-----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, DssmLUIsPwYXlD/yHfGx1ZRnbZZQqKV6Ub5ctKk8mqXWRPJdSDtHn6G9rb7/HVXz XggDW/qzQiGeXA7iffVpGg== 0000930661-96-000620.txt : 19960617 0000930661-96-000620.hdr.sgml : 19960617 ACCESSION NUMBER: 0000930661-96-000620 CONFORMED SUBMISSION TYPE: 424B4 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19960614 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: CODA ENERGY INC CENTRAL INDEX KEY: 0000356799 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 751842480 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: 1933 Act SEC FILE NUMBER: 333-02375 FILM NUMBER: 96580823 BUSINESS ADDRESS: STREET 1: 5735 PINELAND DR STREET 2: STE 300 CITY: DALLAS STATE: TX ZIP: 75231 BUSINESS PHONE: 2146921800 MAIL ADDRESS: STREET 1: 5735 PINELAND DRIVE STREET 2: SUITE 300 CITY: DALLAS STATE: TX ZIP: 75231 FORMER COMPANY: FORMER CONFORMED NAME: CHAPMAN ENERGY INC DATE OF NAME CHANGE: 19891012 FORMER COMPANY: FORMER CONFORMED NAME: DALLAS SUNBELT ENERGY INC DATE OF NAME CHANGE: 19821116 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ELECTRA RESOURCES INC CENTRAL INDEX KEY: 0001012952 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752644280 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: 1933 Act SEC FILE NUMBER: 333-02375-03 FILM NUMBER: 96580824 BUSINESS ADDRESS: STREET 1: 5735 PINELAND DRIVE STREET 2: SUITE 300 CITY: DALLAS STATE: TX ZIP: 75231 BUSINESS PHONE: 2146921800 MAIL ADDRESS: STREET 1: 5735 PINELAND DRIVE STREET 2: SUITE 300 CITY: DALLAS STATE: TX ZIP: 75231 FILER: COMPANY DATA: COMPANY CONFORMED NAME: TAURUS ENERGY CORP CENTRAL INDEX KEY: 0001012954 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752322473 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: 1933 Act SEC FILE NUMBER: 333-02375-02 FILM NUMBER: 96580825 BUSINESS ADDRESS: STREET 1: 5735 PINELAND DRIVE STREET 2: SUITE 300 CITY: DALLAS STATE: TX ZIP: 75231 BUSINESS PHONE: 2146921800 MAIL ADDRESS: STREET 1: 5735 PINELAND DRIVE STREET 2: SUITE 300 CITY: DALLAS STATE: TX ZIP: 75231 FILER: COMPANY DATA: COMPANY CONFORMED NAME: DIAMOND ENERGY OPERATING CO CENTRAL INDEX KEY: 0001012955 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 731366557 STATE OF INCORPORATION: OK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B4 SEC ACT: 1933 Act SEC FILE NUMBER: 333-02375-01 FILM NUMBER: 96580826 BUSINESS ADDRESS: STREET 1: 5735 PINELAND DRIVE STREET 2: SUITE 300 CITY: DALLAS STATE: TX ZIP: 75231 BUSINESS PHONE: 2146921800 MAIL ADDRESS: STREET 1: 5735 PINELAND DRIVE STREET 2: SUITE 300 CITY: DALLAS STATE: TX ZIP: 75231 424B4 1 OFFER TO EXCHANGE Filed pursuant to Rule 424(b)(4) SEC File No. 333-2375 PROSPECTUS JUNE 11, 1996 OFFER TO EXCHANGE 10 1/2% SERIES B SENIOR SUBORDINATED NOTES DUE 2006 FOR ALL OUTSTANDING 10 1/2% SERIES A SENIOR SUBORDINATED NOTES DUE 2006 OF [CODA ENERGY, INC. LOGO] -------------- THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M, NEW YORK CITY TIME ON JULY 12, 1996 UNLESS EXTENDED. Coda Energy, Inc., a Delaware corporation ("Coda;" and, together with the guarantor subsidiaries, Diamond Energy Operating Company, Taurus Energy Corp. and Electra Resources, Inc., the "Company"), is hereby offering (the "Exchange Offer"), upon the terms and subject to the conditions set forth in this Prospectus and the accompanying Letter of Transmittal (the "Letter of Transmittal"), to exchange $1,000 principal amount of its 10 1/2% Series B Senior Subordinated Notes due 2006 (the "Exchange Notes"), which exchange has been registered under the Securities Act of 1933, as amended (the "Securities Act"), pursuant to a registration statement of which this Prospectus is a part (the "Registration Statement"), for each $1,000 principal amount of its outstanding 10 1/2% Series A Senior Subordinated Notes due 2006 (the "Private Notes"), of which $110,000,000 in aggregate principal amount was issued on March 18, 1996 and is outstanding as of the date hereof. The form and terms of the Exchange Notes are the same as the form and terms of the Private Notes (which they replace) except that (i) the Exchange Notes will bear a Series B designation, (ii) the Exchange Notes will have been registered under the Securities Act, and, therefore, the Exchange Notes will not bear legends restricting the transfer thereof and (iii) holders of the Exchange Notes will not be entitled to certain rights of holders of the Private Notes under the Registration Rights Agreement (as defined herein), which rights will terminate upon the consummation of the Exchange Offer. The Exchange Notes will evidence the same indebtedness as the Private Notes (which they replace) and will be entitled to the benefits of an indenture dated as of March 18, 1996 governing the Private Notes and the Exchange Notes (the "Indenture"). The Private Notes and the Exchange Notes are referred to herein collectively as the "Notes." See "The Exchange Offer" and "Description of Exchange Notes." The Exchange Notes will bear interest at the same rate and on the same terms as the Private Notes. Consequently, the Exchange Notes will bear interest at the rate of 10 1/2% per annum and the interest thereon will be payable semiannually in arrears on April 1 and October 1 of each year, commencing October 1, 1996. The Exchange Notes will bear interest from and including the date of issuance of the Private Notes (March 18, 1996). Holders whose Private Notes are accepted for exchange will be deemed to have waived the right to receive any interest accrued on the Private Notes. The Exchange Notes will be general unsecured obligations of Coda and will be subordinated in right of payment to all Senior Debt (as defined in the Indenture) of Coda (which includes all indebtedness under the Credit Agreement (as defined herein)) and will rank senior in right of payment to all future subordinated indebtedness of Coda. As of March 31, 1996, Coda had $81.8 million in Senior Debt. Coda currently has no indebtedness that is junior to the Notes. See "Description of Exchange Notes--Subordination" and "Description of Other Indebtedness." Coda's payment obligations under the Exchange Notes will be jointly and severally guaranteed on a senior subordinated basis (the "Subsidiary Guarantees") by all of Coda's current and future Restricted Subsidiaries (as defined in the Indenture; collectively, the "Guarantors"). The Subsidiary Guarantees will be subordinated to the guarantees of Senior Debt issued by the Guarantors under the Credit Agreement and to other guarantees of Senior Debt issued in the future. See "Description of Exchange Notes--Subsidiary Guarantees." The Exchange Notes will be redeemable at the option of Coda, in whole or in part, at any time on or after April 1, 2001, at the redemption prices set forth herein, together with accrued and unpaid interest thereon to the date of redemption. Notwithstanding the foregoing, before March 12, 1999, Coda may, on any one or more occasions, redeem up to $27.5 million in aggregate principal amount of Notes at a redemption price of 110.5% of the principal amount thereof plus accrued and unpaid interest thereon to the redemption date, with the net proceeds of an offering of common equity of Coda; provided that at least $82.5 million in aggregate principal amount of Notes must remain outstanding immediately after the occurrence of such redemption; and provided, further, that any such redemption shall occur within 75 days of the date of the closing of such offering of common equity of Coda. See "Description of Exchange Notes." Upon the occurrence of a Change of Control (as defined herein), each holder of Exchange Notes may require Coda to repurchase all or a portion of such holder's Exchange Notes at a repurchase price equal to 101% of the aggregate principal amount thereof plus accrued and unpaid interest thereon to the date of repurchase. See "Description of Exchange Notes--Repurchase of the Option of Holders--Change of Control." The Company will accept for exchange any and all validly tendered Private Notes not withdrawn prior to 5:00 p.m., New York City time, on July 12, 1996, unless the Exchange Offer is extended by the Company in its sole discretion (the "Expiration Date"). Tenders of Private Notes may be withdrawn at any time prior to the Expiration Date. Private Notes may be tendered only in integral multiples of $1,000. The Exchange Offer is subject to certain customary conditions. See "The Exchange Offer--Conditions." SEE "RISK FACTORS," BEGINNING ON PAGE 18, FOR A DISCUSSION OF CERTAIN FACTORS THAT INVESTORS SHOULD CONSIDER IN CONNECTION WITH THE EXCHANGE OFFER AND AN INVESTMENT IN THE EXCHANGE NOTES AND THE SUBSIDIARY GUARANTEES THEREOF. -------------- 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. Based on an interpretation by the staff of the Securities and Exchange Commission (the "Commission") set forth in no-action letters issued to third parties, the Company believes that the Exchange Notes issued pursuant to the Exchange Offer in exchange for Private Notes may be offered for resale, resold and otherwise transferred by a holder thereof (other than (i) a broker-dealer who purchases such Exchange Notes directly from the Company to resell pursuant to Rule 144A or any other available exemption under the Securities Act or (ii) a person that is an affiliate of the Company within the meaning of Rule 405 under the Securities Act), without compliance with the registration and prospectus delivery provisions of the Securities Act; provided that the holder is acquiring the Exchange Notes in the ordinary course of its business and is not participating, and had no arrangement or understanding with any person to participate, in the distribution of the Exchange Notes. Holders of Private Notes wishing to accept the Exchange Offer must represent to the Company, as required by the Registration Rights Agreement, that such conditions have been met. Each broker-dealer that receives Exchange Notes for its own account in exchange for Private Notes, where such Private Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. The Company believes that none of the registered holders of the Private Notes is an affiliate (as such term is defined in Rule 405 under the Securities Act) of the Company. Prior to the Exchange Offer, there has been no public market for the Private Notes. The Company does not intend to list the Exchange Notes on any securities exchange or to seek approval for quotation through any automated quotation system. There can be no assurance that an active market for the Exchange Notes will develop. To the extent that a market for the Notes does develop, the market value of the Notes will depend on market conditions (such as yields on alternative investments), general economic conditions, the Company's financial condition and certain other factors. Such conditions might cause the Notes, to the extent that they are traded, to trade at a significant discount from face value. See "Risk Factors--Absence of Public Market for the Notes." Each broker-dealer that receives Exchange Notes for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. The Letter of Transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This Prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Private Notes where such Private Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. The Company has agreed to make this Prospectus (as it may be amended or supplemented) available to any broker-dealer for use in connection with any such resale for a period of one year after the effective date of the Registration Statement of which this Prospectus forms a part. See "Plan of Distribution." The Company will not receive any proceeds from, and has agreed to bear the expenses of, the Exchange Offer. No underwriter is being used in connection with this Exchange Offer. See "The Exchange Offer--Resale of the Exchange Notes." THE EXCHANGE OFFER IS NOT BEING MADE TO, NOR WILL THE COMPANY ACCEPT SURRENDERS FOR EXCHANGE FROM, HOLDERS OF PRIVATE NOTES IN ANY JURISDICTION IN WHICH THE EXCHANGE OFFER OR THE ACCEPTANCE THEREOF WOULD NOT BE IN COMPLIANCE WITH THE SECURITIES OR BLUE SKY LAWS OF SUCH JURISDICTION. NO PERSON IS AUTHORIZED IN CONNECTION WITH THE EXCHANGE OFFER TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS OR THE ACCOMPANYING LETTER OF TRANSMITTAL, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY. NEITHER THE DELIVERY OF THIS PROSPECTUS OR THE ACCOMPANYING LETTER OF TRANSMITTAL, NOR ANY EXCHANGE MADE HEREUNDER SHALL UNDER ANY CIRCUMSTANCES CREATE ANY IMPLICATION THAT THE INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY DATE SUBSEQUENT TO THE DATE HEREOF. 2 UNTIL SEPTEMBER 9, 1996 (90 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL DEALERS OFFERING TRANSACTIONS IN THE EXCHANGE NOTES, WHETHER OR NOT PARTICIPATING IN THE EXCHANGE OFFER, MAY BE REQUIRED TO DELIVER A PROSPECTUS IN CONNECTION THEREWITH. THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR SUBSCRIPTIONS. The Exchange Notes will be available initially only in book-entry form. The Company expects that the Exchange Notes issued pursuant to the Exchange Offer will be issued in the form of one permanent global certificate in definitive, fully-registered form ("Global Note") that will be deposited with, or on behalf of, the Depository Trust Company ("DTC" or the "Depositary") and registered in its name or in the name of Cede & Co., as its nominee. Beneficial interests in the Global Note representing the Exchange Notes will be shown on, and transfers thereof will be effected only through, records maintained by the Depositary and its participants. After the initial issuance of such Global Note, Exchange Notes in certificated form will be issued in exchange for the Global Note only in accordance with the terms and conditions set forth in the Indenture. See "The Exchange Offer--Book-Entry Transfer" and "Description of Exchange Notes--Book-Entry, Delivery and Form." 3 SUMMARY The following summary is qualified in its entirety by the detailed information, financial statements and other data appearing elsewhere in this Prospectus. The pro forma financial data presented give effect as of January 1, 1995, to (i) the Snyder Acquisition (as defined below), (ii) the Merger (as defined below) and (iii) the offering of the Private Notes and the application of the estimated net proceeds therefrom. Certain oil and gas terms used in this Prospectus are defined in the "Glossary" included herein. Certain terms used in connection with the Notes are defined under the caption "Description of Exchange Notes--Certain Definitions." THE COMPANY The Company is an independent energy company that is principally engaged in the acquisition and exploitation of producing oil and natural gas properties. The Company also owns and operates natural gas processing and liquids extraction facilities and natural gas gathering systems. The Company seeks to acquire oil and natural gas properties whose predominant economic value is attributable to proved producing reserves and to enhance that value through control of operations, reduction of costs and property development. The Company's producing properties are concentrated in the mid-continent region of the United States. At December 31, 1995, the Company had proved reserves of 42.6 Mmbbls of oil and 37.1 Bcf of natural gas, aggregating 48.8 Mmboe. Company operated properties accounted for approximately 94% of its 1995 production of 3.9 Mmboe. As a result of the Company's successful acquisition and exploitation activities, the Company has shown significant growth in reserves, production and earnings before interest, income taxes, depletion, depreciation and amortization ("EBITDA") over the last five years. From 1991 through 1995, the Company achieved an average annual reserve replacement of 480% at an average cost of $3.67 per Boe. To achieve these results, management estimates that the Company evaluated, over the last five years, in excess of 1,400 acquisition opportunities with an aggregate market value estimated by management to exceed $15 billion. Over the same period, management estimates that the Company made approximately 280 offers totaling more than $3 billion and successfully closed in excess of 50 transactions having an aggregate purchase price of $172.2 million. This strategy enabled the Company to increase average net daily production from 3,329 Boe in 1991 to 10,688 Boe in 1995, representing a compound annual growth rate of 34%. Similarly, EBITDA increased at a 46% compound annual growth rate from $8.2 million in 1991 to $37.3 million in 1995. See "Business--General" and "--Acquisition and Exploitation of Principal Properties." 4 STRATEGY The Company's strategy is to increase oil and natural gas reserves, production and cash flow by selectively acquiring and exploiting oil and natural gas properties, especially those properties with enhanced recovery and other lower risk development potential. In order to implement its strategy, the Company principally seeks to acquire oil and natural gas properties with the following characteristics: . Geographic Focus--The Company has focused its acquisition activities in the mid-continent region of the United States. This region includes oil and natural gas basins with geological and production characteristics potentially responsive to the Company's exploitation and development techniques. Management believes that it has considerable experience in, and knowledge of, this region. The Company presently has four core operating areas: west Texas, north Texas, west central Oklahoma and southwestern Kansas. The geographic proximity of the Company's various properties allows the Company to minimize the number of operations and field production offices that it must maintain and the number of supervisory personnel that it must employ. . Proved Developed Reserves--The Company prefers to acquire properties where the majority of the reserves are proved developed reserves producing from relatively shallow horizons. Management believes these properties generally present lower geologic and mechanical risks for drilling, recompleting and operating activities. Substantially all of the Company's wells are under 10,000 feet deep. . Operated, High Working Interest Properties--The Company prefers to operate the properties it acquires and to own the majority working interest in those properties. This allows the Company greater control over (i) timing and plans for future development, (ii) drilling, completing and lifting costs and (iii) marketing of production. At December 31, 1995, the Company operated 2,052 of the 2,190 gross producing and active water injection wells in which it owned an interest, and its weighted average working interest in its properties was approximately 82%. . Exploitation Potential--The Company seeks to increase production and recoverable reserves through exploitation efforts on the properties it acquires. Exploitation efforts include workovers and/or recompletions of existing wells; the initiation of, or improvements to, secondary recovery projects, particularly the use of waterflooding; and the drilling of lower risk development and/or infill wells. The Company believes that it has been able to enhance the value and to extend the economic life of many of the properties that it has acquired by utilizing techniques such as these. . Cost Reduction Potential--The Company seeks to acquire properties where significant economic value can be created by lowering operating costs. The Company believes that it has been able to lower the lifting costs on certain properties it has acquired in comparison to the costs incurred by the major oil companies and larger independents that previously operated the properties. These savings were achieved through reductions in labor, electricity, materials and other costs. . Price Improvement Potential--Whenever possible, the Company attempts to negotiate more favorable marketing agreements than those in place under prior owners. After the Company has begun its exploitation activities on its properties, it may attempt to negotiate more favorable prices as the volumes of oil increase. Certain of the Company's oil purchasers have paid and are currently paying a premium over posted prices and have eliminated certain quality and marketing deductions for a portion of the Company's oil production due to the Company's control over a significant volume of oil production in its core geographic areas. 5 The Company believes that future acquisitions, like its past acquisitions, will come from several categories of sellers including: (i) major oil companies; (ii) companies that are consolidating operations to achieve cost savings; (iii) companies and individuals owning interests in wells in which the Company owns a substantial working interest; and (iv) companies with limited capital resources. The success of the Company's strategy depends upon a number of factors outside of the Company's control, including the availability of attractive acquisition opportunities. In recent years, major oil companies have been divesting many of their higher cost domestic oil and natural gas properties. In addition, the oil and natural gas industry continues to consolidate as smaller independents exit the business. The Company believes these trends will continue. By increasing production and lowering operating costs, the Company believes that it can increase economic value and cash flow as well as extend the productive lives of these properties. However, there can be no assurance that the Company will be able to successfully implement its operating strategy. See "Risk Factors--Acquisition Risks; Depletion of Reserves" and "Business-- Exploitation and Development Activities." RECENT ACQUISITION OF CERTAIN PROPERTIES On October 6, 1995, the Company acquired 63 producing oil and natural gas properties and related assets (the "Snyder Acquisition") from Snyder Oil Corporation ("Snyder"). The majority of these properties are located in the Permian Basin in west Texas. The total purchase price of these properties was $17.1 million in cash, of which $16.0 million was financed with borrowings under the Company's then-existing credit agreement. Total proved reserves of these properties were estimated as of October 1, 1995, to be 4.3 Mmbbls of oil and 6.8 Bcf of natural gas. The Company believes that these properties present exploitation opportunities, including opportunities to implement cost-cutting strategies and initiate or improve secondary recovery operations and lower risk development drilling activities. Additionally, the Snyder Acquisition complements the Company's core operating areas within the mid-continent region of the United States. See Pro Forma Condensed Financial Statements. TAURUS Through its Taurus Energy Corp. ("Taurus") subsidiary, the Company also owns and operates three gas processing and liquid extraction facilities and approximately 700 miles of gas gathering systems, primarily located in west central Texas. Taurus was acquired by the Company in April 1994. The Company's gas gathering and processing revenues, from Taurus and its predecessor, have grown from $5.2 million in 1991 to $35.6 million in 1995, and EBITDA has increased from $50,000 to $3.4 million over the same period. Taurus represented approximately nine percent of the Company's consolidated 1995 EBITDA of approximately $37.3 million. The Company intends to study alternatives for maximizing the value of its investment in Taurus. These alternatives could include a sale of Taurus, whether by merger, sale of all or substantially all of the assets of Taurus or sale of all of the capital stock of Taurus. 6 THE MERGER On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as of October 30, 1995 (as amended, the "Merger Agreement"), by and among Coda, Joint Energy Development Investments Limited Partnership ("JEDI"), which is an affiliate of Enron Capital & Trade Resources Corp. ("ECT"), and Coda Acquisition, Inc. ("CAI"), which was a subsidiary of JEDI, JEDI acquired Coda through a merger (the "Merger") at a price of $7.75 per share in cash (for an aggregate purchase price of approximately $176.2 million). Concurrently with the execution of the Merger Agreement, JEDI and CAI entered into certain agreements with members of the Company's management (the "Management Group"). Following consummation of the Merger, the Management Group owns approximately 5% of Coda's common stock on a fully-diluted basis. JEDI owns the remaining 95%. JEDI was formed as a limited partnership between California Public Employees' Retirement System ("CalPERS") and an affiliate of ECT, with the ECT affiliate designated as the general partner. The purpose of the partnership is to invest in a diversified portfolio of energy related assets. See "The Merger." The sources and uses of funds related to financing the Merger were as follows: SOURCES OF FUNDS (in millions) Credit Agreement.................................................. $ 95.0 JEDI Debt(1)...................................................... 100.0 Redeemable Preferred Stock issued to JEDI......................... 20.0 Common Stock issued to JEDI....................................... 90.0 ------ Total......................................................... $305.0 ======
