Non-United States Holders in light of their specific circumstances. Furthermore, this summary is based on the provisions of the United States Internal Revenue Code of 1986, as amended, and the regulations, rulings and judicial decisions thereunder, all of which are subject to change. PROSPECTIVE INVESTORS ARE URGED TO CONSULT THEIR OWN TAX ADVISORS WITH RESPECT TO THE UNITED STATES TAX CONSEQUENCES TO THEM OF ACQUIRING, HOLDING AND DISPOSING OF COMMON STOCK AS WELL AS ANY TAX CONSEQUENCES THAT MAY ARISE UNDER THE LAWS OF ANY FOREIGN, STATE, LOCAL OR OTHER TAXING JURISDICTION. DIVIDENDS Dividends paid to a Non-United States Holder generally will be subject to withholding of United States federal income tax at a rate of 30% (or a lower rate prescribed by an applicable tax treaty). If the dividends are effectively connected with the conduct of a trade or business within the United States by the Non-United States Holder, the dividends will be subject to the ordinary United States federal income tax on net income that applies to United States persons and will not be subject to withholding if the Non-United States Holder files a United States Internal Revenue Service Form 4224 with the Company or its dividend paying agent. In the case of corporate holders, such dividends might also be subject to the United States branch profits tax at a rate of 30% (or a lower rate prescribed by an applicable tax treaty). A Non-United States Holder may be required to satisfy certain certification requirements in order to obtain any reduction of or exemption from withholding under the foregoing rules and may obtain a refund of any excess amounts currently withheld by filing an appropriate refund claim with the United States Internal Revenue Service. Distributions in excess of the Company's current and accumulated earnings and profits, as determined for United States federal income tax purposes, will be treated first as a return of capital to the extent of the Non-United States Holder's tax basis in the Common Stock (and will be applied against and reduce such holder's tax basis in the Common Stock) and thereafter as gain from the sale of Common Stock. The portion treated as a return of capital will not be subject to United States federal income tax and the portion, if any, treated as gain will be subject to the rules described under " -- Gain on Disposition" below. Because the Company will not be able to determine whether a distribution should properly be treated as a dividend or as a return of capital at the time of payment, it is required to treat all distributions as dividends for United States withholding tax purposes. Non-United States Holders will be eligible to claim a refund to the extent that a distribution represents a return of capital and may in certain circumstances be eligible to claim a refund to the extent that a distribution is treated as gain. Non-United States Holders should consult their own tax advisors with respect to distributions in excess of current and accumulated earnings and profits. GAIN ON DISPOSITION GENERAL RULE Subject to special rules for individuals described below, a Non-United States Holder generally will not be subject to United States federal income tax on gain recognized on a sale or other disposition of Common Stock unless (a) the gain is effectively connected with the conduct of a trade or business within the United States by the Non-United States Holder (in which case the United States branch profits tax described above may also apply to corporate holders) or (b) the gain is 39 treated as effectively connected with the conduct of a trade or business within the United States because the Company is or has been a "United States real property holding corporation" for United States federal income tax purposes (in which case, withholding of such tax may also apply). The Company believes that it is currently, and is likely to remain, a United States real property holding corporation. The preceding sentence notwithstanding, under currently effective United States federal income tax laws, gain recognized by a Non-United States Holder will not be treated as effectively connected with the conduct of a trade or business within the United States (or subject to withholding) unless such Non-United States Holder held, directly or indirectly, at any time during the five-year period ending on the date of disposition, more than five percent of the Common Stock. Non-United States Holders should consult applicable tax treaties, which may provide for different rules (including possibly the exemption of certain capital gains from tax). INDIVIDUALS In addition to the rules described above, an individual Non-United States Holder who holds Common Stock as a capital asset generally will be subject to tax on any gain recognized on the disposition of such stock if such individual is present in the United States for 183 days or more in the taxable year of disposition and either (a) has a "tax home" in the United States (as specifically defined under the United States federal income tax laws) or (b) maintains an office or other fixed place of business in the United States to which the gain from the sale of the stock is attributable. Certain individual Non-United States Holders may also be subject to tax pursuant to provisions of United States federal income tax law applicable to United States expatriates. FEDERAL ESTATE TAX Common Stock owned or treated as owned by an individual Non-United States Holder at the date of death will be subject to United States federal estate tax, unless an applicable estate tax treaty provides otherwise. INFORMATION REPORTING AND BACKUP WITHHOLDING The Company or its designated paying agent (the "payor") must report annually to the United States Internal Revenue Service and to each Non-United States Holder the amount of dividends paid to and the tax, if any, withheld with respect to such holder. That information may also be made available to the tax authorities of the country in which the Non-United States Holder resides. United States information reporting requirements (other than the reporting of dividend payments described in the preceding paragraph) and United States backup withholding (imposed at a 31% rate) generally will not apply to dividends paid to a Non-United States Holder at an address outside the United States, unless the payor has knowledge that the payee is a United States person. Otherwise, information reporting and backup withholding may apply to dividends paid on the Common Stock to a Non-United States Holder who fails to furnish certain information, including a tax identification number, in the manner required by United States law and applicable regulations. Payment of the proceeds of a disposition of Common Stock by a United States office of a broker is subject to backup withholding and information reporting, unless the holder certifies to the broker under penalties of perjury as to its name, address and status as a Non-United States Holder or the holder otherwise establishes an exemption. Neither backup withholding nor information reporting generally will apply to a payment of the proceeds of a disposition of Common Stock by a foreign office of a foreign broker that is not a United States Related Person (as defined below). Information reporting requirements (but not backup withholding) will apply to a payment of the proceeds of a disposition of Common Stock by a foreign office of a broker that is a United States person or a United States Related Person, unless the broker has documentary evidence in its records that the holder is a Non-United States Related Person and certain other conditions are met, or the holder otherwise establishes an exemption. For this purpose, a "United States Related Person" is (a) a foreign broker, 50% or more of whose gross income for certain periods is effectively connected with the conduct of a trade or business in the United States or (b) a foreign broker that is a "controlled foreign corporation" for United States federal income tax purposes. 40 Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules will be refunded or credited against the Non-United States Holder's United States federal income tax liability, provided that required information is furnished to the United States Internal Revenue Service. PLAN OF DISTRIBUTION This Prospectus relates to the 11,000,000 shares of Common Stock that may be delivered by Enron Corp. pursuant to the Exchangeable Notes and is Appendix A to the Enron Corp. Exchangeable Notes Prospectus. At maturity of the Exchangeable Notes, the principal amount of each such note will be mandatorily exchanged by Enron Corp. for shares of Common Stock or, at the option of Enron Corp., cash in lieu of such mandatory exchange. For a description of the Exchangeable Notes, see "Description of the Exchangeable Notes" in the Enron Corp. Exchangeable Notes Prospectus. Enron Corp., the Company and the Company's Chief Executive Officer have agreed that during the period beginning from the date of this Prospectus and continuing to and including the date 270 days after the date of this Prospectus, subject to certain exceptions set forth in the underwriting agreements, they will not offer, sell, contract to sell or otherwise dispose of Common Stock, any securities of the Company which are substantially similar to shares of Common Stock or any securities which are convertible into or exchangeable for Common Stock or such substantially similar securities without the prior written consent of Goldman, Sachs & Co., except for the shares of Common Stock offered in connection with the concurrent Stock Offerings. In connection with the distribution of the Exchangeable Notes, Enron Corp. and the Company have agreed to indemnify the several Underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute to payments the Underwriters may be required to make in respect thereof. VALIDITY OF COMMON STOCK The validity of the shares of Common Stock deliverable upon exchange of the Exchangeable Notes will be passed upon for the Company by Dennis M. Ulak, Esq., Vice President and General Counsel of the