USES OF FUNDS (in millions) Payments to Coda stockholders, warrantholders and optionholders.................................................. $176.2 Repayment of former credit facility and other indebtedness...... 122.7 Merger costs and other expenses................................. 6.1 ------ Total....................................................... $305.0 ======
-------- (1) Represents indebtedness incurred by CAI and assumed by Coda to fund a portion of the consideration paid in the Merger. See "Use of Proceeds." ---------------- The Company was incorporated in Delaware in 1981. The Company's executive offices are located at 5735 Pineland Drive, Suite 300, Dallas, Texas 75231, and its telephone number is (214) 692-1800. 7 THE EXCHANGE OFFER THE EXCHANGE OFFER.............. The Company is hereby offering to exchange $1,000 principal amount of Exchange Notes for each $1,000 principal amount of Private Notes that are properly tendered and accepted. The Private Notes were sold in transactions ex- empt from registration under the Securities Act on March 18, 1996. This Registration Statement is intended to satisfy certain of the Company's obligations under the Registra- tion Rights Agreement and Purchase Agreement (as defined below) entered into in connection with the private placement. The Company will issue Exchange Notes on or promptly after the Expiration Date. As of the date hereof, there is $110,000,000 aggregate principal amount of Private Notes outstanding. See "The Exchange Offer--Purpose of the Exchange Offer." Based on an interpretation by the staff of the Commission set forth in no-action letters issued to third parties, the Company believes that the Exchange Notes issued pursuant to the Exchange Offer in exchange for Private Notes may be offered for resale, resold and otherwise transferred by a holder thereof (other than (i) a broker-dealer who purchases such Exchange Notes directly from the Company to resell pursuant to Rule 144A or any other available exemption under the Securities Act or (ii) a person that is an affiliate of the Company within the meaning of Rule 405 under the Securities Act), without compliance with the registration and prospectus delivery pro- visions of the Securities Act; provided that the holder is acquiring Exchange Notes in the ordinary course of its business and is not participating, and had no arrangement or un- derstanding with any person to participate, in the distribution of the Exchange Notes. Each broker-dealer that receives Exchange Notes for its own account in exchange for Private Notes, where such Private Notes were acquired by such broker-dealer as a result of market-making activities or other trading ac- tivities, must acknowledge that it will de- liver a prospectus in connection with any re- sale of such Exchange Notes. See "The Ex- change Offer--Resale of the Exchange Notes." REGISTRATION RIGHTS AGREEMENT... The Private Notes were sold by the Company on March 18, 1996 to Goldman, Sachs & Co., Chem- ical Securities Inc., ECT Securities Corp. and NationsBanc Capital Markets, Inc. (col- lectively, the "Initial Purchasers") pursuant to a Purchase Agreement, dated March 12, 1996, by and among the Company, the Guaran- tors and the Initial Purchasers (the "Pur- chase Agreement"). Pursuant to the Purchase Agreement, the Company, the Guarantors and 8 the Initial Purchasers entered into a Regis- tration Rights Agreement, dated as of March 18, 1996 (the "Registration Rights Agree- ment"), which grants the holders of the Pri- vate Notes certain exchange and registration rights. The Exchange Offer is intended to satisfy such rights, which will terminate upon the consummation of the Exchange Offer. The holders of the Exchange Notes will not be entitled to any exchange or registration rights with respect to the Exchange Notes. See "The Exchange Offer--Termination of Cer- tain Rights." EXPIRATION DATE................. The Exchange Offer will expire at 5:00 p.m., New York City time, on July 12, 1996, unless the Exchange Offer is extended by the Company in its sole discretion, in which case the term "Expiration Date" shall mean the latest date and time to which the Exchange Offer is extended. See "The Exchange Offer--Expiration Date; Extensions; Amendments." ACCRUED INTEREST ON THE EXCHANGE NOTES AND THE PRIVATE NOTES.......................... The Exchange Notes will bear interest from and including the date of issuance of the Private Notes (March 18, 1996). Holders whose Private Notes are accepted for exchange will be deemed to have waived the right to receive any interest accrued on the Private Notes. See "The Exchange Offer--Interest on the Ex- change Notes." CONDITIONS TO THE EXCHANGE OFFER.......................... The Exchange Offer is subject to certain cus- tomary conditions that may be waived by the Company. The Exchange Offer is not condi- tioned upon any minimum aggregate principal amount of Private Notes being tendered for exchange. See "The Exchange Offer-- Conditions." PROCEDURES FOR TENDERING PRIVATE NOTES.................. Each holder of Private Notes wishing to ac- cept the Exchange Offer must complete, sign and date the Letter of Transmittal, or a fac- simile thereof, in accordance with the in- structions contained herein and therein, and mail or otherwise deliver such Letter of Transmittal, or such facsimile, together with such Private Notes and any other required documentation to Texas Commerce Bank National Association, as exchange agent (the "Exchange Agent"), at the address set forth herein. By executing the Letter of Transmittal, the holder will represent to and agree with the Company that, among other things, (i) the Ex- change Notes to be acquired by such holder of Private Notes in connection with the Exchange Offer are being acquired by such holder in the ordinary course of its business, (ii) if such holder is not a broker-dealer, 9 such holder is not currently participating in, does not intend to participate in, and has no arrangement or understanding with any person to participate in a distribution of the Exchange Notes, (iii) if such holder is a broker-dealer registered under the Exchange Act or is participating in the Exchange Offer for the purposes of distributing the Exchange Notes, such holder will comply with the reg- istration and prospectus delivery require- ments of the Securities Act in connection with a secondary resale transaction of the Exchange Notes acquired by such person and cannot rely on the position of the staff of the Commission set forth in no-action letters (see "The Exchange Offer--Resale of Exchange Notes"), (iv) such holder understands that a secondary resale transaction described in clause (iii) above and any resales of Ex- change Notes obtained by such holder in ex- change for Private Notes acquired by such holder directly from the Company should be covered by an effective registration state- ment containing the selling securityholder information required by Item 507 or Item 508, as applicable, of Regulation S-K of the Com- mission and (v) such holder is not an "affil- iate," as defined in Rule 405 under the Secu- rities Act, of the Company. If the holder is a broker-dealer that will receive Exchange Notes for its own account in exchange for Private Notes that were acquired as a result of market-making activities or other trading activities, such holder will be required to acknowledge in the Letter of Transmittal that such holder will deliver a prospectus in con- nection with any resale of such Exchange Notes; however, by so acknowledging and by delivering a prospectus, such holder will not be deemed to admit that it is an "underwrit- er" within the meaning of the Securities Act. See "The Exchange Offer--Procedures for Tendering." SPECIAL PROCEDURES FOR BENEFICIAL OWNERS.............. Any beneficial owner whose Private Notes are registered in the name of a broker, dealer, commercial bank, trust company or other nomi- nee and who wishes to tender such Private Notes in the Exchange Offer should contact such registered holder promptly and instruct such registered holder to tender on such ben- eficial owner's behalf. If such beneficial owner wishes to tender on such owner's own behalf, such owner must, prior to completing and executing the Letter of Transmittal and delivering such owner's Private Notes, either make appropriate arrangements to register ownership of the Private Notes in such own- er's name or obtain a properly completed bond power from the registered holder. The trans- fer of registered ownership may take consid- erable time and may 10 not be able to be completed prior to the Ex- piration Date. See "The Exchange Offer--Pro- cedures for Tendering." GUARANTEED DELIVERY PROCEDURES..................... Holders of Private Notes who wish to tender their Private Notes and whose Private Notes are not immediately available or who cannot deliver their Private Notes, the Letter of Transmittal or any other documentation re- quired by the Letter of Transmittal to the Exchange Agent prior to the Expiration Date must tender their Private Notes according to the guaranteed delivery procedures set forth under "The Exchange Offer--Guaranteed Deliv- ery Procedures." ACCEPTANCE OF THE PRIVATE NOTES AND DELIVERY OF THE EXCHANGE NOTES.......................... Subject to the satisfaction or waiver of the conditions to the Exchange Offer, the Company will accept for exchange any and all Private Notes that are properly tendered in the Ex- change Offer prior to the Expiration Date. The Exchange Notes issued pursuant to the Ex- change Offer will be delivered on the earli- est practicable date following the Expiration Date. See "The Exchange Offer--Terms of the Exchange Offer." CONSEQUENCES OF NOT EXCHANGING PRIVATE NOTES.................. Private Notes that are not exchanged for Ex- change Notes pursuant to the Exchange Offer will continue to be deemed restricted securi- ties under the Securities Act and subject to the restrictions on transfer of such Private Notes as set forth in the legend thereon. Ac- cordingly, the Private Notes may not be of- fered or sold, unless registered under the Securities Act or sold pursuant to an exemp- tion from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Furthermore, any and all registration rights under the Registration Rights Agreement held by holders of Private Notes eligible to participate in the Exchange Offer will be extinguished as a result of the completion of the Exchange Offer. See "Risk Factors--Consequences of Not Exchanging Pri- vate Notes" and "The Exchange Offer--Conse- quences of Not Exchanging Private Notes." WITHDRAWAL RIGHTS............... Tenders of Private Notes may be withdrawn at any time prior to the Expiration Date. See "The Exchange Offer--Withdrawal of Tenders." CERTAIN FEDERAL INCOME TAX CONSIDERATIONS................. For a discussion of certain material federal income tax considerations relating to the ex- change of the Exchange Notes for the Private Notes, see "Certain Federal Income Tax Con- siderations." 11 EXCHANGE AGENT.................. Texas Commerce Bank National Association is serving as the Exchange Agent in connection with the Exchange Offer. THE EXCHANGE NOTES The Exchange Offer applies to $110,000,000 aggregate principal amount of the Private Notes. The form and terms of the Exchange Notes are the same as the form and terms of the Private Notes except that (i) the Exchange Notes will bear the Series B designation, (ii) the Exchange Notes will have been registered under the Securities Act and, therefore, the Exchange Notes will not bear legends restricting the transfer thereof and (iii) holders of the Exchange Notes will not be entitled to certain rights of holders of the Private Notes under the Registration Rights Agreement, which rights will terminate upon consummation of the Exchange Offer. The Exchange Notes will evidence the same indebtedness as the Private Notes (which they replace) and will be issued under, and be entitled to the benefits of, the Indenture. For further information and for definitions of certain capitalized terms used below, see "Description of Exchange Notes." ISSUER.......................... Coda Energy, Inc. SECURITIES OFFERED.............. $110 million principal amount of 10 1/2% Se- ries B Senior Subordinated Notes due 2006. MATURITY DATE................... April 1, 2006. INTEREST PAYMENT DATES.......... The Exchange Notes will bear interest at an annual rate of 10 1/2% and will be payable in cash semiannually in arrears on April 1 and October 1 of each year, commencing October 1, 1996. See "The Exchange Offer--Interest on the Exchange Notes." RANKING......................... The Exchange Notes will be general, unsecured obligations of Coda, will be subordinated in right of payment to all Senior Debt of Coda, and will be senior in right of payment to all future subordinated debt of Coda. The claims of the holders of the Exchange Notes will be subordinated to Senior Debt, which, as of March 31, 1996, was $81.8 million. On May 1, 1996, the Company redeemed all its outstand- ing 12% Senior Subordinated Debentures due 2000, which resulted in a reduction in Senior Debt of approximately $1.2 million. See "Cap- italization." GUARANTEES...................... Coda's payment obligations under the Exchange Notes will be jointly and severally guaran- teed on a senior subordinated basis by all of Coda's current subsidiaries and future Re- stricted Subsidiaries. The Subsidiary Guaran- tees will be subordinated to the guarantees of Senior Debt issued by the Guarantors under the Credit Agreement and to other guarantees of Senior Debt issued in the future. See "De- scription of Exchange Notes--Subsidiary Guar- antees" and "Description of Other Indebtedness." 12 FORM AND DENOMINATION........... The Exchange Notes will be fully registered as to principal and interest in minimum de- nominations of $100,000 for institutional ac- credited investors and $1,000 for qualified institutional buyers and, in both cases, in integral multiples of $1,000 in excess there- of. The Exchange Notes will be represented by one Global Note in fully registered form, de- posited with a custodian for and registered in the name of a nominee of the Depositary. Beneficial interests in the Global Note rep- resenting the Exchange Notes will be shown on, and transfers thereof will be effected only through, records maintained by the De- positary and its participants. Except as de- scribed herein, Exchange Notes in certifi- cated form will not be issued in exchange for the Global Note or interests therein. See "Description of Exchange Notes--Book-Entry, Delivery and Form." CERTAIN COVENANTS............... The Exchange Notes will be issued pursuant to the Indenture, which contains certain cove- nants that, among other things, limit the ability of Coda and its Restricted Subsidiar- ies to incur additional indebtedness and is- sue Disqualified Stock, pay dividends, make distributions, make investments, make certain other Restricted Payments, enter into certain transactions with affiliates, dispose of cer- tain assets, incur liens securing pari passu or subordinated indebtedness of Coda and en- gage in mergers and consolidations. See "De- scription of Exchange Notes--Certain Cove- nants." MANDATORY REDEMPTION............ None. OPTIONAL REDEMPTION............. Except as described below, the Notes are not redeemable at Coda's option prior to April 1, 2001. After April 1, 2001, the Notes will be subject to redemption at the option of Coda, in whole or in part, at the redemption prices set forth herein, plus accrued and unpaid in- terest thereon to the applicable redemption date. In addition, until March 12, 1999, up to $27.5 million in aggregate principal amount of Notes will be redeemable at the option of Coda on any one or more occasions from the net proceeds of an offering of common equity of Coda, at a price of 110.5% of the aggre- gate principal amount of the Notes, together with accrued and unpaid interest thereon to the date of the redemption; provided, howev- er, that at least $82.5 million in aggregate principal amount of Notes must remain out- standing immediately after the occurrence of such redemption; provided, further, that any such redemption shall occur within 75 13 days of the date of the closing of such of- fering of common equity. See "Description of Exchange Notes--Optional Redemption." CHANGE OF CONTROL............... In the event of a Change of Control, holders of the Notes will have the right to require Coda to repurchase their Notes, in whole or in part, at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the date of repurchase. The Indenture will re- quire that, prior to such a repurchase but in any event within 90 days of such Change of Control, Coda must either repay all Senior Debt or obtain any required consent to such repurchase. The degree to which the Company is leveraged at the time of a Change of Con- trol could prevent it from repaying outstand- ing Senior Debt (or otherwise obtaining the consent of holders of Senior Debt to make a Change of Control Offer) which would prohibit Coda from repurchasing Notes tendered to it upon such Change of Control. In such case, Coda's failure to purchase the Notes would constitute an Event of Default under the In- denture. In such circumstances, the subordi- nation provisions in the Indenture would likely restrict payments to the Holders of Notes by either Coda or the Guarantors. Coda is not required to make a Change of Control Offer if a third party makes a Change of Con- trol Offer in compliance with the Indenture and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer. See "Description of Exchange Notes-- Repurchase at the Option of Holders--Change of Control." RISK FACTORS Prior to making an investment decision, holders of the Private Notes should consider all of the information set forth in this Prospectus and should evaluate the considerations set forth in "Risk Factors" beginning on page 18 hereof. 14 SUMMARY FINANCIAL INFORMATION The following table sets forth certain historical and pro forma operating and financial data of the Company. See "Selected Historical and Pro Forma Financial Data" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The historical data should be read in conjunction with the Historical Financial Statements and the notes thereto included elsewhere in this Prospectus. The Company acquired significant producing oil and natural gas properties in all the periods presented which affect the comparability of the historical financial and operating data for the periods presented. As a result of the Merger, JEDI acquired Coda effective February 16, 1996. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired based on estimated fair values. As a result, the Company's financial position and operating results subsequent to the date of the Merger reflect a new basis of accounting and are not comparable to prior periods. The pro forma information should be read in conjunction with the Pro Forma Condensed Financial Statements and notes thereto included elsewhere in this Prospectus. Neither the historical results nor the pro forma results are necessarily indicative of the Company's future operations or financial results.
HISTORICAL PRO FORMA ----------------------------------------------------------------------------- ------------------------- THREE MONTHS 47 DAYS 44 DAYS YEAR THREE MONTHS YEAR ENDED DECEMBER 31, ENDED ENDED ENDED ENDED ENDED ----------------------------------------- MARCH 31, FEBRUARY 16, MARCH 31, DECEMBER 31, MARCH 31, 1991 1992 1993 1994 1995 1995 1996 1996 1995(1) 1996(1) ------- ------- ------- ------- ------- ------------ ------------ --------- ------------ ------------ (in thousands, except ratios) INCOME STATEMENT DATA: Oil and gas sales........... $16,512 $18,631 $38,877 $50,683 $60,997 $14,948 $8,079 $8,964 $66,156 $17,043 Gas gathering and processing(2)... 5,246 4,709 732 20,081 35,634 7,904 5,322 4,799 35,634 10,121 Total revenues.. 22,782 23,637 40,050 71,586 97,838 23,039 13,569 13,964 102,997 27,533 Interest expense......... 2,420 2,752 4,834 5,281 8,676 2,068 1,102 2,087 18,563 4,300 Total costs and expenses(3)..... 21,865 24,778 36,398 65,676 88,881 20,938 15,378 97,015 110,066 27,816 Income (loss) before income taxes........... 917 (1,141) 3,652 5,910 8,957 2,101 (1,809) (83,051) (7,069) (283) Net income (loss).......... (65) (734) 2,334 3,329 5,755 1,305 (1,298) (53,136) (4,493) (279) Ratio of earnings to fixed charges(4)...... 1.4x -- 1.8x 2.1x 2.0x 2.0x -- -- -- -- CASH FLOW DATA(5): Net income (loss).......... $ (65) $ (734) $ 2,334 $ 3,329 $ 5,755 $ 1,305 $(1,298) $(53,136) $ (4,493) $ (279) Depletion, depreciation and amortization.... 4,823 4,813 10,808 16,419 19,715 4,870 2,583 3,498 28,509 6,897 Net cash provided by operating activities...... 6,127 2,241 16,443 22,987 24,301 5,122 3,136 1,461 17,069 3,487 OTHER DATA(6): EBITDA.......... 8,160 6,424 19,294 27,610 37,348 9,039 1,876 5,839 40,003 10,914 EBITDA/interest expense......... 3.4x 2.3x 4.0x 5.2x 4.3x 4.4x 1.7x 2.8x 2.2x 2.5x Debt/EBITDA..... 3.8x 9.2x 3.2x 3.8x 3.3x CAPITAL EXPENDITURES: Oil and gas property acquisitions.... $21,650 $23,318 $42,223 $40,109 $25,363 $ 498 $ 305 $ 92 Oil and gas development and other........... 4,404 7,550 10,403 12,450 14,464 4,457 1,412 678 Gas plant and gathering systems and other property additions....... 687 1,365 646 7,380 8,500 7,346 114 43
15 SUMMARY FINANCIAL INFORMATION (CONTINUED)
AT DECEMBER 31, ------------------------------------------ MARCH 31, 1991 1992 1993 1994 1995 1996 ------- ------- -------- -------- -------- --------- (in thousands) BALANCE SHEET DATA: Total assets............. $56,010 $82,226 $132,754 $203,102 $229,064 $304,435 Notes.................... -- -- -- -- -- 110,000 Other long-term debt, less current maturities.. 28,794 56,563 59,651 105,063 123,907 81,719 Redeemable Preferred Stock.................... -- -- -- -- -- 20,000 Common stockholders' equity................... 19,502 18,949 58,231 74,741 79,188 40,487
SUMMARY OPERATING DATA
HISTORICAL PRO FORMA ---------------------------------------------------------------------- ------------------------- THREE MONTHS 47 DAYS 44 DAYS YEAR THREE MONTHS YEAR ENDED DECEMBER 31, ENDED ENDED ENDED ENDED ENDED ---------------------------------- MARCH 31, FEBRUARY 16, MARCH 31, DECEMBER 31, MARCH 31, 1991 1992 1993 1994 1995 1995 1996 1996 1995(1) 1996(1) ------ ------ ------ ------ ------ ------------ ------------ --------- ------------ ------------ Production Oil (Mbbls)......... 517 734 1,766 2,650 3,165 772 408 427 3,440 835 Gas (Mmcf).......... 4,188 3,255 4,703 4,982 4,416 1,186 500 512 4,895 1,012 Oil Equivalent (Mboe)............. 1,215 1,277 2,550 3,480 3,901 970 491 512 4,256 1,003 Average sales prices Oil (per Bbl)....... $19.14 $19.03 $16.88 $15.86 $17.08 $17.03 $17.57 $18.89 $17.01 $18.25 Gas (per Mcf)....... 1.58 1.44 1.92 1.74 1.57 1.52 1.82 1.75 1.56 1.78 Production costs per Boe(7).............. 5.86 8.02 6.90 6.22 6.95 6.77 7.33 7.59 7.18 7.46 Depreciation, depletion and amortization per Boe................. 3.89 3.64 4.15 4.27 4.33 4.33 4.40 5.94 5.94 5.94 General and administrative per Boe................. 2.06 1.98 1.02 0.90 0.74 .73 .65 .69 0.46 .67 Average finding cost per Boe............. 1.96 3.57 5.27 4.21 2.97
SUMMARY RESERVE DATA
AT DECEMBER 31, ------------------------------------------- 1991 1992 1993 1994 1995 ------- -------- -------- -------- -------- Proved reserves(8) Oil (Mbbls)...................... 12,389 18,941 30,084 39,207 42,590 Gas (Mmcf)....................... 28,601 27,830 36,196 39,808 37,130 Total proved reserves (Mboe)..... 17,156 23,579 36,117 45,842 48,778 Proved developed reserves (Mboe)........................... 12,496 18,222 21,326 25,633 31,126 Annual reserve replacement ratio(9).......................... 5.7 5.6 6.9 6.0 2.3 Estimated reserve life (in years)(10)........................ 12.9 11.6 9.9 10.3 11.7 Present value of estimated future net revenues before income taxes (in thousands)(11)................ $81,361 $121,494 $140,980 $217,540 $283,375 Standardized measure of discounted future net cash flows (in thousands)(12).................... 65,175 95,860 116,023 168,616 220,742
16 - -------- (1) Reflects the pro forma effect of the Snyder Acquisition, the Merger, the sale of the Private Notes and the application of the proceeds thereof to retire the JEDI Debt and pay down a portion of the outstanding borrowings under the Credit Agreement. See the Company's Pro Forma Condensed Financial Statements, included elsewhere in this Prospectus, for a discussion of the preparation of this data. The pro forma combined results of operations exclude a charge of approximately $53.3 million (net of related deferred taxes of $30.0 million) representing the adjustment of the carrying value of proved oil and gas properties pursuant to the full cost method of accounting. Such adjustment has been included in the historical results of operations of the Company in the period the Merger was consummated. Pro forma net cash provided by operating activities was obtained by adjusting the historical amount for the pro forma changes in oil and natural gas sales, oil and natural gas production expenses, general and administrative expenses and interest expense. The exchange of the Exchange Notes for the Private Notes would have no effect on the pro forma information. See also "Use of Proceeds" and "Capitalization." (2) The Company ceased its third party natural gas marketing operations in 1992. The Company acquired Taurus in April 1994. (3) Total costs and expenses for the periods ended February 16, 1996 and March 31, 1996 include approximately $3.2 million of stock option compensation expense and $83.3 million for the writedown of oil and gas properties, respectively. (4) For purposes of computing the ratio of earnings to fixed charges, earnings consist of income before income taxes plus fixed charges. Fixed charges consist of interest expense. For the periods ended December 31, 1992, February 16, 1996 and March 31, 1996, earnings were inadequate to cover fixed charges by approximately $1.1 million, $1.8 million and $83.1 million, respectively. Pro forma earnings for the year ended December 31, 1995 and three months ended March 31, 1996, would have been inadequate to cover fixed charges by approximately $7.1 million and $283,000, respectively. (5) In addition to cash flows provided by operating activities, the Company also has significant cash flows which are provided by or used in investing and financing activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources," "--Effects of the Merger, the Sale of the Private Notes and the Exchange Offer--Credit Agreement" and the Historical Financial Statements of the Company. (6) EBITDA is calculated as operating income before interest, income taxes, depletion, depreciation and amortization. EBITDA is not a measure of cash flow as determined by generally accepted accounting principles ("GAAP"). The Company has included information concerning EBITDA because EBITDA is a measure used by certain investors in determining the Company's historical ability to service its indebtedness. EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows as determined in accordance with GAAP as an indicator of the Company's operating performance or liquidity. Debt/EBITDA is calculated only for the historical annual periods. EBITDA for the period ended February 16, 1996 is net of approximately $3.2 million of stock option compensation expense which is a non-cash charge. (7) Production costs in 1992 were relatively high because two of the Company's waterflood operations and the costs associated therewith commenced in 1992 but the anticipated response of increased oil production did not commence to any material degree until 1993. (8) In 1994, the Company acquired Diamond Energy Operating Company and a related company which have since merged ("Diamond") in a transaction accounted for as a pooling of interests. Reserve data was prepared by the Company's independent consulting engineers except that such estimates related to the reserves of Diamond as of December 31, 1991, 1992 and 1993 were prepared by Diamond's in-house engineers. (9) The annual reserve replacement ratio is calculated by dividing total reserve additions (purchases of reserves, extensions and revisions) on a Boe basis for the year by actual production on a Boe basis for such year with the acquisition of Diamond treated as a purchase instead of a pooling. (10) The estimated reserve life is calculated by dividing the proved reserves on a Boe basis by the forecasted production on a Boe basis for the 12 months following the date indicated (both as estimated by the Company's independent consulting engineers as of December 31 of each year). (11) Discounted at an annual rate of 10%. See "Glossary" included elsewhere in this Prospectus for the definition of "present value of estimated future net revenues." The Company believes that the present value of estimated future net revenues before income taxes, while not in accordance with generally accepted accounting principles, is an important financial measure used by investors in independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions. The present value of estimated future net revenues should not be construed as an alternative to the Standardized Measure, as determined in accordance with generally accepted accounting principles. (12) Represents after tax present value of estimated future net revenues. 17 RISK FACTORS Prior to making an investment decision, prospective investors should consider fully, together with the other information contained in this Prospectus, the following factors. This Prospectus contains forward looking statements of the Company. The Company wishes to caution prospective investors that the following important factors could affect the Company's actual results in the future. TENDERING PRIVATE NOTES Exchange Notes will be issued in exchange for Private Notes only after timely receipt by the Exchange Agent of such Private Notes, a properly completed and duly executed Letter of Transmittal and all other required documentation. Therefore, holders of Private Notes desiring to tender such Private Notes in exchange for Exchange Notes should allow sufficient time to ensure timely delivery. Neither the Exchange Agent nor the Company is under any duty to give notification of defects or irregularities with respect to tenders of Private Notes for exchange. In addition, any holder of Private Notes who tenders in the Exchange Offer for the purpose of participating in a distribution of the Exchange Notes will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction. Each broker-dealer that receives Exchange Notes for its own account in exchange for Private Notes, where such Private Notes were acquired by such broker-dealer as a result of market-making activities or any other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. See "The Exchange Offer." CONSEQUENCES OF NOT EXCHANGING PRIVATE NOTES Private Notes that are not exchanged for Exchange Notes pursuant to the Exchange Offer will continue to be deemed restricted securities under the Securities Act and subject to the restrictions on transfer of such Private Notes a set forth in the legend thereon. Accordingly, the Private Notes may not be offered or sold, unless registered under the Securities Act or sold pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Furthermore, any and all registration rights under the Registration Rights Agreement held by holders of Private Notes eligible to participate in the Exchange Offer will be extinguished as a result of the completion of the Exchange Offer. To the extent that Private Notes are tendered and accepted in the Exchange Offer, the trading market for untendered and tendered but unaccepted Private Notes could be adversely affected due to the limited amount, or "float," of the Private Notes that are expected to remain outstanding following the Exchange Offer. Generally, a lower "float" of a security could result in less demand to purchase such security and could, therefore, result in lower prices for such security. For the same reason, to the extent that a large amount of Private Notes are not tendered or are tendered and not accepted in the Exchange Offer, the trading market for the Exchange Notes could be adversely affected. See "The Exchange Offer--Consequences of Not Exchanging Private Notes." LEVERAGE The Company incurred substantial indebtedness in connection with the Merger and as a result, the Company is highly leveraged. As of March 31, 1996, the Company had total indebtedness of approximately $191.8 million and stockholders' equity (including preferred stock) of approximately $60.5 million. Also, after giving pro forma effect to the Merger and the related financing transactions, including the sale of the Private Notes, the Company's earnings would have been insufficient to cover its fixed charges by approximately $7.1 million for 1995. Pro forma interest expense for 1995 would have been approximately $18.6 million. The Company intends to incur additional indebtedness in the future as it executes its acquisition and exploitation strategy. See "--Ability to Obtain Capital to Finance Acquisitions," "Capitalization" and Pro Forma Condensed Financial Statements. 18 The Company's ability to make scheduled payments of principal of, or to pay interest on, or to refinance its indebtedness (including the Notes) depends on its future performance, which, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory and other factors beyond its control, as well as to the prevailing market prices for oil and natural gas. There can be no assurance that the Company's business will generate sufficient cash flow from operations or that future bank credit will be available in an amount sufficient to enable the Company to service its indebtedness, including the Notes, or make necessary capital expenditures. In addition, the Company anticipates that it is likely to find it necessary to refinance a portion of the principal amount of the Notes at or prior to their maturity. However, there can be no assurance that the Company will be able to obtain financing to complete a refinancing of the Notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations-- Liquidity and Capital Resources." The degree to which the Company is leveraged as a result of the sale of the Private Notes could have important consequences to holders of the Notes, including, but not limited to, the following: (i) a substantial portion of the Company's cash flow from operations will be required to be dedicated to debt service and will not be available for other purposes; (ii) the Company's ability to obtain additional financing in the future could be limited; (iii) certain of the Company's borrowings are at variable rates of interest, which could result in higher interest expense in the event of increases in interest rates; and (iv) the Company will be subject to a variety of restrictive covenants and the failure of the Company to comply with such covenants could result in events of default which, if not cured or waived, could have a material adverse effect on the Company and its ability to make payments of principal of, and interest on, the Notes. See "Description of Exchange Notes" and "Description of Other Indebtedness." ACQUISITION RISKS; DEPLETION OF RESERVES The Company's strategy is to increase oil and natural gas reserves and cash flow by selectively acquiring and exploiting producing oil and natural gas properties, primarily in the mid-continent region of the United States, rather than engaging in exploratory drilling. The Company's business strategy assumes that major integrated oil companies and independent oil companies will continue to divest many of their domestic oil and natural gas properties. There can be no assurance, however, that such divestitures will continue or that the Company will be able to acquire such properties at acceptable prices or develop additional reserves in the future. If such acquisition opportunities should cease to exist, the Company may be required to alter its business strategy. Although the Company performs a review of the properties proposed to be acquired, such reviews are subject to uncertainties. It is not feasible to review in detail every individual property involved in each acquisition. Ordinarily, the Company will focus its review efforts on the higher-valued properties. However, even a detailed review of all properties and records may not necessarily reveal existing or potential problems; nor will it permit the Company to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are not routinely performed on every well, and many potential problems, for example, mechanical integrity of equipment and environmental conditions that may require significant remedial expenditures, are not necessarily detectable even when an inspection is undertaken. See "Business--Strategy." Producing oil and natural gas reservoirs are, in general, characterized by declining production rates. The decline rate varies depending upon reservoir characteristics and other factors. The Company's future oil and natural gas reserves and production, and, therefore, cash flow and income, are highly dependent upon the Company's level of success in exploiting its current reserves and acquiring or finding additional reserves. Without reserve additions in excess of production through acquisition or exploitation and development activities, the Company's reserves and production will decline over the long term. There can be no assurance that the Company will be able to find and develop or acquire additional reserves to replace its current and future production. 19 ABILITY TO OBTAIN CAPITAL TO FINANCE ACQUISITIONS The Company's strategy of acquiring producing oil and natural gas properties is dependent upon its ability to obtain financing for any such acquisitions. The Company expects to utilize its Credit Agreement (the "Credit Agreement") with NationsBank of Texas, N.A. ("NationsBank"), individually and as agent, and certain other financial institutions as lenders, to borrow 60% to 100% of the funds required on any given transaction. The Credit Agreement limits the amounts the Company may borrow thereunder to amounts, determined by the lenders in their sole discretion, based upon projected net revenues from the Company's oil and natural gas properties and gas gathering and processing assets and restricts the amounts the Company may borrow under other credit facilities. The lenders can adjust the borrowings permitted to be outstanding under the Credit Agreement semiannually. The lenders require that outstanding borrowings in excess of the borrowing limit be repaid ratably over a period no longer than six months. No assurances can be given that the Company will be able to make any such mandatory principal payments required by the lenders. Any future acquisition by the Company requiring bank financing in excess of the amount then available under the Credit Agreement will depend upon the lenders' evaluations of the properties proposed to be acquired. For a description of the Credit Agreement and its principal terms and conditions, see "Description of Other Indebtedness." VOLATILITY OF OIL, NATURAL GAS AND NATURAL GAS LIQUIDS PRICES The Company's financial results are significantly impacted by the price received for the Company's oil, natural gas and natural gas liquids production. Historically, the markets for oil, natural gas and natural gas liquids have been volatile and are likely to continue to be volatile in the future. Prices for oil, natural gas and natural gas liquids are subject to wide fluctuation in response to market uncertainty, changes in supply and demand and a variety of additional factors, all of which are beyond the control of the Company. These factors include domestic and foreign political conditions, the overall level of supply of and demand for oil, natural gas and natural gas liquids, the price of imports of oil and natural gas, weather conditions, the price and availability of alternative fuels and overall economic conditions. The Company's future financial condition and results of operations will be dependent, in part, upon the prices received for the Company's oil and natural gas production, as well as the costs of acquiring, finding, developing and producing reserves. If oil and natural gas prices fall materially below their current levels, the availability of funds and the Company's ability to repay outstanding amounts under its Credit Agreement and the Notes could be materially adversely affected. See "--Ability to Obtain Capital" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." RELIANCE ON ESTIMATES OF PROVED RESERVES AND FUTURE NET REVENUES There are numerous uncertainties in estimating quantities of proved reserves and in projecting future rates of production and the timing of development expenditures, including many factors beyond the control of the Company. The reserve data set forth in this Prospectus are only estimates. Reserve estimates are imprecise and may be expected to change as additional information becomes available. Furthermore, estimates of oil and gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be exactly measured, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, estimates of the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery and estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers at different 20 times may vary substantially. There also can be no assurance that the reserves set forth herein will ultimately be produced or that the proved undeveloped reserves will be developed within the periods anticipated. It is likely that variances from the estimates will be material. In addition, the estimates of future net revenues from proved reserves of the Company and the present value thereof are based upon certain assumptions about future production levels, prices and costs that may not be correct. The Company emphasizes with respect to the estimates prepared by independent petroleum engineers that the discounted future net cash flows should not be construed as representative of the fair market value of the proved oil and natural gas properties belonging to the Company, since discounted future net cash flows are based upon projected cash flows which do not provide for changes in oil and natural gas prices or for escalation of expenses and capital costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. Actual results are likely to differ materially from the results estimated. Prospective investors in the Exchange Notes are cautioned not to place undue reliance on the reserve data included in this Prospectus. DRILLING AND OPERATIONAL RISKS The Company's oil and natural gas business is also subject to all of the operating risks associated with the drilling for and production and secondary recovery of oil and natural gas, including, but not limited to, uncontrollable flows of oil, natural gas, brine or well fluids (including fluids used in waterflood activities) into the environment (including groundwater contamination), fires, explosions, pollution and other risks, any of which could result in substantial losses to the Company. The natural gas gathering and processing business is also subject to certain of these risks, including fires, explosions and environmental contamination. Although the Company carries insurance at levels which it believes are consistent with industry practices, it is not fully insured against all risks. Losses and liabilities arising from uninsured and underinsured events could have a material adverse effect on the financial condition and operations of the Company. See "Business--Exploitation and Development Activities." There are certain risks associated with secondary recovery operations, especially the use of waterflooding techniques, and drilling activities in general. Waterflooding involves significant capital expenditures and uncertainty as to the total amount of secondary reserves that can be recovered. In waterflood operations, there is generally a delay between the initiation of water injection into a formation containing hydrocarbons and any increase in production that may result. The unit production costs per Boe of waterflood projects are generally higher during the initial phases of such projects due to the purchase of injection water and related costs, as well as during the later stages of the life of the project. The degree of success, if any, of any secondary recovery program depends on a large number of factors, including the porosity of the formation, the technique used and the location of injector wells. Drilling activities carry the risk that no commercial production will be obtained. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of many factors. SUBORDINATION OF THE NOTES AND GUARANTEES The Notes and Guarantees will be subordinated in right of payment to all existing and future Senior Debt of the Company, which includes all indebtedness under the Credit Agreement. As of March 31, 1996, the Company had $81.8 million in Senior Debt and $35.0 million available for borrowing under the Credit Agreement. In the event of a liquidation, dissolution, reorganization, bankruptcy or any similar proceeding regarding the Company, the assets of the Company will be available to pay obligations on the Notes only after Senior Debt of the Company has been paid in full. Accordingly, there may not be sufficient funds remaining to pay amounts due on all or any of the Notes. See "Description of Exchange Notes--Subordination." 