Company, and for the Underwriters by Bracewell & Patterson, L.L.P. Certain matters will be passed upon for Enron Corp. by Vinson & Elkins L.L.P. Mr. Ulak owns substantially less than 1% of the outstanding shares of Common Stock of the Company or common stock of Enron Corp. Bracewell & Patterson, L.L.P. provides services to Enron Corp. and certain of its subsidiaries (including the Company) and affiliates on matters unrelated to the offering of the Exchangeable Notes, the delivery of the Common Stock upon exchange thereof and the Stock Offerings. EXPERTS The consolidated financial statements and schedule included in the Company's Annual Report on Form 10-K for the year ended December 31, 1994, incorporated by reference in this Prospectus, have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are incorporated by reference herein in reliance upon the authority of said firm as experts in accounting and auditing in giving said report. The letter report of DeGolyer and MacNaughton, independent petroleum consultants, included as an exhibit to the Company's Annual Report on Form 10-K for the year ended December 31, 1994, and the estimates from the reports of that firm appearing in such Annual Report, are incorporated by reference herein on the authority of said firm as experts in petroleum engineering and in giving such reports. 41 ============================================================================== NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES DESCRIBED IN THIS PROSPECTUS OR AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY SUCH SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR SOLICITATION IS UNLAWFUL. 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 OR THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE. ------------------------ TABLE OF CONTENTS PAGE ----- Available Information................ 2 Incorporation of Certain Documents by Reference.......................... 2 Prospectus Summary................... 3 Use of Proceeds...................... 10 Price Range of Common Stock and Cash Dividends........... 10 Business............................. 11 Selected Consolidated Financial and Operating Information.............. 20 Management's Discussion and Analysis of Financial Condition and Results of Operations...................... 22 Management........................... 33 The Selling Stockholder.............. 34 Relationship Between the Company and Enron Corp............. 35 Description of Common Stock.......... 38 Certain United States Federal Tax Consequences For Non-United States Holders of Common Stock............ 39 Plan of Distribution................. 41 Validity of Common Stock............. 41 Experts.............................. 41 ENRON OIL & GAS COMPANY COMMON STOCK (PAR VALUE $.01 PER SHARE) ------------------------ PROSPECTUS ------------------------ ============================================================================== ============================================================================== NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES DESCRIBED IN THIS PROSPECTUS OR AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY SUCH SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR SOLICITATION IS UNLAWFUL. 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 ENRON SINCE THE DATE HEREOF OR THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE. ------------------------ TABLE OF CONTENTS PAGE ----- Available Information................ 2 Incorporation of Certain Documents by Reference.......................... 2 Prospectus Summary................... 3 Risk Factors Relating to Exchangeable Notes.............................. 5 Enron Corp........................... 7 Recent Events........................ 8 Selected Financial Data of Enron..... 10 Capitalization....................... 11 Relationship Between Enron and EOG.. 12 Use of Proceeds...................... 14 Ratio of Enron's Earnings to Fixed Charges............................ 14 Price Range of EOG Common Stock and Cash Dividends..................... 14 Description of the Exchangeable Notes.............................. 15 Certain United States Federal Income Tax Considerations................. 24 Underwriting......................... 27 Validity of the Exchangeable Notes... 28 Experts.............................. 28 Prospectus Relating to Common Stock of Enron Oil & Gas Company......... Appendix A 10,000,000 EXCHANGEABLE NOTES ENRON CORP. 6 1/4% EXCHANGEABLE NOTES DUE DECEMBER 13, 1998 ------------------------ PROSPECTUS ------------------------ GOLDMAN, SACHS & CO. MERRILL LYNCH & CO. SALOMON BROTHERS INC REPRESENTATIVES OF THE UNDERWRITERS ============================================================================== PART II INFORMATION NOT REQUIRED IN PROSPECTUS ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION The following table sets forth those expenses to be incurred by Enron in connection with the issuance and distribution of the securities being registered. Except for the Securities and Exchange Commission registration fee and NASD, Inc. filing fees, all amounts shown are estimates. Securities and Exchange Commission Registration Fee................... $ 75,388 NASD Filing Fees..................... 22,365 Accounting Fees and Expenses......... 