21 The Company's oil and natural gas properties will not serve as collateral under the Credit Agreement unless certain events occur. The Company will provide the lenders with first lien deeds of trust on substantially all of the Company's oil and natural gas properties. The lenders have agreed, however, that the mortgages will not be effective and the lenders will not file the deeds of trust on the oil and natural gas assets unless (i) 80% of any outstanding borrowings in excess of the borrowing limit is not repaid within a 90 day period, (ii) cash collateral securing a hedging transaction exceeds 20% of the borrowing limit or (iii) an event of default or a material adverse event, as defined in the Credit Agreement, occurs. In addition to being subordinated to all existing and future Senior Debt of the Company, the Notes and Guarantees will not be secured by any of the Company's assets. GOVERNMENT LAWS AND REGULATIONS The Company's operations are affected from time to time in varying degrees by political developments and federal and state laws and regulations. In particular, oil and natural gas production, operations and economics are or have been affected by price controls, taxes and other laws relating to the oil and natural gas industry, by changes in such laws and by changes in administrative regulations. The Company cannot predict how existing laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on its business or financial condition. See "Business-- Regulation." ENVIRONMENTAL REGULATIONS The Company's operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local governmental authorities. The Company believes that compliance with such laws has had no material adverse effect upon the Company's operations to date, and that the cost of such compliance has not been material. Nevertheless, the discharge of oil, natural gas or other pollutants into the air, soil or water may give rise to liabilities on the part of the Company to the government and third parties and may require the Company to incur costs of remediation. Additionally, since a significant portion of the Company's reserves are dependent upon waterflood operations, any change in produced water disposal requirements or injection well permitting could have a material adverse effect on the financial conditions and operations of the Company. Moreover, from time to time the Company has agreed to indemnify both sellers of producing properties from whom the Company acquires reserves and purchasers of properties from the Company against certain liabilities for environmental claims associated with the properties being purchased or sold by the Company. No assurance can be given that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations, will not materially adversely affect the Company's operations and financial condition or that material indemnity claims will not arise against the Company with respect to properties acquired or sold by the Company. See "Business--Environmental Matters." USE AND RISKS OF HEDGING TRANSACTIONS The Company has in the past and may in the future enter into oil and natural gas hedging transactions. While intended to reduce the effects of volatility of the price of oil and natural gas, such transactions may limit potential gains by the Company if oil and natural gas prices were to rise substantially over the price established by the hedge. If the Company is required to maintain cash collateral on hedging transactions which exceeds 20% of the Company's borrowing limit under its Credit Agreement, the Company may be required by the lenders to pledge substantially all of its oil and natural gas properties as collateral under the Credit Agreement. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Results of Operations" and Note 7 of Notes to Consolidated Financial Statements. 22 CONFLICTS OF INTEREST Enron Corp. ("Enron") is the parent of ECT and accordingly may be deemed to control indirectly both JEDI and the Company. Enron and certain of its subsidiaries and other affiliates collectively participate in nearly all phases of the oil and natural gas industry and are, therefore, competitors of the Company. In addition, ECT and JEDI have provided, and may in the future provide, and ECT Securities Corp. has assisted, and may in the future assist, in arranging, financing to non-affiliated participants in the oil and natural gas industry who are or may become competitors of the Company. ECT, the Company, JEDI and the Management Group have entered into a Business Opportunity Agreement (the "Business Opportunity Agreement") that is intended to make clear that Enron and its affiliates have no duty to make business opportunities available to the Company in most circumstances. The Business Opportunity Agreement also provides that ECT and its affiliates may pursue certain business opportunities to the exclusion of the Company. Accordingly, the Business Opportunity Agreement may limit the business opportunities available to the Company. In addition, pursuant to the Business Opportunity Agreement there may be circumstances in which the Company will be required to offer business opportunities to certain affiliates of Enron. If an Enron affiliate is offered such an opportunity and decides to pursue it, the Company may be unable to pursue it. In addition, the Company has in the past marketed a material portion of its crude oil and natural gas production through certain Enron trading subsidiaries and will likely continue to do so in the future. During 1994 and 1995, sales of oil and natural gas to EOTT Energy Operating Limited Partnership (a subsidiary of Enron) accounted for 22% and 18%, respectively, of the Company's consolidated revenues. The Indenture will not prohibit the Company from conducting business with Enron and its subsidiaries and affiliates, but will provide that certain requirements must be satisfied in order for the Company to transact such business. See "Description of Exchange Notes--Certain Covenants" and "Certain Transactions." COMPETITION The Company encounters substantial competition in acquiring properties, marketing oil and natural gas and securing trained personnel. Many competitors have financial resources, staffs and facilities which substantially exceed those of the Company. See "Business--Markets and Competition." DEPENDENCE ON KEY PERSONNEL The Company believes that its operations are dependent to a significant extent upon its senior management. The loss of the services of a significant number of these key personnel could have a material adverse effect upon the Company. The Credit Agreement contains a covenant that requires the continued employment of certain members of management and requires that certain officers of the Company maintain specified levels of equity ownership in the Company. See "Management." PAYMENT UPON A CHANGE OF CONTROL Upon the occurrence of a Change of Control, each holder of the Notes may require the Company to repurchase all or a portion of such holder's Notes at 101% of the principal amount of the Notes, together with accrued and unpaid interest and Liquidated Damages, if any, to the date of repurchase. The Indenture will require that prior to such a repurchase, the Company must either repay all outstanding Senior Debt or obtain any required consents to such repurchase. Further, under the Credit Agreement, an event of default is deemed to occur if (i) JEDI, Enron, CalPERS or any wholly owned subsidiary of either Enron or CalPERS ceases to own greater than 50% of every class of issued and outstanding capital stock of the Company (on either an undiluted or fully diluted basis), (ii) JEDI, Enron, CalPERS or any wholly owned subsidiary of either Enron or CalPERS ceases to own a majority of the outstanding capital stock of the Company (on either an undiluted or fully diluted basis) having ordinary 23 voting rights for the election of directors or (iii) certain officers cease to serve in their current positions. In such circumstances, the lenders could require the repayment of the borrowings under the Credit Agreement. Thus, if a Change of Control were to occur, the Company may not have the financial resources to repay all of the Senior Debt, the Notes and the other indebtedness that would become payable upon the occurrence of such Change of Control. See "Description of Exchange Notes--Repurchase at the Option of Holders--Change of Control." FRAUDULENT CONVEYANCE Management of the Company believes that the indebtedness represented by the Notes and the Guarantees was incurred for proper purposes and in good faith, and that, based on present forecasts, asset valuations and other financial information, after the consummation of the sale of the Private Notes and the Exchange Offer, the Company will be solvent, will have sufficient capital for carrying on its business and will be able to pay its debts as they mature. See, however, "--Leverage." Notwithstanding management's belief, however, if a court of competent jurisdiction in a suit by an unpaid creditor or a representative of creditors (such as a trustee in bankruptcy or a debtor-in- possession) were to find that, at the time of the incurrence of such indebtedness, the Company or any of the Guarantors were insolvent, were rendered insolvent by reason of such incurrence, were engaged in a business or transaction for which its remaining assets constituted unreasonably small capital, intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured, or intended to hinder, delay or defraud its creditors, and that the indebtedness was incurred for less than reasonably equivalent value, then such court could, among other things, (i) void all or a portion of the Company's or the Guarantors' obligations to the holders of the Notes, the effect of which would be that the holders of the Notes may not be repaid in full and/or (ii) subordinate the Company's or the Guarantors' obligations to the holders of the Notes to other existing and future indebtedness of the Company to a greater extent than would otherwise be the case, the effect of which would be to entitle such other creditors to be paid in full before any payment could be made on the Notes or the Guarantees. LACK OF PUBLIC MARKET FOR THE NOTES; RESTRICTIONS ON RESALES As of the date of this Prospectus, the only registered holder of the Private Notes is Cede & Co., as nominee of DTC. The Company believes that, as of the date of this Prospectus, such holder is not an "affiliate" (as such term is defined in Rule 405 under the Securities Act) of the Company. Prior to the offering of the Private Notes, there had been no existing trading market for the Notes, and there can be no assurance regarding the future development of a market for the Notes, or the ability of holders of the Notes to sell their Notes or the price at which such holders may be able to sell their Notes. If such a market were to develop, the Notes could trade at prices that may be higher or lower than the initial offering price of the Private Notes depending on many factors, including prevailing interest rates, the Company's operating results and the market for similar securities. The Initial Purchasers (other than ECT Securities Corp.) have advised the Company that they currently intend to make a market in the Notes. The Purchasers are not obligated to do so, however, and any market-making with respect to the Notes may be interrupted or discontinued at any time without notice. In addition, such market making activity may be limited during the Exchange Offer and the pendency of the Shelf Registration Statement (as defined in the Registration Rights Agreement), if any. There can be no assurance as to the liquidity of any trading market for the Notes or that an active public market for the Notes will develop. The Private Notes are eligible for trading in the Private Offerings, Resales and Trading through Automatic Linkages (PORTAL) Market. The Company does not intend to apply for listing or quotation of the Notes on any securities exchange or stock market. 24 THE EXCHANGE OFFER PURPOSE OF THE EXCHANGE OFFER The Private Notes were sold by the Company on March 18, 1996 (the "Closing Date") to the Initial Purchasers pursuant to the Purchase Agreement. The Initial Purchasers subsequently sold the Private Notes to (i) "qualified institutional buyers" ("QIBs"), as defined in Rule 144A under the Securities Act ("Rule 144A"), in reliance on Rule 144A and (ii) a limited number of institutional "accredited investors" ("Accredited Institutions"), as defined in Rule 501(a)(1), (2), (3) or (7) under the Securities Act. As a condition to the sale of the Private Notes, the Company and the Initial Purchasers entered into the Registration Rights Agreement on March 18, 1996. Pursuant to the Registration Rights Agreement, the Company agreed that it would (i) file with the Commission a Registration Statement under the Securities Act with respect to the Exchange Notes within 30 days after the Closing Date and (ii) use its best efforts to cause such Registration Statement to become effective under the Securities Act within 90 days after the Closing Date. A copy of the Registration Rights Agreement has been filed as an exhibit to the Registration Statement. The Registration Statement is intended to satisfy certain of the Company's obligations under the Registration Rights Agreement and the Purchase Agreement. RESALE OF THE EXCHANGE NOTES With respect to the Exchange Notes, based upon an interpretation by the staff of the Commission set forth in certain no-action letters issued to third parties, the Company believes that a holder (other than (i) a broker-dealer who purchases such Exchange Notes directly from the Company to resell pursuant to Rule 144A or any other available exemption under the Securities Act or (ii) any such holder that is an "affiliate" of the Company within the meaning of Rule 405 under the Securities Act) who exchanges Private Notes for Exchange Notes in the ordinary course of business and who is not participating, does not intend to participate, and has no arrangement with any person to participate, in a distribution of the Exchange Notes, will be allowed to resell Exchange Notes to the public without further registration under the Securities Act and without delivering to the purchasers of the Exchange Notes a prospectus that satisfies the requirements of Section 10 of the Securities Act. However, if any holder acquires Exchange Notes in the Exchange Offer for the purpose of distributing or participating in the distribution of the Exchange Notes or is a broker-dealer, such holder cannot rely on the position of the staff of the Commission enumerated in certain no-action letters issued to third parties and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction, unless an exemption from registration is otherwise available. Each broker- dealer that receives Exchange Notes for its own account in exchange for Private Notes, where such Private Notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. The Letter of Transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This Prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of Exchange Notes received in exchange for Private Notes where such Private Notes were acquired by such broker-dealer as a result of market-making or other trading activities. Pursuant to the Registration Rights Agreement, the Company has agreed to make this Prospectus, as it may be amended or supplemented from time to time, available to broker-dealers for use in connection with any resale for a period of one year after the date the Registration Statement is declared effective. See "Plan of Distribution." TERMS OF THE EXCHANGE OFFER Upon the terms and subject to the conditions set forth in this Prospectus and in the Letter of Transmittal, the Company will accept any and all Private Notes validly tendered and not withdrawn prior to the Expiration Date. The Company will issue $1,000 principal amount of Exchange Notes in 25 exchange for each $1,000 principal amount of outstanding Private Notes surrendered pursuant to the Exchange Offer. Private Notes may be tendered only in integral multiples of $1,000. The form and terms of the Exchange Notes are the same as the form and terms of the Private Notes except that (i) the Exchange Notes will bear a Series B designation, (ii) the Exchange Notes will have been registered under the Securities Act and, therefore, the Exchange Notes will not bear legends restricting the transfer thereof and (iii) holders of the Exchange Notes will not be entitled to certain rights of holders of the Private Notes under the Registration Rights Agreement, which rights will terminate upon consummation of the Exchange Offer. The Exchange Notes will evidence the same indebtedness as the Private Notes (which they replace) and will be issued under, and be entitled to the benefits of, the Indenture, which also authorized the issuance of the Private Notes, such that both series of Notes will be treated as a single class of debt securities under the Indenture. As of the date of this Prospectus, $110,000,000 in aggregate principal amount of the Private Notes are outstanding and registered in the name of Cede & Co., as nominee for DTC. Only a registered holder of the Private Notes (or such holder's legal representative or attorney-in-fact) as reflected on the records of the Trustee under the Indenture may participate in the Exchange Offer. There will be no fixed record date for determining registered holders of the Private Notes entitled to participate in the Exchange Offer. Holders of the Private Notes do not have any appraisal or dissenters' rights under the Indenture in connection with the Exchange Offer. The Company intends to conduct the Exchange Offer in accordance with the provisions of the Registration Rights Agreement and the applicable requirements of the Securities Act, the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and the rules and regulations of the Commission thereunder. The Company shall be deemed to have accepted validly tendered Private Notes when, as and if the Company has given oral or written notice thereof to the Exchange Agent. The Exchange Agent will act as agent for the tendering holders of Private Notes for the purposes of receiving the Exchange Notes from the Company. Holders who tender Private Notes in the Exchange Offer will not be required to pay brokerage commissions or fees or, subject to the instructions in the Letter of Transmittal, transfer taxes with respect to the exchange of Private Notes pursuant to the Exchange Offer. The Company will pay all charges and expenses, other than certain applicable taxes described below, in connection with the Exchange Offer. See "--Fees and Expenses." EXPIRATION DATE; EXTENSIONS; AMENDMENTS The term "Expiration Date" shall mean 5:00 p.m., New York City time on July 12, 1996, unless the Company, in its sole discretion, extends the Exchange Offer, in which case the term "Expiration Date" shall mean the latest date and time to which the Exchange Offer is extended. In order to extend the Exchange Offer, the Company will (i) notify the Exchange Agent of any extension by oral or written notice, (ii) mail to the registered holders an announcement thereof and (iii) issue a press release or other public announcement which shall include disclosure of the approximate number of Private Notes deposited to date, each prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date. Without limiting the manner in which the Company may choose to make a public announcement of any delay, extension, amendment or termination of the Exchange Offer, the Company shall have no obligation to publish, advertise, or otherwise communicate any such public announcement, other than by making a timely release to an appropriate news agency. 26 The Company reserves the right, in its sole discretion, (i) to delay accepting any Private Notes, (ii) to extend the Exchange Offer or (iii) if any conditions set forth below under "--Conditions" shall not have been satisfied, to terminate the Exchange Offer by giving oral or written notice of such delay, extension or termination to the Exchange Agent. Any such delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders. If the Exchange Offer is amended in a manner determined by the Company to constitute a material change, the Company will promptly disclose such amendment by means of a prospectus supplement that will be distributed to the registered holders of the Private Notes, and the Company will extend the Exchange Offer for a period of five to ten business days, depending upon the significance of the amendment and the manner of disclosure to the registered holders, if the Exchange Offer would otherwise expire during such five to ten business day period. INTEREST ON THE EXCHANGE NOTES The Exchange Notes will bear interest at a rate equal to 10 1/2% per annum. Interest on the Exchange Notes will be payable semiannually in arrears on each April 1 and October 1, commencing October 1, 1996. Holders of Exchange Notes will receive interest on October 1, 1996 from and including the date of initial issuance of the Exchange Notes, plus an amount equal to the accrued interest on the Private Notes from the date of initial delivery to the date of exchange thereof for Exchange Notes. Holders of Private Notes that are accepted for exchange will be deemed to have waived the right to receive any interest accrued on the Private Notes. PROCEDURES FOR TENDERING Only a registered holder of Private Notes may tender such Private Notes in the Exchange Offer. To tender in the Exchange Offer, a holder of Private Notes must complete, sign and date the Letter of Transmittal, or a facsimile thereof, have the signatures thereon guaranteed if required by the Letter of Transmittal, and mail or otherwise deliver such Letter of Transmittal or such facsimile to the Exchange Agent at the address set forth below under "-- Exchange Agent" for receipt prior to the Expiration Date. In addition, either (i) certificates for such Private Notes must be received by the Exchange Agent along with the Letter of Transmittal, (ii) a timely confirmation of a book- entry transfer (a "Book-Entry Confirmation") of such Private Notes, if such procedure is available, into the Exchange Agent's account at the Depositary pursuant to the procedure for book-entry transfer described below, must be received by the Exchange Agent prior to the Expiration Date or (iii) the holder must comply with the guaranteed delivery procedures described below. The tender by a holder that is not withdrawn prior to the Expiration Date will constitute an agreement between such holder and the Company in accordance with the terms and subject to the conditions set forth herein and in the Letter of Transmittal. THE METHOD OF DELIVERY OF PRIVATE NOTES AND THE LETTER OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND RISK OF THE HOLDER. INSTEAD OF DELIVERY BY MAIL, IT IS RECOMMENDED THAT HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE, PROPERLY INSURED. IN ALL CASES, SUFFICIENT TIME SHOULD BE ALLOWED TO ASSURE DELIVERY TO THE EXCHANGE AGENT BEFORE THE EXPIRATION DATE. NO LETTER OF TRANSMITTAL OR PRIVATE NOTES SHOULD BE SENT TO THE COMPANY. HOLDERS MAY REQUEST THEIR RESPECTIVE BROKERS, DEALERS, COMMERCIAL BANKS, TRUST COMPANIES OR NOMINEES TO EFFECT THE ABOVE TRANSACTIONS FOR SUCH HOLDERS. Any beneficial owner(s) of the Private Notes whose Private Notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and who wishes to tender should contact the registered holder promptly and instruct such registered holder to tender on such beneficial 27 owner's behalf. If such beneficial owner wishes to tender on such owner's own behalf, such owner must, prior to completing and executing the Letter of Transmittal and delivering such owner's Private Notes, either make appropriate arrangements to register ownership of the Private Notes in such owner's name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time. Signatures on a Letter of Transmittal or a notice of withdrawal described below (see "--Withdrawal of Tenders"), as the case may be, must be guaranteed by an Eligible Institution (as defined below) unless the Private Notes tendered pursuant thereto are tendered (i) by a registered holder who has not completed the box titled "Special Delivery Instructions" on the Letter of Transmittal or (ii) for the account of an Eligible Institution. In the event that signatures on a Letter of Transmittal or a notice of withdrawal, as the case may be, are required to be guaranteed, such guarantee must be made by a member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., a commercial bank or trust company having an office or correspondent in the United States or an "eligible guarantor institution" within the meaning of Rule 17Ad-15 under the Exchange Act which is a member of one of the recognized signature guarantee programs identified in the Letter of Transmittal (an "Eligible Institution"). If the Letter of Transmittal is signed by a person other than the registered holder of any Private Notes listed therein, such Private Notes must be endorsed or accompanied by a properly completed bond power, signed by such registered holder as such registered holder's name appears on such Private Notes. If the Letter of Transmittal or any Private Notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, such persons should so indicate when signing, and unless waived by the Company, evidence satisfactory to the Company of their authority to so act must be submitted with the Letter of Transmittal. The Exchange Agent and the Depositary have confirmed that any financial institution that is a participant in the Depositary's system may utilize the Depositary's Automated Tender Offer Program to tender Private Notes. All questions as to the validity, form, eligibility (including time of receipt), acceptance and withdrawal of tendered Private Notes will be determined by the Company in its sole discretion, which determination will be final and binding. The Company reserves the absolute right to reject any and all Private Notes not properly tendered or any Private Notes the Company's acceptance of which would, in the opinion of counsel for the Company, be unlawful. The Company also reserves the right to waive any defects, irregularities or conditions of tender as to particular Private Notes. The Company's interpretation of the terms and conditions of the Exchange Offer (including the instructions in the Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of Private Notes must be cured within such time as the Company shall determine. Although the Company intends to notify holders of defects or irregularities with respect to tenders of Private Notes, neither the Company, the Exchange Agent nor any other person shall incur any liability for failure to give such notification. Tenders of Private Notes will not be deemed to have been made until such defects or irregularities have been cured or waived. While the Company has no present plan to acquire any Private Notes that are not tendered in the Exchange Offer or to file a registration statement to permit resales of any Private Notes that are not tendered pursuant to the Exchange Offer, the Company reserves the right in its sole discretion to purchase or make offers for any Private Notes that remain outstanding subsequent to the Expiration Date or, as set forth below under "--Conditions," to terminate the Exchange Offer and, to the extent permitted by applicable law, purchase Private Notes in the open market, in privately negotiated 28 transactions or otherwise. The terms of any such purchases or offers could differ from the terms of the Exchange Offer. By tendering, each holder of Private Notes will represent to the Company that, among other things, (i) Exchange Notes to be acquired by such holder of Private Notes in connection with the Exchange Offer are being acquired by such holder in the ordinary course of business of such holder, (ii) such holder has no arrangement or understanding with any person to participate in the distribution of the Exchange Notes, (iii) such holder acknowledges and agrees that any person who is a broker-dealer registered under the Exchange Act or is participating in the Exchange Offer for the purposes of distributing the Exchange Notes must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction of the Exchange Notes acquired by such person and cannot rely on the position of the staff of the Commission set forth in certain no-action letters, (iv) such holder understands that a secondary resale transaction described in clause (iii) above and any resales of Exchange Notes obtained by such holder in exchange for Private Notes acquired by such holder directly from the Company should be covered by an effective registration statement containing the selling securityholder information required by Item 507 or Item 508, as applicable, of Regulation S-K of the Commission and (v) such holder is not an "affiliate," as defined in Rule 405 under the Securities Act, of the Company. If the holder is a broker-dealer that will receive Exchange Notes for such holder's own account in exchange for Private Notes that were acquired as a result of market-making activities or other trading activities, such holder will be required to acknowledge in the Letter of Transmittal that such holder will deliver a prospectus in connection with any resale of such Exchange Notes; however, by so acknowledging and by delivering a prospectus, such holder will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. RETURN OF PRIVATE NOTES If any tendered Private Notes are not accepted for any reason set forth in the terms and conditions of the Exchange Offer or if Private Notes are withdrawn or are submitted for a greater principal amount than the holders desire to exchange, such unaccepted, withdrawn or non-exchanged Private Notes will be returned without expense to the tendering holder thereof (or, in the case of Private Notes tendered by book-entry transfer into the Exchange Agent's account at the Depositary pursuant to the book-entry transfer procedures described below, such Private Notes will be credited to an account maintained with the Depositary) as promptly as practicable. BOOK-ENTRY TRANSFER The Exchange Agent will make a request to establish an account with respect to the Private Notes at the Depositary for purposes of the Exchange Offer within two business days after the date of this Prospectus, and any financial institution that is a participant in the Depositary's systems may make book- entry delivery of Private Notes by causing the Depositary to transfer such Private Notes into the Exchange Agent's account at the Depositary in accordance with the Depositary's procedures for transfer. However, although delivery of Private Notes may be effected through book-entry transfer at the Depositary, the Letter of Transmittal or facsimile thereof, with any required signature guarantees and any other required documents, must, in any case, be transmitted to and received by the Exchange Agent at the address set forth below under "--Exchange Agent" on or prior to the Expiration Date or pursuant to the guaranteed delivery procedures described below. GUARANTEED DELIVERY PROCEDURES Holders who wish to tender their Private Notes and (i) whose Private Notes are not immediately available or (ii) who cannot deliver their Private Notes, the Letter of Transmittal or any other required documents to the Exchange Agent prior to the Expiration Date, may effect a tender if: 29 (a) The tender is made through an Eligible Institution; (b) Prior to the Expiration Date, the Exchange Agent receives from such Eligible Institution a properly completed and duly executed Notice of Guaranteed Delivery substantially in the form provided by the Company (by facsimile transmission, mail or hand delivery) setting forth the name and address of the holder, the certificate number(s) of such Private Notes and the principal amount of Private Notes tendered, stating that the tender is being made thereby and guaranteeing that, within five New York Stock Exchange trading days after the Expiration Date, the Letter of Transmittal (or a facsimile thereof), together with the certificate(s) representing the Private Notes in proper form for transfer or a Book-Entry Confirmation, as the case may be, and any other documents required by the Letter of Transmittal, will be deposited by the Eligible Institution with the Exchange Agent; and (c) Such properly executed Letter of Transmittal (or facsimile thereof), as well as the certificate(s) representing all tendered Private Notes in proper form for transfer and all other documents required by the Letter of Transmittal are received by the Exchange Agent within five New York Stock Exchange trading days after the Expiration Date. Upon request to the Exchange Agent, a Notice of Guaranteed Delivery will be sent to holders who wish to tender their Private Notes according to the guaranteed delivery procedures set forth above. WITHDRAWAL OF TENDERS Except as otherwise provided herein, tenders of Private Notes may be withdrawn at any time prior to the Expiration Date. To withdraw a tender of Private Notes in the Exchange Offer, a written or facsimile transmission notice of withdrawal must be received by the Exchange Agent at its address set forth herein prior to the Expiration Date. Any such notice of withdrawal must (i) specify the name of the person having deposited the Private Notes to be withdrawn (the "Depositor"), (ii) identify the Private Notes to be withdrawn (including the certificate number or numbers and principal amount of such Private Notes) and (iii) be signed by the holder in the same manner as the original signature on the Letter of Transmittal by which such Private Notes were tendered (including any required signature guarantees). All questions as to the validity, form and eligibility (including time of receipt) of such notices will be determined by the Company in its sole discretion, whose determination shall be final and binding on all parties. Any Private Notes so withdrawn will be deemed not to have been validly tendered for purposes of the Exchange Offer and no Exchange Notes will be issued with respect thereto unless the Private Notes so withdrawn are validly retendered. Properly withdrawn Private Notes may be retendered by following one of the procedures described above under "The Exchange Offer--Procedures for Tendering" at any time prior to the Expiration Date. CONDITIONS Notwithstanding any other term of the Exchange Offer, the Company shall not be required to accept for exchange, or exchange the Exchange Notes for, any Private Notes, and may terminate the Exchange Offer as provided herein before the acceptance of such Private Notes, if the Exchange Offer violates applicable law, rules or regulations or an applicable interpretation of the staff of the Commission. If the Company determines in its sole discretion that any of these conditions are not satisfied, the Company may (i) refuse to accept any Private Notes and return all tendered Private Notes to the tendering holders, (ii) extend the Exchange Offer and retain all Private Notes tendered prior to the expiration of the Exchange Offer, subject, however, to the rights of holders to withdraw such Private Notes (see "--Withdrawal of Tenders") or (iii) waive such unsatisfied conditions with respect to the 30 Exchange Offer and accept all properly tendered Private Notes that have not been withdrawn. If such waiver constitutes a material change to the Exchange Offer, the Company will promptly disclose such waiver by means of a prospectus supplement that will be distributed to the registered holders of the Private Notes, and the Company will extend the Exchange Offer for a period of five to ten business days, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the Exchange Offer would otherwise expire during such five to ten business day period. TERMINATION OF CERTAIN RIGHTS All rights under the Registration Rights Agreement (including registration rights) of holders of the Private Notes eligible to participate in the Exchange Offer will terminate upon consummation of the Exchange Offer except with respect to the Company's continuing obligations (i) to indemnify such holders (including any broker-dealers) and certain parties related to such holders against certain liabilities (including liabilities under the Securities Act), (ii) to provide, upon the request of any holder of a transfer-restricted Private Note, the information required by Rule 144A(d)(4) under the Securities Act in order to permit resales of such Private Notes pursuant to Rule 144A, (iii) to use its best efforts to keep the Registration Statement effective to the extent necessary to ensure that it is available for resales of transfer-restricted Private Notes by broker-dealers for a period of up to one year from the date the Registration Statement is declared effective and (iv) to provide copies of the latest version of the Prospectus to broker- dealers upon their request for a period of up to one year from the date the Registration Statement is declared effective. ADDITIONAL INTEREST In the event of a Registration Default (as defined in the Registration Rights Agreement), the Company is required to pay as liquidated damages, Additional Interest (as defined in the Registration Rights Agreement) to each holder of Transfer Restricted Securities (as defined below), during the first 90-day period immediately following the occurrence of such Registration Default in an amount equal to $0.05 per week per $1,000 principal amount of Private Notes constituting Transfer Restricted Securities held by such holder. Transfer Restricted Securities shall mean each Private Note until (i) the date on which such Private Note has been exchanged for an Exchange Note in the Exchange Offer and is entitled to be resold to the public by the holder thereof without complying with the prospectus delivery requirements of the Securities Act, (ii) the date on which such Private Note has been effectively registered under the Securities Act and disposed of in accordance with the Shelf Registration Statement (as defined in the Registration Rights Agreement) and (iii) the date on which such Private Note is distributed to the public pursuant to Rule 144(k) under the Securities Act or by a broker-dealer pursuant to the "Plan of Distribution" set forth in this Prospectus (including delivery of this Prospectus). The amount of the Additional Interest will increase by an additional $0.05 per week per $1,000 principal amount of Private Notes constituting Transfer Restricted Securities for each subsequent 90-day period until all Registration Defaults have been cured, up to a maximum Additional Interest of $0.50 per week per $1,000 principal amount of Private Notes constituting Transfer Restricted Securities. Following the cure of all Registration Defaults, the payment of Additional Interest will cease. The filing and effectiveness of the Registration Statement of which this Prospectus is a part and the consummation of the Exchange Offer will eliminate all rights of the holders of Private Notes eligible to participate in the Exchange Offer to receive damages that would have been payable if such actions had not occurred. EXCHANGE AGENT Texas Commerce Bank National Association has been appointed as Exchange Agent of the Exchange Offer. Questions and requests for assistance, requests for additional copies of this Prospectus or of the Letter of Transmittal and requests for Notice of Guaranteed Delivery should be directed to the Exchange Agent addressed as follows: 31 By Registered or Certified Mail: By Overnight or Hand Delivery: Texas Commerce Bank National Texas Commerce Bank National Association Association P.O. Box 2320 One Main Place, 19th Floor Dallas, Texas 75221-2320 1201 Main Street Attn: Frank Ivins Dallas, Texas 75201 Attn: Frank Ivins By Facsimile: Confirm by Telephone: (214) 672-5744 (214) 672-5678 FEES AND EXPENSES The expenses of soliciting tenders will be borne by the Company. The principal solicitation is being made by mail; however, additional solicitation may be made by telegraph, telephone or in person by officers and regular employees of the Company and its affiliates. The Company has not retained any dealer-manager in connection with the Exchange Offer and will not make any payments to brokers, dealers or others soliciting acceptances of the Exchange Offer. The Company, however, will pay the Exchange Agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection therewith. The cash expenses to be incurred in connection with the Exchange Offer will be paid by the Company and are estimated in the aggregate to be approximately $70,000. Such expenses include registration fees, fees and expenses of the Exchange Agent and the Trustee, accounting and legal fees and printing costs, among others. The Company will pay all transfer taxes, if any, applicable to the exchange of Private Notes pursuant to the Exchange Offer. If, however, a transfer tax is imposed for any reason other than the exchange of the Private Notes pursuant to the Exchange Offer, then the amount of any such transfer taxes (whether imposed on the registered holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the Letter of Transmittal, the amount of such transfer taxes will be billed directly to such tendering holder. CONSEQUENCES OF NOT EXCHANGING PRIVATE NOTES Participation in the Exchange Offer is voluntary. Holders of the Private Notes are urged to consult their financial and tax advisors in making their own decisions on what action to take. Private Notes that are not exchanged for Exchange Notes pursuant to the Exchange Offer will continue to be deemed restricted securities under the Securities Act and subject to the restrictions on transfer of such Private Notes as set forth in the legend thereon. Accordingly, the Private Notes may not be offered or sold, unless registered under the Securities Act or sold pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Furthermore, any and all registration rights under the Registration Rights Agreement held by holders of Private Notes eligible to participate in the Exchange Offer will be extinguished as a result of the completion of the Exchange Offer. See "Risk Factors--Consequences of Not Exchanging Private Notes." ACCOUNTING TREATMENT For accounting purposes, the Company will recognize no gain or loss as a result of the Exchange Offer. The expenses of the Exchange Offer will be amortized over the term of the Exchange Notes. 32 THE MERGER On October 31, 1995, the Company announced that it had entered into an Agreement and Plan of Merger dated as of October 30, 1995, by and among Coda, JEDI and CAI, whereby JEDI would acquire in the Merger all outstanding shares of common stock, par value $0.02 per share, of Coda (the "Common Stock"). Concurrently with the execution of the Merger Agreement, JEDI and CAI entered into certain agreements with the Management Group providing for a continuing role of management in the Company after the Merger. The per share purchase price for the Common Stock was $7.75 in cash (for an aggregate purchase price of approximately $176.2 million). The Merger was completed on February 16, 1996. JEDI was formed as a limited partnership between CalPERS and an affiliate of ECT, with the ECT affiliate designated as the general partner. The purpose of the partnership is to invest in a diversified portfolio of energy related assets. The Management Group entered into written agreements with JEDI and CAI concerning their employment with and/or equity participation in the Company. The Management Group holds an aggregate of approximately 1.5% of the Company's common stock (approximately 5% on a fully diluted basis, including options granted to such persons). See "Executive Compensation and Other Information." The sources and uses of funds related to financing the Merger were as follows: SOURCES OF FUNDS (in millions) Credit Agreement.................................................. $ 95.0 JEDI Debt(1)...................................................... 100.0 Redeemable Preferred Stock issued to JEDI......................... 20.0 Common Stock issued to JEDI....................................... 90.0 ------ Total......................................................... $305.0 ======
USES OF FUNDS (in millions) Payments to Coda stockholders, warrantholders and optionholders.. $176.2 Repayment of former credit facility and other indebtedness....... 122.7 Merger costs and other expenses.................................. 6.1 ------ Total........................................................ $305.0 ======
-------- (1) Represents indebtedness incurred by CAI and assumed by Coda to fund a portion of the consideration paid in the Merger. See "Use of Proceeds." 33 USE OF PROCEEDS The net proceeds of the sale of the Private Notes were approximately $107.25 million and $100 million of such proceeds were used to repay all of the principal amount of the indebtedness owed to JEDI (the "JEDI Debt") incurred by CAI in connection with the Merger and assumed by the Company upon the Company's merger with CAI. The JEDI Debt bore interest at the rate of U.S. Treasury instruments with a maturity closest to the maturity date of the JEDI Debt plus 6.25% per annum; however, during the first six months, the Company could choose an interest rate option which provided for interest at the rate of LIBOR plus 4.25% per annum. The JEDI Debt had a maturity date of February 16, 2003. See "The Merger" and "Certain Transactions." The remaining net proceeds of approximately $7.25 million, together with available corporate cash of $2.75 million, were used to repay indebtedness outstanding under the Credit Agreement (which had an outstanding balance of approximately $122.0 million at December 31, 1995 and approximately $80.0 million at March 31, 1996). The indebtedness under the Credit Agreement was incurred primarily in connection with acquisitions of producing properties and for other general corporate purposes. After application of such net proceeds of the sale of the Private Notes, approximately $35.0 million is available as of March 31, 1996 for reborrowing under the Credit Agreement to be used for general corporate purposes, which may include acquiring producing oil and natural gas properties or companies owning the same. The Company has no current understandings or agreements in respect of any pending material acquisition. See "Description of Other Indebtedness--Credit Agreement" and "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources." 34 CAPITALIZATION The following table sets forth the unaudited capitalization of the Company as of December 31, 1995, and March 31, 1996 on an historical basis. The following table should be read in conjunction with the Company's Historical Financial Statements, and the other information contained elsewhere in this Prospectus, including the information set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations." For further information regarding the terms of the long-term debt reflected in the following table, see "Description of Other Indebtedness" and the Notes to Historical Financial Statements.
DECEMBER 31, MARCH 31, 1995 1996 ------------ ---------- (in thousands) Current maturities of long-term debt(1)............... $ 453 $ 120 Long-term debt: Former credit facility.............................. 122,000 -- Credit Agreement(1)................................. -- 80,000 12% Senior Subordinated Debentures due 2000(1)...... 988 1,153 10 1/2% Senior Subordinated Notes due 2006.......... -- 110,000 Other(1)............................................ 919 566 ----------- ---------- Total long-term debt.............................. 123,907 191,719 ----------- ---------- 15% Cumulative Redeemable Preferred Stock(2).......... -- -- Additional paid-in capital.......................... -- 20,000 ----------- ---------- Total preferred stock............................. -- 20,000 ----------- ---------- Common stockholders' equity of management, subject to put and call rights: Common stock(3)..................................... -- -- Additional paid-in capital.......................... -- 4,560 Less related notes receivable....................... -- (937) ----------- ---------- Total common stockholders' equity of management... -- 3,623 ----------- ---------- Other common stockholders' equity: Common stock(3)..................................... 442 9 Additional paid-in capital.......................... 68,671 89,991 Retained earnings (deficit)......................... 10,075 (53,136) ----------- ---------- Total other common stockholders' equity........... 79,188 36,864 ----------- ---------- Total capitalization.................................. $ 203,548 $ 252,326 =========== ========== Shares authorized Preferred stock; par value $0.001 historical; par value $0.01 pro forma.............................. 7,500,000 40,000 Common stock; par value $0.02 historical; par value $0.01 pro forma.................................... 40,000,000 1,000,000
- -------- (1) Such indebtedness is senior in right of payment to the Notes. (2) At December 31, 1995, there were no shares of preferred stock (par value $0.001 per share) issued or outstanding. At March 31, 1996, there were 20,000 shares (par value $0.01 per share) issued and outstanding. The 15% Cumulative Redeemable Preferred Stock, par value $0.01 per share (the "Preferred Stock"), was issued to JEDI in connection with the Merger and can be paid cash dividends or redeemed for cash only to the extent permitted by the Indenture and the Credit Agreement. See "Description of Exchange Notes--Certain Covenants--Restricted Payments" and "Description of Capital Stock--Preferred Stock." (3) At December 31, 1995, there were 22,088,903 shares (par value $0.02 per share) of Common Stock issued and outstanding. At March 31, 1996, 913,611 shares (par value $0.01 per share) were issued and outstanding (13,611 shares held by the Management Group and 900,000 shares held by JEDI). The outstanding share numbers exclude 2,416,632 shares and 31,989 shares reserved for issuance at December 31, 1995 and March 31, 1996, respectively, upon exercise of outstanding options and warrants to purchase Common Stock. At December 31, 1995, the Common Stock held by management is included in other common stockholders' equity. See "Certain Transactions--Stockholders Agreement" and "Description of Capital Stock-- Common Stock." 35 SELECTED HISTORICAL AND PRO FORMA FINANCIAL DATA The following table sets forth for the period indicated selected historical and pro forma financial data for the Company. The selected historical financial data as of and for each of the years in the five-year period ended December 31, 1995, have been derived from the historical financial statements of the Company, which were audited by Ernst & Young LLP, independent auditors. The selected historical financial data as of and for the periods ended March 31, 1995, February 16, 1996 and March 31, 1996 have been derived from the unaudited consolidated financial statements of the Company included elsewhere herein. The Company acquired significant producing oil and natural gas properties in all the periods presented which affect the comparability of the historical financial and operating data for the periods presented. As a result of the Merger, JEDI acquired Coda effective February 16, 1996. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired based on estimated fair values. As a result, the Company's financial position and operating results subsequent to the date of the Merger reflect a new basis of accounting and are not comparable to prior periods. The pro forma condensed financial data presented in the table below are derived from the Pro Forma Condensed Financial Statements included elsewhere in this Prospectus. The information below should be read in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations," the Historical Financial Statements of the Company and the notes thereto, as well as the Pro Forma Condensed Financial Statements and the notes thereto included elsewhere in this Prospectus.