50,000 Legal Fees and Expenses.............. 70,000 Fees and Expenses of Transfer Agent and Trustee........................ 15,000 Blue Sky Fees and Expenses, Including Counsel Fees....................... 10,000 Printing and Engraving Expenses...... 150,000 Miscellaneous........................ 32,247 ----------- Total...................... $ 425,000 =========== ITEM 15. INDEMNIFICATION OF OFFICERS AND DIRECTORS Section 145 of Chapter 1 of Title 8 of the Delaware Code provides that every corporation created under the provisions thereof shall have the power to indemnify its directors, officers, employees and agents against certain liabilities. The Restated Certificate of Incorporation, as amended, of Enron contains the following provisions relating to indemnification of directors and officers: "1. A director of the Corporation shall not be personally liable to the Corporation or its stockholders for monetary damages for breach of fiduciary duty as a director, except for liability (i) for any breach of the director's duty of loyalty to the Corporation or its stockholders, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, (iii) under Section 174 of the Delaware General Corporation Law, or (iv) for any transaction from which the director derived an improper personal benefit. 2. (A) Each person who was or is made a party or is threatened to be made a party to or is involved in any action, suit or proceeding, whether civil, criminal, administrative or investigative (hereinafter a "proceeding"), by reason of the fact that he or she, or a person of whom he or she is the legal representative, is or was a director or officer, of the Corporation or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust or other enterprise, including service with respect to employee benefit plans, whether the basis of such proceeding is alleged action in an official capacity as a director, officer, employee or agent or in any other capacity while serving as a director, officer, employee or agent, shall be indemnified and held harmless by the Corporation to the fullest extent authorized by the Delaware General Corporation Law, as the same exists or may hereafter be amended (but, in the case of any such amendment, only to the extent that such amendment permits the Corporation to provide broader indemnification rights than said law permitted the Corporation to provide prior to such amendment), against all expense, liability and loss (including attorneys' fees, judgments, fines, ERISA excise taxes or penalties and amounts paid or to be paid in settlement) reasonably incurred or suffered by such person in connection therewith, and such indemnification shall continue as to a person who has ceased to be a director, officer, employee or agent and shall inure to the benefit of his or her heirs, executors and administrators; provided, however, that, except as provided in paragraph II-1 (B) hereof, the Corporation shall indemnify any such person seeking indemnification in connection with a proceeding (or part thereof) initiated by such person only if such proceeding (or part thereof) was authorized by the Board of Directors of the Corporation. The right to indemnification conferred in this Section shall be a contract right and shall include the right to be paid by the Corporation the expenses incurred in defending any such proceeding in advance of its final disposition; provided, however, that, if the Delaware General Corporation Law requires, the payment of such expenses incurred by a director or officer in his or her capacity as a director or officer (and not in any other capacity in which service was or is rendered by such person while a director or officer, including, without limitation, service to an employee benefit plan) in advance of the final disposition of the proceeding, shall be made only upon delivery to the Corporation of an undertaking, by or on behalf of such director or officer, to repay all amounts so advanced if it shall ultimately be determined that such director or officer is not entitled to be indemnified under this Section or otherwise. The Corporation may, by action of its Board of Directors, provide indemnification to employees and agents of the Corporation with the same scope and effect as the foregoing indemnification of directors and officers. (B) If a claim under paragraph 2(A) of this Article XVI is not paid in full by the Corporation within thirty days after a written claim has been received by the Corporation, the claimant may at any time thereafter bring suit against the Corporation to recover the unpaid amount of the claim and, if successful in whole or in part, the claimant shall be entitled to be paid also the expense of prosecuting such claim. It shall be a defense to any such action (other than an action brought to enforce a claim for expenses incurred in defending any