HISTORICAL PRO FORMA ----------------------------------------------------------------------------- ------------------------- THREE MONTHS 47 DAYS 44 DAYS YEAR THREE MONTHS YEAR ENDED DECEMBER 31, ENDED ENDED ENDED ENDED ENDED ----------------------------------------- MARCH 31, FEBRUARY 16, MARCH 31, DECEMBER 31, MARCH 31, 1991 1992 1993 1994 1995 1995 1996 1996 1995(1) 1996(1) ------- ------- ------- ------- ------- ------------ ------------ --------- ------------ ------------ (in thousands, except ratios) INCOME STATEMENT DATA: Oil and gas sales........... $16,512 $18,631 $38,877 $50,683 $60,997 $14,948 $8,079 $8,964 $66,156 $17,043 Gas gathering and processing(2)... 5,246 4,709 732 20,081 35,634 7,904 5,322 4,799 35,634 10,121 Total revenues.. 22,782 23,637 40,050 71,586 97,838 23,039 13,569 13,964 102,997 27,533 Interest expense......... 2,420 2,752 4,834 5,281 8,676 2,068 1,102 2,087 18,563 4,300 Total costs and expenses(3)..... 21,865 24,778 36,398 65,676 88,881 20,938 15,378 97,015 110,066 27,816 Income (loss) before income taxes........... 917 (1,141) 3,652 5,910 8,957 2,101 (1,809) (83,051) (7,069) (283) Net income (loss).......... (65) (734) 2,334 3,329 5,755 1,305 (1,298) (53,136) (4,493) (279) Ratio of earnings to fixed charges(4)...... 1.4x -- 1.8x 2.1x 2.0x 2.0x -- -- -- -- CASH FLOW DATA(5): Net income (loss).......... $ (65) $ (734) $ 2,334 $ 3,329 $ 5,755 $ 1,305 $(1,298) $(53,136) $ (4,493) $ (279) Depletion, depreciation and amortization.... 4,823 4,813 10,808 16,419 19,715 4,870 2,583 3,498 28,509 6,897 Net cash provided by operating activities...... 6,127 2,241 16,443 22,987 24,301 5,122 3,136 1,461 17,069 3,487 OTHER DATA(6): EBITDA.......... 8,160 6,424 19,294 27,610 37,348 9,039 1,876 5,839 40,003 10,914 EBITDA/interest expense......... 3.4x 2.3x 4.0x 5.2x 4.3x 4.4x 1.7x 2.8x 2.2x 2.5x Debt/EBITDA..... 3.8x 9.2x 3.2x 3.8x 3.3x CAPITAL EXPENDITURES: Oil and gas property acquisitions.... $21,650 $23,318 $42,223 $40,109 $25,363 $ 498 $ 305 $ 92 Oil and gas development and other........... 4,404 7,550 10,403 12,450 14,464 4,457 1,412 678 Gas plant and gathering systems and other property additions....... 687 1,365 646 7,380 8,500 7,346 114 43
36
AT DECEMBER 31, ------------------------------------------ MARCH 31, 1991 1992 1993 1994 1995 1996 ------- ------- -------- -------- -------- --------- (in thousands) BALANCE SHEET DATA: Total assets............. $56,010 $82,226 $132,754 $203,102 $229,064 $304,435 Notes.................... -- -- -- -- -- 110,000 Other long-term debt, less current maturities.............. 28,794 56,563 59,651 105,063 123,907 81,719 Redeemable Preferred Stock................... -- -- -- -- -- 20,000 Common stockholders' equity.................. 19,502 18,949 58,231 74,741 79,188 40,487
- -------- (1) Reflects the pro forma effect of the Snyder Acquisition, the Merger, the sale of the Private Notes and the application of the proceeds thereof to retire the JEDI Debt and pay down a portion of the outstanding borrowings under the Credit Agreement. See the Company's Pro Forma Condensed Financial Statements, included elsewhere in this Prospectus, for a discussion of the preparation of this data. The pro forma combined results of operations exclude a charge of approximately $53.3 million (net of related deferred taxes of $30.0 million) representing the adjustment of the carrying value of proved oil and gas properties pursuant to the full cost method of accounting. Such adjustment has been included in the historical results of operations of the Company in the period the Merger was consummated. Pro forma net cash provided by operating activities was obtained by adjusting the historical amount for the pro forma changes in oil and natural gas sales, oil and natural gas production expenses, general and administrative expenses and interest expense. The exchange of the Exchange Notes for the Private Notes would have no effect on the pro forma information. See also "Use of Proceeds" and "Capitalization." (2) The Company ceased its third party natural gas marketing operations in 1992. The Company acquired Taurus in April 1994. (3) Total costs and expenses for the periods ended February 16, 1996 and March 31, 1996 include approximately $3.2 million of stock option compensation expense and $83.3 million for the writedown of oil and gas properties, respectively. (4) For purposes of computing the ratio of earnings to fixed charges, earnings consist of income before income taxes plus fixed charges. Fixed charges consist of interest expense. For the periods ended December 31, 1992, February 16, 1996 and March 31, 1996, earnings were inadequate to cover fixed charges by approximately $1.1 million, $1.8 million and $83.1 million, respectively. Pro forma earnings for the year ended December 31, 1995 and three months ended March 31, 1996, would have been inadequate to cover fixed charges by approximately $7.1 million and $283,000, respectively. (5) In addition to cash flows provided by operating activities, the Company also has significant cash flows which are provided by or used in investing and financing activities. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Liquidity and Capital Resources," "--Effects of the Merger, the Sale of the Private Notes and the Exchange Offer--Credit Agreement" and the Historical Financial Statements of the Company. (6) EBITDA is calculated as operating income before interest, income taxes, depletion, depreciation and amortization. EBITDA is not a measure of cash flow as determined by generally accepted accounting principles ("GAAP"). The Company has included information concerning EBITDA because EBITDA is a measure used by certain investors in determining the Company's historical ability to service its indebtedness. EBITDA should not be considered as an alternative to, or more meaningful than, net income or cash flows as determined in accordance with GAAP as an indicator of the Company's operating performance or liquidity. Debt/EBITDA is calculated only for the historical annual periods. EBITDA for the period ended February 16, 1996 is net of approximately $3.2 million of stock option compensation expense which is a non-cash charge. 37 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS GENERAL The Company is an independent energy company principally engaged in the acquisition and exploitation of producing oil and natural gas properties. The Company also owns and operates natural gas processing and liquids extraction facilities and natural gas gathering systems. The Company seeks to acquire properties whose predominant economic value is attributable to proved producing reserves and to enhance that value through control of operations, reduction of costs, and property development. The Company's principal strategy is to increase oil and natural gas reserves, production and cash flow by selectively acquiring and exploiting producing oil and natural gas properties, especially those properties with enhanced recovery and other lower risk development potential. The Company's exploitation efforts include, where appropriate, the drilling of lower risk development wells, the initiation of secondary recovery projects, the renegotiation of marketing agreements and the reduction of drilling, completion and lifting costs. Cost savings may be principally achieved through reductions in field staff and the more effective utilization of field facilities and equipment by virtue of geographic concentration. The success of the Company's strategy is dependent upon a number of factors, some of which are beyond its control. See "Risk Factors." As a result of the Company's successful acquisition and exploitation activities, the Company has shown significant growth in reserves, production and EBITDA over the last five years. From January 1, 1991 to December 31, 1995, the Company completed acquisitions with an aggregate purchase price of $172.2 million and estimated reserves at the date of acquisition of 47.1 Mmboe (treating the acquisition of Diamond for this purpose as a purchase). The Company's producing properties are concentrated onshore in the mid-continent region of the United States. At December 31, 1995, the Company had proved reserves of 42.6 Mmbbls of oil and 37.1 Bcf of natural gas, aggregating 48.8 Mmboe. The Company has two principal operating sources of cash: (i) net oil and natural gas sales from its oil and natural gas properties and (ii) net margins earned from gas gathering and processing operations. The Company expects to continue its efforts to acquire additional oil and natural gas properties. Future acquisitions, if any, would necessitate, in most cases, borrowing additional funds under the Credit Agreement. The ability to borrow such funds is dependent upon the Company's borrowing base under the Credit Agreement. On February 16, 1996, the Company completed the Merger. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired using estimated fair values. As a result, the Company's financial position and operating results subsequent to the date of the Merger reflect a new basis of accounting and are not comparable to prior periods. The immediately following sections, "--Results of Operations" and "--Liquidity and Capital Resources," discuss the Company's historical financial position and operating results. For a discussion of the expected impact of the Merger and the sale of the Private Notes on the Company's financial position and results of operations see "-- Effects of the Merger, the Sale of the Private Notes and the Exchange Offer." 38 RESULTS OF OPERATIONS The following table sets forth certain operating data regarding the production and sales volumes, average sales prices, and costs associated with the Company's oil and natural gas operations and gas gathering and processing operations for the periods indicated on an historical basis.
PRO FORMA THREE COMBINED MONTHS 47 DAYS 44 DAYS THREE MONTHS YEAR ENDED DECEMBER 31, ENDED ENDED ENDED ENDED ----------------------- MARCH 31, FEBRUARY 16, MARCH 31, MARCH 31, 1993 1994 1995 1995 1996 1996 1996 ------- ------- ------- --------- ------------ --------- ------------ OIL AND NATURAL GAS OPERATING DATA: Net production: Oil (Mbbls)............ 1,766 2,650 3,165 772 408 427 835 Natural Gas (Mmcf)..... 4,703 4,982 4,416 1,186 500 512 1,012 Average sales price: Oil (per Bbl).......... $ 16.88 $ 15.86 $ 17.08 $ 17.03 $ 17.57 $ 18.89 $ 18.25 Natural Gas (per Mcf).. 1.92 1.74 1.57 1.52 1.82 1.75 1.78 Production cost per Boe.................... 6.90 6.22 6.95 6.77 7.33 7.59 7.46 GAS GATHERING AND PROCESSING OPERATING DATA: Sales: Total revenue (in thousands)............ $ 732 $20,081 $35,634 $ 7,904 $ 5,322 $ 4,799 $ 10,121 Gas sales (MMBTU, in thousands)......... -- 6,725 13,356 3.079 1,555 1,430 2,985 Gas sales average price................. -- $ 1.82 $ 1.58 $ 1.49 $ 2.24 $ 2.07 $ 2.16 Natural gas liquids sales (M gallons)..... 2,467 26,193 53,284 12,568 5,868 5,487 11,355 Natural gas liquids average price......... $0.2966 $0.2967 $0.2739 $0.2640 $0.3173 $0.3313 $ 0.3241 Costs and expenses (in thousands): Gas purchases.......... 146 15,121 26,547 5,912 3,760 3,390 7,450 Plant operating expenses.............. 424 2,203 3,926 818 506 499 1,005
COMPARISON OF THE THREE MONTHS ENDED MARCH 31, 1995 AND 1996 The unaudited pro forma combined information was prepared as if the Merger and the issuance of $110.0 million of Notes had occurred on January 1, 1995. The unaudited pro forma information was prepared by combining the two 1996 periods and giving effect to adjustments affecting (i) depletion, depreciation and amortization, (ii) interest expense, (iii) income taxes and (iv) certain other costs resulting from the Merger as more fully outlined in the Notes to Pro Forma Condensed Financial Statements contained elsewhere in this Prospectus. The comparisons below compare the unaudited pro forma combined information to historical information for 1995. Oil and natural gas sales for the three months ended March 31, 1996 increased 14% to approximately $17.0 million from approximately $14.9 million in the comparable period in 1995 primarily due to an 8% increase in oil production and an increase of $1.22 per barrel and $0.26 per Mcf in the average sales price of oil and natural gas, respectively. The increase in production is a result of the acquisition of producing oil and natural gas properties in the fourth quarter of 1995, the Company's development drilling program and favorable responses from certain of the Company's waterflood units. This increase was partially offset by a 15% decrease in natural gas production (due primarily to sales of properties). During the three months ended March 31, 1996, 89% of oil and natural gas sales was attributable to oil production. Oil and natural gas prices remain unpredictable. See "--Changes in Prices and Hedging Activities" below. 39 Gas gathering and processing revenues for the three months ended March 31, 1996 increased 28% to approximately $10.1 million from approximately $7.9 million in the comparable period in 1995 primarily due to a 45% and a 23% increase in the average sales price for natural gas and natural gas liquids, respectively. This increase was partially offset by a decrease in natural gas liquids volumes. Gas gathering and processing expenses for the three months ended March 31, 1996 increased 26% to approximately $8.5 million from approximately $6.7 million in the comparable period in 1995 primarily due to an increase in the purchase price paid to producers. Gas gathering and processing expenses usually fluctuate in direct proportion to gas gathering and processing revenues. Oil and natural gas production expenses (including production taxes) for the three months ended March 31, 1996 increased 14% to approximately $7.5 million from approximately $6.6 million for the same period in 1995 reflecting the effects of production from the properties acquired during the fourth quarter of 1995 and from new wells drilled. Oil and natural gas production expenses for the three months ended March 31, 1996 were $7.46 per Boe and are expected to remain near this level for the remainder of the year. Pro forma depletion, depreciation and amortization expense for the three months ended March 31, 1996 increased 42% to approximately $6.9 million from approximately $4.9 million for the historical period in 1995 reflecting the increase in the carrying value of the Company's assets as a result of the Merger and an increase in oil production from acquisitions during the fourth quarter of 1995 and property development. Oil and natural gas depletion, depreciation and amortization expense increased from $4.33 per Boe for the three months ended March 31, 1995, to $5.94 per Boe on a pro forma basis for the three months ended March 31, 1996. The Company anticipates that the depletion, depreciation and amortization rate per Boe will be approximately $5.94 for 1996 absent significant additional acquisitions. General and administrative expenses for the three months ended March 31, 1996 were essentially unchanged from 1995. This is primarily due to increased overhead charges billed to working interest owners on the properties acquired in 1995 being largely offset by additional employees needed as a result of acquisitions of oil and natural gas properties. The Company expects base general and administrative expenses, net of overhead recoveries, to remain near this level, absent significant additional acquisitions. Pro forma interest expense for the three months ended March 31, 1996 increased 108% to approximately $4.3 million from approximately $2.1 million for the historical period in 1995 primarily due to increases in outstanding debt levels as a result of the Merger which reduced the Company's bank debt, but added $110.0 million of subordinated debt bearing interest at 10 1/2% per annum. Also contributing to the increase were amounts borrowed during 1995 to fund development drilling and property acquisitions. The historical results of operations for the period ended February 16, 1996 include approximately $3.2 million of stock option compensation expense as a result of the replacement of certain outstanding options and warrants with new options subject to a lower exercise price. The historical results for the period ended March 31, 1996 includes a writedown of oil and natural gas properties of approximately $83.3 million to the full cost pool ceiling based on product prices at the date of the Merger. The allocation of JEDI's purchase price to the assets and liabilities of Coda resulted in a significant increase in the carrying value of the Company's oil and gas properties. Under the full cost method of accounting, the carrying value of oil and gas properties (net of related deferred taxes) is generally not permitted to exceed the sum of the present value (10% discount rate) of estimated future net cash flows (after tax) from proved reserves, based on current prices and costs, plus the lower of cost or estimated fair value of unproved properties (the "cost center ceiling"). Based upon the allocation of 40 JEDI's purchase price and estimated proved reserves and product prices in effect at the date of the Merger, the purchase price allocated to oil and gas properties was in excess of the cost center ceiling by approximately $83.3 million ($53.3 million net of related deferred taxes). The resulting writedown is a non-cash charge and has been included in the results of operations for the period ended March 31, 1996. The pro forma net loss for the three months ended March 31, 1996 was approximately $279,000 compared to net income of approximately $1.3 million for the historical period in 1995. This decrease resulted primarily from increases in depletion, depreciation and amortization and interest expense as a result of the Merger partially offset by an increase in oil production and higher oil prices. COMPARISON OF THE YEARS ENDED DECEMBER 31, 1994 AND 1995 Oil and natural gas sales for the year ended December 31, 1995 increased 20% to approximately $61.0 million from approximately $50.7 million in 1994 primarily due to a 19% increase in oil production and an increase of $1.22 per barrel in the average sales price for oil. The increase in production was a result of the acquisition of producing oil and natural gas properties during the fourth quarters of 1994 and 1995, the Company's development drilling program and favorable responses from certain of the Company's waterflood units. This increase was partially offset by an 11% decrease in natural gas production (due primarily to sales of properties) and a decrease in the average sales price for natural gas of $0.17 per Mcf. During the year ended December 31, 1995, 89% of oil and natural gas sales was attributable to oil production. Oil and natural gas prices remain unpredictable. See "--Changes in Prices and Hedging Activities." As a result of the acquisition of Taurus on April 29, 1994, gas gathering and processing revenues, expenses and gross profit increased significantly for the year ended December 31, 1995, compared to 1994. The year ended December 31, 1994 only includes eight months of Taurus' operations. Contributing to the increases in revenues and expenses was the acquisition in January 1995 of the remaining ownership interest in one of Taurus' gas plants and associated facilities for $6.5 million. The levels of revenues and expenses attributed to Taurus' operations are largely dependent on natural gas and natural gas liquids prices and plant throughput volumes and, therefore, may fluctuate significantly. Oil and natural gas production expenses (including production taxes) for the year ended December 31, 1995 increased 25% to approximately $27.1 million from approximately $21.6 million for 1994, reflecting the effects of the increased production from the properties acquired in 1994 and from new wells drilled. Oil and natural gas production expenses for the year ended December 31, 1995 were $6.95 per Boe. Absent additional significant acquisitions, the Company expects production expenses to be between $7.00 and $7.50 per Boe in 1996. Depletion, depreciation and amortization expense for the year ended December 31, 1995 increased 20% to approximately $19.7 million from approximately $16.4 million for 1994, reflecting the increase in oil production from acquisitions in 1994, property development and the acquisition of Taurus in April 1994. The increase attributable to Taurus was approximately $1.2 million. Oil and natural gas depletion, depreciation and amortization expense increased to $4.33 per Boe for the year ended December 31, 1995 from $4.27 per Boe for 1994. The increase reflects the relatively higher purchase price of the reserves related to the properties acquired during 1994. General and administrative expenses for the year ended December 31, 1995 decreased to approximately $2.9 million from approximately $3.1 million for 1994. This decrease was primarily due to increased overhead charges billed to working interest owners on the properties acquired during the fourth quarters of 1994 and 1995, being partially offset by additional employees needed as a result of acquisitions of oil and natural gas properties and the acquisition of Taurus. 41 Interest expense for the year ended December 31, 1995 increased 64% to approximately $8.7 million from approximately $5.3 million for 1994, primarily due to increases in outstanding debt levels used to fund development drilling, oil and natural gas property acquisitions and the acquisition of Taurus and related assets, and higher market interest rates in 1995. Business combination expenses of $1.8 million in 1994 were related to the acquisition of Diamond pursuant to a merger. The merger with Diamond was accounted for as a pooling of interests and accordingly the transaction costs were expensed when incurred. Net income for the year ended December 31, 1995 increased to approximately $5.8 million from approximately $3.3 million for 1994, primarily due to (i) an increase in oil production from the Company's waterflood units, the Company's development drilling program and the oil and natural gas property acquisitions during the fourth quarters of 1994 and 1995, (ii) an increase in the average sales price of oil by $1.22 per barrel and (iii) the lack of business combination expenses in 1995. COMPARISON OF THE YEARS ENDED DECEMBER 31, 1993 AND 1994 Oil and natural gas sales for the year ended December 31, 1994 increased 30% to approximately $50.7 million from approximately $38.9 million in 1993 primarily due to an increase in oil and natural gas production of 50% and 6%, respectively, as a result of the acquisition of producing oil and natural gas properties in the third quarter of 1993, the Company's development drilling program and the favorable response of Diamond's waterflood units, partially offset by a decrease in oil prices. During the year ended December 31, 1994, 83% of oil and natural gas sales was attributable to oil production. On April 29, 1994, the Company acquired 100% of the issued and outstanding common stock of Taurus, a privately held Texas corporation, in exchange for 1.5 million shares of the Company's Common Stock, valued at approximately $7.3 million, and approximately $3.3 million cash. The Company assumed existing Taurus debt of approximately $9.8 million. Taurus owns and operates three gas processing and liquids extraction facilities and approximately 700 miles of gas gathering systems located primarily in west central Texas. As a result of this acquisition, gas gathering and processing revenues, expenses and gross profit increased significantly for the year ended December 31, 1994, which reflects eight months of activity for Taurus. In January 1995, Taurus purchased for $6.5 million the remaining interest in one of the plants that it operates. The level of revenues and expenses for Taurus is largely dependent on natural gas and natural gas liquids prices and plant throughput volumes and, therefore, may fluctuate significantly. Other income for the year ended December 31, 1994 increased to approximately $822,000 from approximately $441,000 for 1993, due primarily to the receipt in 1994 of $107,000 of interest income attributable to the receipt in December 1993 of previously suspended oil and natural gas sales proceeds and to the receipt of $117,000 related to the settlement of claims which arose in connection with an unsuccessful acquisition effort in a prior year. Also contributing to the increase was an increase in rental income from the Company's office building. Oil and natural gas production expenses (including production taxes) for the year ended December 31, 1994 increased 23% to approximately $21.6 million from approximately $17.6 million for 1993, reflecting the effects of increased production from the properties acquired in the third quarter of 1993 and from new wells drilled. Oil and natural gas production expenses per Boe decreased in 1994 to $6.22 per Boe from $6.90 per Boe in 1993, reflecting the effect of the relatively lower lifting cost related to the properties acquired in the third quarter of 1993 and the effect of increased production response from the Diamond waterflood units. 42 Depletion, depreciation and amortization expense for the year ended December 31, 1994 increased 52% to approximately $16.4 million from approximately $10.8 million for 1993, reflecting the increases in production from the acquisitions in the third quarter of 1993 and the acquisition of Taurus in April 1994. The increase attributable to Taurus was approximately $1.4 million. Oil and natural gas depletion, depreciation and amortization expense increased from $4.15 per Boe for the year ended December 31, 1993, to $4.27 per Boe for 1994. The increase reflects the relatively higher purchase price of the reserves related to the properties acquired during the third quarter of 1993. General and administrative expenses for the year ended December 31, 1994 increased to approximately $3.1 million from approximately $2.6 million for 1993. This increase was primarily due to additional employees needed as a result of the 1993 acquisitions and the acquisition of Taurus, partially offset by increased overhead charges billed to working interest owners on the properties acquired during 1993. The increase attributable to Taurus was approximately $483,000. Interest expense for the year ended December 31, 1994 increased 10% to approximately $5.3 million from approximately $4.8 million for 1993, primarily as a result of increases in outstanding debt levels used to fund development drilling, property acquisitions and the acquisition of Taurus, partially offset by lower market interest rates in the first half of 1994. In connection with the merger with Diamond, the Company incurred approximately $1.8 million of legal, accounting, printing and other costs related to the combination of the previously separate entities. Included in these expenses is the writeoff of approximately $316,000 of Diamond's deferred financing costs. Under pooling of interests accounting, these costs were expensed in September 1994. Furthermore, certain of these expenses are neither deductible nor amortizable for income tax purposes, resulting in a higher than expected effective tax rate. Net income for the year ended December 31, 1994 increased to approximately $3.3 million from approximately $2.3 million for 1993, primarily due to an increase in oil and natural gas production from Diamond's waterflood units, the Company's development drilling program and the acquisitions in the third quarter of 1993, partially offset by a $1.02 per barrel decrease in average oil prices and $1.8 million in business combination expenses. CHANGES IN PRICES AND HEDGING ACTIVITIES Annual average oil and natural gas prices have fluctuated significantly over the past three years. The Company's weighted average oil price per Bbl during 1995 and at December 31, 1995 was $17.08 and $18.31, respectively. For the three months ended March 31, 1996, the Company averaged $1.33 per barrel less (including an oil hedging price decrease of $0.32 per barrel) and $0.65 per Mcf less for its oil and natural gas sales, respectively, than the average NYMEX prices for the same period. For the year ended December 31, 1995, the Company averaged $1.32 per Bbl less (including an oil hedging price increase of $0.09 per barrel) and $0.13 per Mcf less for its oil and natural gas sales, respectively, than the average NYMEX prices for the same period. The Company's weighted average price per Bbl during 1994 and at December 31, 1994, was $15.86 and $16.24, respectively. For the year ended December 31, 1994, the Company averaged $1.33 per Bbl and $0.20 per Mcf, respectively, less for its oil and natural gas sales than the average NYMEX prices for the same period. Pursuant to the loan agreements with Diamond's former primary lender, Diamond entered into an agreement with a refining and marketing company to sell a fixed number of barrels attributable to its share of production of liquid hydrocarbons from certain formerly secured properties at a price of $15.25 per barrel. The effect of this contract was to lower the Company's 1995 and first quarter of 1996 oil revenue by approximately $1.0 million ($0.32 per barrel) and $123,000 ($0.15 per barrel), respectively. The remaining commitment under this agreement at December 31, 1995, was 47,000 barrels. The Company fulfilled this commitment during the first quarter of 1996. 43 In an effort to reduce the effects of the volatility of the price of oil and natural gas on the Company's operations, management has adopted a policy of hedging oil and natural gas prices through the use of commodity futures, options, and swap agreements whenever market prices are in excess of the prices anticipated in the Company's operating budget and profit plan. While the use of these hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. All hedging is accomplished pursuant to exchange-traded contracts or master swap agreements based upon standard forms. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. Credit risk related to hedging activities, which is minimal, is managed by requiring minimum credit standards for counterparties, periodic settlements and mark-to-market valuations. The Company has not historically been required to provide any significant amount of collateral in connection with its hedging activities. The following table sets forth the barrels and weighted average NYMEX prices hedged under various swap agreements entered into as of March 31, 1996.
WEIGHTED AVERAGE PERIODS COVERED BARRELS SOLD PRICE --------------- ------------ -------- Nine months ending December 31, 1996................ 530,000 $18.81 Year ending December 31, 1997....................... 375,000 $19.02
As of March 31, 1996, the Company had open positions for sold call options covering 25,000 Bbls of oil per month at an option price of $18.30 per Bbl for the period April 1996 to August 1996, increasing to $20.00 per Bbl for the period from September 1996 to August 1997. Under the standard form swap agreements in use by the Company, the Company has a potential liability when the NYMEX price exceeds the swap price. The total potential liability is equal to the difference between the swap price and the NYMEX price for the production month hedged multiplied by the number of barrels swapped. To the extent this total liability exceeds the credit limit established by the counterparty, the Company may be required to utilize cash to fund a margin account. The Company has not historically had to fund a margin account. During the years ended December 31, 1993 and 1994, the Company's oil and natural gas sales were reduced by $289,000 and $5,000, respectively as a result of hedging transactions. During the year ended December 31, 1995, the Company's oil sales were increased by $298,000, representing an average price increase of $0.09 per barrel of oil, as a result of hedging transactions. During the periods ended February 16, 1996 and March 31, 1996, the Company's oil revenues were decreased by $14,000 and $250,000, respectively, as a result of hedging transactions. See Note 7 of the Notes to the Company's Historical Financial Statements for a further discussion of the Company's hedging activities. LIQUIDITY AND CAPITAL RESOURCES At March 31, 1996, the Company had cash and cash equivalents aggregating approximately $3.5 million and working capital of approximately $9.4 million. Cash provided by operating activities for the three months ended March 31, 1996 decreased to approximately $4.6 million compared to $5.1 million for the comparable period in 1995 due primarily to an increase in interest expense partially offset by an increase in oil production and an oil price increase. Excluding the impact of the Merger, cash flows used in investing activities decreased from $11.6 million for the three months ended March 31, 1995 to $2.2 million for the comparable period in 1996, as a result of a higher level of additions to property and equipment in 1995. Investing activities in 1996 also include the impact of the purchase of Coda by JEDI. Cash flows provided by financing activities increased to $176.6 million for the three months ended March 31, 1996 from $3.1 million for the comparable period in 1995, primarily due to financing transactions related to the Merger. See "Effects of the Merger, the Sale of the Private Notes and the Exchange Offer--The Merger" below. 44 At December 31, 1995, the Company had cash and cash equivalents aggregating approximately $4.6 million and working capital of approximately $8.3 million. Cash provided by operating activities for the year ended December 31, 1995 increased to approximately $24.3 million compared to $23.0 million for 1994, due primarily to an increase in oil production and an oil price increase. Cash flows used in investing activities decreased from $56.8 million for the year ended December 31, 1994 to $43.0 million in 1995. This decrease was a result of the sale of assets in 1995 for almost $5.7 million and a slight decrease in the total spending on oil and natural gas properties in 1995, partially offset by the acquisition by Taurus of an additional interest in one of its plants for $6.5 million. Cash flows provided by financing activities decreased to $16.9 million for the year ended December 31, 1995 from $36.2 million for 1994, primarily due to a decrease in net borrowings under the Company's then- existing credit agreement. As a result of the Merger, the Company's financial position and results of operations reflect a new basis of accounting and are not comparable to prior periods. The following section discusses the expected impact of the Merger, the sale of the Private Notes and the Exchange Offer on the Company's financial position and results of operations. EFFECTS OF THE MERGER, THE SALE OF THE PRIVATE NOTES AND THE EXCHANGE OFFER THE MERGER On February 16, 1996, the Company completed the Merger. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired using estimated fair values. As a result, the Company's financial position and operating results subsequent to the date of the Merger reflect a new basis of accounting and are not comparable to prior periods. Concurrently with the execution of the Merger Agreement, JEDI and CAI entered into certain agreements with the Management Group providing for a continuing role of management in the Company after the Merger. The sources and uses of funds related to financing the Merger were as follows: SOURCES OF FUNDS (in millions) Credit Agreement.................................................. $ 95.0 JEDI Debt(1)...................................................... 100.0 Redeemable Preferred Stock issued to JEDI......................... 20.0 Common Stock issued to JEDI....................................... 90.0 ------ Total........................................................... $305.0 ======
USES OF FUNDS (in millions) Payments to Coda stockholders, warrantholders and optionholders.................................................. $176.2 Repayment of former credit facility and other indebtedness...... 122.7 Merger costs and other expenses................................. 6.1 ------ Total......................................................... $305.0 ======
-------- (1) Represents indebtedness incurred by CAI and assumed by Coda to fund a portion of the consideration paid in the Merger. See "Use of Proceeds." The Company incurred substantial indebtedness in connection with the Merger and is highly leveraged. As of March 31, 1996, the Company had total indebtedness of approximately $191.8 million and stockholders' equity (including Preferred Stock) of approximately $60.5 million. After giving pro forma effect to the Merger and the related financing transactions, including the sale of the Private 45 Notes and the Exchange Offer, and the Snyder Acquisition, the Company's earnings would have been insufficient to cover its fixed charges by approximately $7.1 million for 1995. Pro forma interest expense for 1995 would have been approximately $18.6 million. Pro forma cash flow from operations (assuming that the additional interest was paid in cash) would have been approximately $17.1 million. Based upon the Company's current level of operations and anticipated growth, management of the Company believes that available cash, together with available borrowings under the Credit Agreement, will be adequate to meet the Company's budgeted requirements for capital expenditures and scheduled payments of principal of, and interest on, its indebtedness, including the Notes. There can be no assurance that such anticipated growth will be realized, that the Company's business will generate sufficient cash flow from operations or that future borrowings will be available in an amount sufficient to enable the Company to service its indebtedness, including the Notes, or make necessary capital expenditures. In addition, the Company anticipates that it is likely to find it necessary to refinance a portion of the principal amount of the Notes at or prior to their maturity. However, there can be no assurance that the Company will be able to obtain financing to complete a refinancing of the Notes. See "Risk Factors-- Leverage." The Company has planned development and exploitation activities for all of its major operating areas. The Company has budgeted capital spending of approximately $18 million in 1996, but is not contractually committed to expend these funds. During the first three months of 1996, the Company incurred approximately $1.9 million of these costs. In addition, the Company is continuing to evaluate oil and natural gas properties for future acquisitions. Historically, the Company has used the public equity market (i) to raise cash to fund acquisitions or repay indebtedness incurred for acquisitions and (ii) as a medium of exchange for other companies' capital stock or assets in connection with acquisitions. As a result of being 95% owned by JEDI (on a fully diluted basis), the Company does not expect to utilize the public equity market to finance acquisitions in the near term. Accordingly, any material expenditures in connection with acquisitions would require borrowing under the Credit Agreement or from other sources. There can be no assurance that such funds will be available to the Company. Furthermore, the Company's ability to borrow in the future is subject to restrictions imposed by the Credit Agreement and the Indenture as more fully described below. See "Description of Other Indebtedness" and "Description of Exchange Notes--Certain Covenants--Incurrence of Indebtedness and Issuance of Preferred Stock." CREDIT AGREEMENT In connection with the Merger, the Company entered into the Credit Agreement to replace a prior credit facility. The borrowing base under the Credit Agreement currently is $115.0 million. As of March 31, 1996, approximately $35.0 million was available for borrowing under the Credit Agreement. The borrowing base is scheduled to be redetermined on July 1, 1996; however, the Credit Agreement allows the lenders to redetermine the borrowing base upon the occurrence of either of the following events: (i) the sale of all, or substantially all, of the assets or common stock of Taurus or (ii) the issuance of public subordinated debt in an amount greater than $100.0 million. The lenders under the Credit Agreement have agreed to waive their right to redetermine the borrowing base with respect to the issuance of the Notes. As a result of the sale of the Private Notes, ECT Securities Corp., an affiliate of ECT, refunded to the Company $2.0 million in fees paid by the Company to ECT Securities Corp. for arranging the JEDI Debt. These additional funds, together with other available cash of $550,000 and the remaining net proceeds of the sale of the Private Notes were used to repay approximately $10.0 million of the indebtedness outstanding under the Credit Agreement. The Credit Agreement is unsecured. The Company has provided the bank lenders with first lien deeds of trust on its oil and natural gas assets that will not become effective, and that the lenders have agreed to not file, unless: (i) 80% of any outstanding borrowings in excess of the borrowing limit are not repaid within a 90 day period, (ii) cash collateral securing a hedging transaction exceeds 20% of 46 the borrowing limit or (iii) an event of default or a material adverse event, as defined in the Credit Agreement, occurs. The Credit Agreement contains various restrictive covenants, including limitations on the granting of liens, restrictions on the issuance of additional debt, restrictions on investments, a requirement to maintain positive working capital, and restrictions on dividends and stock repurchases. The Credit Agreement also contains requirements that JEDI, Enron, CalPERS or any wholly owned subsidiary of either Enron or CalPERS must continue to own a majority of the outstanding equity of the Company and must have the ability to elect the majority of the Board of Directors and that certain members of management maintain specified levels of equity ownership in the Company and continue their employment with the Company. So long as no default (as defined in the Credit Agreement) is continuing, the Company has the option of having all or any portion of the amount borrowed under the Credit Agreement be the subject of one of the following interest rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base and (iii) LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base. The Company must also pay a commitment fee of between 0.375% to 0.425% on the unused portion of the borrowing base facility. JEDI DEBT The principal amount of JEDI Debt outstanding after the Merger was $100.0 million. A portion of the net proceeds of the sale of the Private Notes was used to repay the JEDI Debt. The Company also paid approximately $823,000 of accrued interest thereon. See "Use of Proceeds." 10 1/2% SENIOR SUBORDINATED NOTES On March 18, 1996, the Company completed the sale of $110 million principal amount of Notes. The proceeds of the Notes were used to fully repay the JEDI Debt assumed in the Merger and to partially repay bank debt. The Notes bear interest at an annual rate of 10 1/2% payable semiannually in arrears on April 1 and October 1 of each year. The Notes are general, unsecured obligations of the Company, are subordinated in right of payment to all Senior Debt (as defined in the Indenture governing the Notes) of Coda, and are senior in right of payment to all future subordinated debt of the Company. The claims of the holders of the Notes will be subordinated to Senior Debt, which, as of March 31, 1996, was $81.8 million. Coda's payment obligations under the Notes are fully, unconditionally and jointly and severally guaranteed on a senior subordinated basis by all of Coda's current subsidiaries and future Restricted Subsidiaries (as defined in the Indenture). Such guarantees are subordinated to the guarantees of Senior Debt issued by the Guarantors under the Credit Agreement and to other guarantees of Senior Debt issued in the future. The Notes were issued pursuant to an Indenture, which contains certain covenants that, among other things, limit the ability of Coda and its Restricted Subsidiaries to incur additional indebtedness and issue Disqualified Stock (as defined in the Indenture), pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing pari passu or subordinated indebtedness of Coda and engage in mergers and consolidations. The Notes are not redeemable at Coda's option prior to April 1, 2001. After April 1, 2001, the Notes will be subject to redemption at the option of Coda, in whole or in part, at the redemption prices set forth in the Indenture, plus accrued and unpaid interest thereon to the applicable redemption date. 47 In addition, until March 12, 1999, up to $27.5 million in aggregate principal amount of Notes is redeemable, at the option of Coda on any one or more occasions from the net proceeds of an offering of common equity of Coda, at a price of 110.5% of the aggregate principal amount of the Notes, together with accrued and unpaid interest thereon to the date of the redemption; provided, however, that at least $82.5 million in aggregate principal amount of Notes must remain outstanding immediately after the occurrence of such redemption; provided, further, that any such redemption shall occur within 75 days of the date of the closing of such offering of common equity. In the event of a Change of Control (as defined in the Indenture), holders of the Notes will have the right to require Coda to repurchase their Notes, in whole or in part, at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the date of repurchase. The Indenture requires that, prior to such a repurchase but in any event within 90 days of such Change of Control, Coda must either repay all Senior Debt or obtain any required consent to such repurchase of Notes. OTHER LONG-TERM DEBT The Company's 12% Senior Subordinated Debentures due 2000 (the "Debentures") bear interest at 12% per annum, payable semiannually. At March 31, 1996, approximately $1.2 million in aggregate principal amount of the Debentures was outstanding. On March 28, 1996, the Company gave notice of redemption, prior to maturity, to each of the record holders of the outstanding Debentures. The outstanding Debentures were redeemed on May 1, 1996 at a redemption price of 100.0% of the principal amount of the Debentures plus accrued and unpaid interest thereon. On May 1, 1996, the Company deposited with the trustee of the Debentures funds sufficient to so redeem the Debentures, and thereafter interest on the Debentures ceased to accrue. 15% CUMULATIVE PREFERRED STOCK The Company's Certificate of Incorporation authorizes the issuance of up to 40,000 shares of Preferred Stock. In conjunction with the Merger, the Company issued 20,000 shares of Preferred Stock to JEDI for $20.0 million in cash. Additional shares of Preferred Stock in excess of 20,000 shares may be issued only for the purpose of paying dividends on the issued and outstanding Preferred Stock. The holders of each share of Preferred Stock are entitled to receive, when and as declared by the Board of Directors, cumulative preferential dividends at the rate of $150.00 per share per annum, payable in equal semi-annual installments. Dividend payments will be made in cash or through the issuance of additional shares of Preferred Stock. The payment of Preferred Stock dividends in cash is restricted by the Credit Agreement and the Indenture. The Company's Certificate of Incorporation requires that the Company redeem all the issued and outstanding shares of Preferred Stock at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption, if the Company has sufficient funds legally available for such redemption and if such redemption would not violate or conflict with any loan agreement, credit agreement, note agreement, indenture or other agreement relating to indebtedness to which the Company is a party, on or before the fifth business day after the earliest to occur of the following: (i) the closing of the sale by the Company of Taurus and (ii) a Trigger Event, as such term is defined in the Stockholders Agreement. The Preferred Stock may be redeemed by the Company at its option, as a whole or in part, to the extent the Company shall have funds legally available for such redemption, at any time or from time to time at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption. Such redemption, whether required or optional, is restricted by the Credit Agreement and the Indenture. 48 ENRON Enron is the parent of ECT and accordingly may be deemed to control indirectly both JEDI and the Company. Enron and certain of its subsidiaries and other affiliates collectively participate in nearly all phases of the oil and natural gas industry and are, therefore, competitors of the Company. In addition, ECT and JEDI have provided, and may in the future provide, and ECT Securities Corp. has assisted, and may in the future assist, in arranging financing to non-affiliated participants in the oil and natural gas industry who are or may become competitors of the Company. Because of these various conflicting interests, ECT, the Company, JEDI and the Management Group have entered into the Business Opportunity Agreement which is intended to make it clear that Enron and its affiliates have no duty to make business opportunities available to the Company in most circumstances. The Business Opportunity Agreement also provides that ECT and its affiliates may pursue certain business opportunities to the exclusion of the Company. The Business Opportunity Agreement may limit the business opportunities available to the Company. In addition, pursuant to the Business Opportunity Agreement there may be circumstances in which the Company will offer business opportunities to certain affiliates of Enron. If an Enron affiliate is offered such an opportunity and decides to pursue it, the Company may be unable to pursue it. RESULTS OF OPERATIONS As a result of the Merger, the Company has significantly more debt outstanding at a higher weighted average interest rate than before the Merger. On a pro forma basis reflecting the effects of the Snyder Acquisition, the Merger and the sale of the Private Notes, as if such transactions had occurred on January 1, 1995, pro forma depletion, depreciation and amortization increased by $8.8 million, pro forma interest expense increased by $9.9 million and pro forma general and administrative expenses decreased by $921,000, compared to the actual amounts reported for 1995. Pro forma EBITDA would have increased to $40.0 million from $37.3 million on a historical basis. Pro forma net loss for 1995 would have been $4.5 million compared to historical net income of $5.8 million. The pro forma combined results of operations exclude a charge of approximately $53.3 million (net of related deferred taxes of $30.0 million) representing the adjustment of the carrying value of proved oil and gas properties pursuant to the full cost method of accounting. Such adjustment has been included in the results of operations of the Company in the period the Merger was consummated. Based on the allocation of purchase price, the Company expects oil and natural gas property depletion, depreciation and amortization to be approximately $5.94 per Bbl in 1996. Absent significant changes in the Company's operations or interest rates, general and administrative expenses are expected to be approximately $3 million in 1996 and interest expense for 1996 should be approximately $17 million. Absent significant increases in prices or increases in production through development or acquisition activities, the Company will continue to incur net losses. In addition, the Company will be incurring a 15% cumulative dividend on $20.0 million of Preferred Stock (payable in cash or shares of Preferred Stock) issued to JEDI in connection with the Merger. See Pro Forma Condensed Financial Statements included elsewhere in this Prospectus. The Company estimates that it has approximately $15.4 million in available net operating loss carryforwards ("NOLs"). While the Merger will result in a change in control pursuant to (S)382 of the Internal Revenue Code, the Company does not expect such change to have any significant impact on its ability to utilize its NOLs. 49 BUSINESS GENERAL The Company is an independent energy company that is principally engaged in the acquisition and exploitation of oil and natural gas properties. The Company also owns and operates natural gas processing and liquids extraction facilities and natural gas gathering systems. The Company seeks to acquire oil and natural gas properties whose predominant economic value is attributable to proved producing reserves and to enhance that value through control of operations, reduction of costs and property development. The Company's producing properties are concentrated in the mid-continent region of the United States. At December 31, 1995, the Company had proved reserves of 42.6 Mmbbls of oil and 37.1 Bcf of natural gas, aggregating 48.8 Mmboe. Company operated properties accounted for approximately 94% of its 1995 production of 3.9 Mmboe. As a result of the Company's successful acquisition and exploitation activities, the Company has shown significant growth in reserves, production and EBITDA over the last five years. From 1991 through 1995, the Company achieved an average annual reserve replacement of 480% at an average cost of $3.67 per Boe (with