proceeding in advance of its final disposition where the required undertaking, if any is required, has been tendered to the Corporation) that the claimant has not met the standards of conduct which make it permissible under the Delaware General Corporation Law for the Corporation to indemnify the claimant for the amount claimed, but the burden of proving such defense shall be on the Corporation. Neither the failure of the Corporation (including its Board of Directors, independent legal counsel, or its stockholders) to have made a determination prior to the commencement of such action that indemnification of the claimant is proper in the circumstances because he or she has met the applicable standard of conduct set forth in the Delaware General Corporation Law, nor an actual determination by the Corporation (including its Board of Directors, independent legal counsel, or its stockholders) that the claimant has not met such applicable standard of conduct, shall be a defense to the action or create a presumption that the claimant has not met the applicable standard of conduct. (C) The right to indemnification and the payment of expenses incurred in defending a proceeding in advance of its final disposition conferred in this Section shall not be exclusive of any other right which any person may have or hereafter acquire under any statute, provision of the Certificate of Incorporation, bylaw, agreement, vote of stockholders or disinterested directors or otherwise. (D) The Corporation may maintain insurance, at its expense, to protect itself and any director, officer, employee or agent of the Corporation or another corporation, partnership, joint venture, trust or other enterprise against any such expense, liability or loss, whether or not the Corporation would have the power to indemnify such person against such expense, liability or loss under the Delaware General Corporation Law." Enron has purchased liability insurance policies covering its directors and officers to provide protection where Enron cannot legally indemnify a director or officer and where a claim arises under the Employee Retirement Income Security Act of 1974 against a director or officer based on an alleged breach of fiduciary duty or other wrongful act. II-2 ITEM 16. EXHIBITS **1 -- Form of Underwriting Agreement for Exchangeable Notes. *4(a) -- Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22-14390, filed October 24, 1985). **4(b) -- Form of First Supplemental Indenture between Enron and Harris Trust and Savings Bank, as Trustee. **5 -- Opinion of James V. Derrick, Jr., Esq., Senior Vice President and General Counsel of Enron, as to validity of the Exchangeable Notes. 8 -- Opinion of Vinson & Elkins L.L.P. regarding certain tax matters (revised). **10 -- Form of 1995 Tax Allocation Agreement between Enron and Enron Oil & Gas Company. **12 -- Computations of Ratios of Earnings to Fixed Charges. 23(a) -- Consents of Arthur Andersen LLP. **23(b) -- Consent of DeGolyer and MacNaughton. 23(c) -- The consent of James V. Derrick, Jr., Esq., is contained in his opinion filed as Exhibit 5 hereto. **24 -- Powers of Attorney. **25 -- Form T-1 Statement of Eligibility under the Trust Indenture Act of 1939 of Harris Trust and Savings Bank. - ------------ * Incorporated by reference as indicated. ** Previously filed. ITEM 17. UNDERTAKINGS (a) The undersigned Registrant hereby undertakes that for purposes of determining any liability under the Securities Act of 1933, each filing of Enron's annual report pursuant to section 13(a) or section 15(d) of the Securities Exchange Act of 1934 that is incorporated by reference in the Registration Statement shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof. (b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrants pursuant to the provisions described under Item 15 above, or otherwise, the Registrants have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of such registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, such Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue. (c) The undersigned registrant hereby undertakes that: (1) For purposes of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4), or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective. (2) For purposes of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial BONA FIDE offering thereof. II-3 SIGNATURES PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, ENRON CERTIFIES THAT IT HAS REASONABLE GROUNDS TO BELIEVE THAT IT MEETS ALL OF THE REQUIREMENTS FOR FILING ON FORM S-3 AND HAS DULY CAUSED THIS REGISTRATION STATEMENT OR AMENDMENT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED, IN THE CITY OF HOUSTON AND STATE OF TEXAS, ON THE 7TH DAY OF DECEMBER, 1995. ENRON CORP. (Registrant) By: KURT S. HUNEKE KURT S. HUNEKE VICE PRESIDENT, FINANCE AND TREASURER PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, THIS REGISTRATION STATEMENT OR AMENDMENT HAS BEEN SIGNED BY THE FOLLOWING PERSONS IN THE CAPACITIES WITH ENRON CORP. INDICATED AND ON THE 7TH DAY OF DECEMBER, 1995. SIGNATURE TITLE - ----------------------------- ------------------------------------------------ KENNETH L. LAY Chairman of the Board, Chief Executive Officer (KENNETH L. LAY) and Director (Principal Executive Officer) JACK I. TOMPKINS Senior Vice President and Chief Information, (JACK I. TOMPKINS) Administrative and Accounting Officer (Principal Accounting Officer) KURT S. HUNEKE Vice President, Finance and Treasurer (Principal (KURT S. HUNEKE) Financial Officer) ROBERT A. BELFER* Director (ROBERT A. BELFER) NORMAN P. BLAKE, JR.* Director (NORMAN P. BLAKE, JR.) JOHN H. DUNCAN* Director (JOHN H. DUNCAN) JOE H. FOY* Director (JOE H. FOY) WENDY L. GRAMM* Director (WENDY L. GRAMM) ROBERT K. JAEDICKE* Director (ROBERT K. JAEDICKE) II-4 RICHARD D. KINDER* Director and President and Chief (RICHARD D. KINDER) Operating Officer CHARLES A. LEMAISTRE* Director (CHARLES A. LEMAISTRE) JOHN A. URQUHART* Director (JOHN A. URQUHART) JOHN WAKEHAM* Director (JOHN WAKEHAM) CHARLS E. WALKER* Director (CHARLS E. WALKER) HERBERT S. WINOKUR, JR.* Director (HERBERT S. WINOKUR, JR.) *By: PEGGY B. MENCHACA PEGGY B. MENCHACA (ATTORNEY-IN-FACT FOR PERSONS INDICATED) II-5 INDEX TO EXHIBITS EXHIBIT NUMBER DESCRIPTION PAGE - ------- ----------- ---- **1 -- Form of Underwriting Agreement for Exchangeable Notes. *4(a) -- Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22-14390, filed October 24, 1985). **4(b) -- Form of First Supplemental Indenture between Enron and Harris Trust and Savings Bank, as Trustee. **5 -- Opinion of James V. Derrick, Jr., Esq., Senior Vice President and General Counsel of Enron, as to validity of the Exchangeable Notes. 8 -- Opinion of Vinson & Elkins L.L.P. regarding certain tax matters (revised). **10 -- Form of 1995 Tax Allocation Agreement between Enron and Enron Oil & Gas Company. **12 -- Computations of Ratios of Earnings to Fixed Charges. 23(a) -- Consents of Arthur Andersen LLP. **23(b) -- Consent of DeGolyer and MacNaughton. 23(c) -- The consent of James V. Derrick, Jr., Esq., is contained in his opinion filed as Exhibit 5 hereto. **24 -- Powers of Attorney. **25 -- Form T-1 Statement of Eligibility under the Trust Indenture Act of 1939 of Harris Trust and Savings Bank. - ------------ * Incorporated by reference as indicated. ** Previously filed. EX-8 2 OPINION VINSON & ELKINS LLP EXHIBIT 8 (713) 758-2194 (713) 615-5660 December 7, 1995 Enron Corp. 1400 Smith Street Houston, Texas 77002-7369 Ladies and Gentlemen: We have participated in the preparation of the Registration Statement on Form S-3 (Registration No. 33-64057) (such Registration Statement, as amended at the effective date thereof being referred to herein as the "Registration Statement") filed with the Securities and Exchange Commission under the Securities Act of 1933, as amended (the "Securities Act"), with respect to the registration of Exchangeable Notes of Enron Corp., as well as the prospectus relating thereto and included as part of the Registration Statement (the "Prospectus"). The statements in the Prospectus under the caption "Certain United States Federal Income Tax Considerations" have been prepared by us and, in our opinion, are based upon reasonable interpretations of law in effect as of the date hereof. Because of the absence of authority as to the proper characterization of the Exchangeable Notes for federal income tax purposes, no opinion can be given with respect to the specific tax consequences of owning or disposing of the Exchangeable Notes and no assurance can be given that the Internal Revenue Service will accept, or that a court will uphold, the interpretations set forth under the caption "Certain United States Federal Income Tax Considerations." We hereby consent to the references to this firm under the captions "Certain United States Federal Income Tax Considerations" and "Validity of the Exchangeable Notes" in the Prospectus and to the filing of this opinion as an exhibit to the Registration Statement. By giving such consent, we do not admit that we are within the category of persons whose consent is required under Section 7 of the Securities Act or the rules and regulations of the Commission issued thereunder. Very truly yours, VINSON & ELKINS L.L.P. EX-23.A 3 CONSENTS OF INDEPENDENT PUBLIC ACCOUNTANTS EXHIBIT 23(a) CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in this Registration Statement of our reports dated February 17, 1995 included in Enron Corp.'s Annual Report on Form 10-K for the year ended December 31, 1994 and to all references to our Firm included in this Registration Statement. ARTHUR ANDERSEN LLP Houston, Texas December 6, 1995 CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference in this Registration Statement of our report on the consolidated financial statements of Enron Oil & Gas Company and subsidiaries dated February 17, 1995, included in Enron Oil & Gas Company's Form 10-K for the year ended December 31, 1994, and to all references to our Firm included in this Registration Statement. ARTHUR ANDERSEN LLP Houston, Texas December 6, 1995 -----END PRIVACY-ENHANCED MESSAGE-----