the acquisition of Diamond treated as a purchase instead of a pooling). To achieve these results, management estimates that the Company evaluated, over the last five years, in excess of 1,400 acquisition opportunities with an aggregate market value estimated by management to exceed $15 billion. Over the same period (with the acquisition of Diamond treated as a purchase instead of a pooling), management estimates that the Company made approximately 280 offers totaling more than $3 billion and successfully closed in excess of 50 transactions having an aggregate purchase price of $172.2 million. This strategy enabled the Company to increase average net daily production from 3,329 Boe in 1991 to 10,688 Boe in 1995, representing a compound annual growth rate of 34%. Similarly, EBITDA increased at a 46% compound annual growth rate from $8.2 million in 1991 to $37.3 million in 1995. STRATEGY The Company's strategy is to increase oil and natural gas reserves, production and cash flow by selectively acquiring and exploiting oil and natural gas properties, especially those properties with enhanced recovery and other lower risk development potential. In order to implement its strategy, the Company principally seeks to acquire oil and natural gas properties with the following characteristics: . Geographic Focus--The Company has focused its acquisition activities in the mid-continent region of the United States. This region includes oil and natural gas basins with geological and production characteristics potentially responsive to the Company's exploitation and development techniques. Management believes that it has considerable experience in, and knowledge of, this region. The Company presently has four core operating areas: west Texas, north Texas, west central Oklahoma and southwestern Kansas. The geographic proximity of the Company's various properties allows the Company to minimize the number of operations and field production offices that it must maintain and the number of supervisory personnel that it must employ. . Proved Developed Reserves--The Company prefers to acquire properties where the majority of the reserves are proved developed reserves producing from relatively shallow horizons. Management believes these properties generally present lower geologic and mechanical risks for drilling, recompleting and operating activities. Substantially all of the Company's wells are under 10,000 feet deep. . Operated, High Working Interest Properties--The Company prefers to operate the properties it acquires and to own the majority working interest in those properties. This allows the Company greater control over (i) timing and plans for future development, (ii) drilling, completing and lifting costs and (iii) marketing of production. At December 31, 1995, the 50 Company operated approximately 2,052 of the 2,190 gross producing and active water injection wells in which it owned an interest, and its weighted average working interest in its properties was approximately 82%. . Exploitation Potential--The Company seeks to increase production and recoverable reserves through exploitation efforts on the properties it acquires. Exploitation efforts include workovers and/or recompletions of existing wells; the initiation of, or improvements to, secondary recovery projects, particularly the use of waterflooding; and the drilling of lower risk development and/or infill wells. The Company believes that it has been able to enhance the value and to extend the economic life of many of the properties that it has acquired by utilizing techniques such as these. . Cost Reduction Potential--The Company seeks to acquire properties where significant economic value can be created by lowering operating costs. The Company believes that it has been able to lower the lifting costs on certain properties it has acquired in comparison to the costs incurred by the major oil companies and larger independents that previously operated the properties. These savings were achieved through reductions in labor, electricity, materials and other costs. . Price Improvement Potential--Whenever possible, the Company attempts to negotiate more favorable marketing agreements than those in place under prior owners. After the Company has begun its exploitation activities on its properties, it may attempt to negotiate more favorable prices as the volumes of oil increase. Certain of the Company's oil purchasers have paid and are currently paying a premium over posted prices and have eliminated certain quality and marketing deductions for a portion of the Company's oil production due to the Company's control over a significant volume of oil production in its core geographic areas. The Company believes that future acquisitions, like its past acquisitions, will come from several categories of sellers including : (i) major oil companies; (ii) companies that are consolidating operations to achieve cost savings; (iii) companies and individuals owning interests in wells in which the Company owns a substantial working interest; and (iv) companies with limited capital resources. The success of the Company's strategy depends upon a number of factors outside of the Company's control, including the availability of attractive acquisition opportunities. In recent years, major oil companies have been divesting many of their higher cost domestic oil and natural gas properties. In addition, the oil and natural gas industry continues to consolidate as smaller independents exit the business. The Company believes these trends will continue. By increasing production and lowering operating costs, the Company believes that it can increase economic value and cash flow as well as extend the productive lives of these properties. See "--Exploitation and Development Activities" and "Risk Factors--Acquisition Risks; Depletion of Reserves." ACQUISITION AND EXPLOITATION OF PRINCIPAL PROPERTIES GENERAL Management estimates that the Company evaluated, over the last five years, in excess of 1,400 acquisition opportunities with an aggregate market value estimated by management to exceed $15 billion. Over the same period (with the acquisition of Diamond treated as a purchase instead of a pooling), management estimates that the Company made approximately 280 offers totaling more than $3 billion and successfully closed in excess of 50 transactions having an aggregate purchase price of $172.2 million. Management estimates that in 1995, the Company evaluated more than $4.5 billion of acquisition opportunities, offered to purchase more than $1.2 billion of such opportunities and closed transactions worth $25.4 million. The Company generally prefers to focus on larger acquisitions. It is management's opinion that operating larger properties will allow even greater cost savings due to economies of scale, as well as higher prices for oil and natural gas due to the concentration of production in a given geographic area. 51 The table below presents the results of the Company's acquisition activities since January 1, 1991, showing the aggregate net purchase price and the estimated proved oil and natural gas reserves purchased (with the acquisition of Diamond treated as a purchase instead of a pooling). The reserve estimates are shown as of the dates of acquisition, were generally derived from the studies prepared by in-house engineers prior to the acquisition, and have not been adjusted for subsequent revisions, if any.
PROVED RESERVES WHEN ACQUIRED AGGREGATE NET --------------------------------- PURCHASE PRICE(1) OIL GAS COMBINED ACQUISITION YEAR ENDED DECEMBER 31, (IN THOUSANDS) (MBBLS) (MMCF) MBOE COST (PER BOE) - ----------------------- ----------------- ---------- --------- ---------- -------------- 1991.................... $16,368 8,100 808 8,235 $1.99 1992.................... 20,546 5,448 2,466 5,859 3.51 1993.................... 36,872 5,521 8,881 7,001 5.27 1994.................... 73,100 15,900 9,123 17,421 4.20 1995.................... 25,363 7,324 7,298 8,540 2.97
- -------- (1) Includes the value attributable to cash and non-cash consideration and reflects credits against the gross purchase price for production from the effective date of the acquisition through the actual closing date. Does not include future development costs. HISTORICAL ACQUISITIONS Since 1991, the Company has been actively engaged in the acquisition of producing oil and natural gas properties located primarily in north Texas, the Permian Basin in west Texas, west central Oklahoma and southwestern Kansas. These acquisitions have permitted the Company to develop concentrated ownership positions in certain producing fields, building on the Company's knowledge of the reservoir characteristics in these areas and enhancing the Company's ability to operate these properties more efficiently than prior owners. 1991 Acquisitions. During 1991, the Company consummated three major purchases in north Texas and the Permian Basin in west Texas, which established those areas as core operating areas for the Company. In March 1991, the Company paid approximately $2.9 million to acquire an existing waterflood project located in the Wichita County Regular Field of the West Burkburnett Area of north Texas. In May 1991, the Company paid approximately $2.7 million to acquire 16 producing wells in the McElroy Field located in Upton County in west Texas. The Company subsequently initiated a waterflood project on this lease. In July 1991, the Company paid $10.5 million to acquire an existing waterflood project and a natural gas processing plant and gathering facility located in Wichita and Wilberger Counties in north Texas (the "Electra Properties"). 1992 Acquisitions. The December 1992 purchase of producing oil and natural gas properties located in the Permian Basin in west Texas and in north Texas furthered the Company's objective of acquiring proved reserves in concentrated geographic locations in which the Company was familiar with the geology and other reservoir characteristics. These properties already were operating on waterflood recovery. In the first of these acquisitions, the Company paid an aggregate of approximately $17.2 million to acquire interests in 13 producing oil and natural gas properties located in the Permian Basin of west Texas and Lea County, New Mexico. One of these properties, the Shafter Lake Unit, is a 12,720 acre San Andres formation waterflood project. In the second acquisition, the Company paid approximately $4.1 million to acquire working interests in an existing waterflood project plus ancillary assets located in Wichita, Wilberger and Hardeman Counties in north Texas. These properties are adjacent to the Company's Electra Properties, which were acquired in 1991. 1993 Acquisitions. In 1993, the Company concluded two significant acquisitions. The first acquisition created the Company's core operating area in southwestern Kansas. These properties were acquired from Mobil Oil Corporation for approximately $15.8 million. The second acquisition, MJM 52 Oil & Gas, Inc. ("MJM"), added properties in the Company's core operating areas of north Texas, the Permian Basin of west Texas and west central Oklahoma. 1994 Acquisitions. The most significant acquisition of oil and natural gas properties during 1994 was the Company's acquisition of Diamond, whose properties are principally concentrated in west central Oklahoma. Substantially all of Diamond's properties are waterflood recovery projects which were initiated and developed by Diamond. This acquisition also brought to the Company additional management with experience in waterflood recovery projects. The Company also completed two acquisitions of properties located in west Texas in December 1994, as well as several other smaller acquisitions. The Company paid an aggregate of $73.1 million in connection with its acquisitions during 1994 (including $21.4 million of the Company's Common Stock issued in connection with the Diamond merger). 1995 Acquisitions. On October 6, 1995, the Company acquired 63 producing oil and natural gas properties and related assets from Snyder. The majority of these properties are located in the Permian Basin in west Texas. The total purchase price of these properties was $17.1 million in cash, of which $16.0 million was financed with borrowings under the Company's then-existing credit agreement. The Company believes that these properties present exploitation opportunities, including opportunities to implement cost-cutting strategies and initiate or improve secondary recovery operations and lower risk development drilling activities. The Snyder Acquisition complements the Company's core operating areas within the mid-continent region of the United States. In addition to the Snyder Acquisition, the Company completed several other smaller acquisitions during 1995. The aggregate purchase price of the Company's acquisitions during 1995 was $25.4 million. The Company does not have a specific acquisition budget since the timing and size of acquisitions are difficult to forecast. The Company is constantly reviewing acquisition possibilities and anticipates acquisitions in 1996 and thereafter. The Company may expand its geographic core areas if it identifies properties that complement its current activities and that it believes will likely be responsive to the Company's exploitation strategy. At the present time, the Company has no binding agreements with respect to any significant acquisitions. EXPLOITATION AND DEVELOPMENT ACTIVITIES GENERAL The Company concentrates on exploiting proved producing properties, including those with development potential, through workovers, behind the pipe recompletions, secondary recovery operations, the drilling of development wells or infill wells and other exploitation techniques. The Company has conducted or intends to conduct significant secondary recovery/infill drilling programs on many of the properties it has acquired. Secondary recovery projects have represented the Company's primary development focus over the past four years. Generally, "secondary recovery" refers to methods of oil extraction in which fluid or gas (usually water, natural gas or CO/2/) is injected into a formation through input (injector) wells, and oil is removed from surrounding wells. "Waterflooding" is one proven method of secondary recovery in which water is injected into an oil reservoir for the purpose of forcing the oil out of the reservoir rock and into the bore of a producing well. Waterflood projects are engineered to suit the type of reservoir, depth and condition of the field. The Company has considerable experience with and actively employs waterflood techniques in many of its fields in order to stimulate production. The Company also seeks to exploit its properties through cost reduction measures, including the reduction of labor, electrical and materials costs. It seeks to take advantage of volume discounts in the purchase of equipment and supplies and more effectively utilize field facilities and equipment by virtue 53 of its geographical concentration. The Company attempts to negotiate more favorable marketing agreements upon completion of an acquisition, particularly for oil production. Certain oil purchasers have paid in the past and are currently paying a premium over posted prices and have eliminated certain quality and marketing deductions for a portion of the Company's oil production due to the Company's control over a significant volume of oil production in its core geographic areas. The Company makes only limited investments in exploratory drilling. EXPLOITATION RESULTS The properties presented in this table represent the ten largest properties in which the Company had an ownership position as of January 1, 1995, based upon the present value of estimated future net revenues at December 31, 1995. These ten properties represent 65% of the present value of estimated future net revenues at December 31, 1995, as estimated by the Company's independent engineers, and are among the Company's most successful projects to date. The present value of estimated future net revenues at December 31, 1995 and the financial data presented provide an indication of the results of the Company's exploitation strategy to date; however, certain of the properties acquired by the Company have not been as successful as those described below and there can be no assurance that the results presented below will be indicative of the Company's future exploitation activities. The present value of future net revenues shown below has been computed on the same basis as the Standardized Measure, but without deducting income taxes, which is not in accordance with generally accepted accounting principles. The amounts cannot be computed on an after tax basis because the tax attributes of the Company's net operating loss carryforwards cannot be allocated to specific properties. The Company believes the present value of future net revenues is an important financial measure for evaluating the relative significance of oil and natural gas properties, but it should not be construed as an alternative to the Standardized Measure.
A B C (A+B+C) D E (D+E) PRESENT VALUE OF ESTIMATED PROPERTY (INITIAL ORIGINAL COST OF FUTURE NET ACQUISITION/ PURCHASE ADDITIONAL CAPITAL NET REVENUES UNITIZATION DATE)(1) PRICE(2) PURCHASES(3) EXPENDITURES(4) TOTAL REVENUES(5) PRETAX(6) TOTAL -------------------- -------- ------------ --------------- ------- ----------- ------------- -------- (in thousands) Andrews Wolfcamp Field (Various)......... $ 7,690 $ 7,565 $ 606 $15,861 $ 6,968 $ 50,406 $ 57,374 Oakdale Red Fork Unit (4/1/91)........... 3,217 8,205 2,269 13,691 5,350 31,925 37,275 Shafter Lake San Andres Unit (10/1/92)... 7,613 836 3,771 12,220 4,210 28,949 33,159 Calumet Cottage Grove Unit (5/1/92)...... 6,855 7,134 2,830 16,819 11,764 23,132 34,896 Chadbourne Ranch (9/30/93)............... 8,252 222 6,002 14,476 8,424 11,662 20,086 McElroy (5/1/91)......................... 2,730 403 2,084 5,217 976 10,013 10,989 S.M.A. Unit "B" (3/1/91)................. 1,760 -- 6,149 7,909 4,832 9,385 14,217 Cutter South Unit (6/1/93)............... 1,343 332 642 2,317 536 6,984 7,520 B.A. Bywaters (7/1/91)................... 1,694 -- 4,154 5,848 2,821 5,931 8,752 L.K. Johnson (9/30/93)................... 2,501 100 1,071 3,672 1,235 4,833 6,068 ------- ------- ------- ------- ------- -------- -------- Totals.................................. $43,655 $24,797 $29,578 $98,030 $47,116 $183,220 $230,336 ======= ======= ======= ======= ======= ======== ========
- -------- (1) Shows the effective date of acquisition by the Company or the date that unitization was approved by the appropriate regulatory agency. (2) Represents the amount of the original purchase price allocated to this property. (3) Represents the amount of the purchase price of additional interests acquired in the property. (4) Represents capital expenditures incurred in the Company's exploitation of each of the indicated properties. (5) Represents the sum of all revenues recorded by the Company on the property since the date of acquisition less the total of all operating expenses (excluding overhead charged by the Company) and severance and other taxes on the property. (6) Represents the present value of estimated future net revenues before income taxes at December 31, 1995, discounted at an annual rate of 10%, as determined by the Company's independent engineers. See "Glossary." 54 Andrews Wolfcamp Field. On January 1, 1993, as part of a larger acquisition, the Company took over operations of three leases in the Andrews Wolfcamp Field. These leases produce primarily from the Wolfcamp and Pennsylvanian formations at an average depth of 9,000 feet and are located in Andrews County, Texas. The Company recognized the waterflood potential of this field and thus began acquiring offset leases. In July 1994, the Company purchased a 100% working interest in three adjacent properties with five active wells. In December 1994, the Company purchased 100% working interests in two additional leases and a 93.8% working interest in a third lease. The Company purchased several additional minor leases in 1995. The Company produced an average of 475 Bbls and 1,196 Mcf per day from 36 wells on these leases in December 1995. The Company has begun the process of unitizing the field and under the proposed plan of participation, the Company will have a 96.4% working interest in the unit. The Company anticipates initiating waterflood activities in the third quarter of 1996. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 7,551 Mbbls and 2,107 Mmcf at December 31, 1995. Oakdale Red Fork Unit. Recognizing that the Oakdale Red Fork Field located in Woods County, Oklahoma was an excellent candidate for secondary recovery, the Company began acquiring leases in 1991. At that time, cumulative production from the field was a total of 4.9 Mmbbls of oil from the Red Fork Formation at an average depth of 5,800 feet. In April 1991, even though a prior attempt by another party to unitize the field had failed, the Company was able to effect unitization and assume operational control of the unit. The unit was producing 30 Bbls per day when the Company installed a waterflood project in 1991. Average daily oil and natural gas production in December 1995 was 1,471 Bbls per day. The Company increased its ownership in the unit to an 89% working interest through acquisitions in December 1994 and February 1995. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 4,246 Mbbls and 659 Mmcf at December 31, 1995. Shafter Lake San Andres Unit. On January 1, 1993, the Company became the operator of the Shafter Lake San Andres Unit in Andrews County, Texas by acquiring a 49% working interest in the unit from the prior operator. At that time, this 12,720 acre unit was producing 743 Bbls per day from the Grayburg/San Andres formation at an average depth of 4,500 feet. The Company has since acquired an additional 14% working interest in this property through eleven different acquisitions. In 1993, the Company expanded an east-west line drive waterflood pattern by converting eight wells to water injection. The Company continued expanding this pattern in 1994 and 1995 by drilling 21 additional producing wells and converting nine existing wells to water injection. In December 1995, average daily production was 1,071 Bbls from 111 producing wells and 36 water injection wells. The Company has identified 58 additional drilling locations. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 4,871 Mbbls and 1,407 Mmcf at December 31, 1995. Calumet Cottage Grove Unit. The Company recognized the secondary recovery potential of this field, located in Canadian County, Oklahoma, in 1991. The Company made approximately 100 separate acquisitions of leases prior to forming the unit. During the unitization of this 11,440 acre unit, the Company solicited approvals from 801 working interest and royalty interest owners. The acquisition and unitization process took over 18 months to complete before the unit was finally formed in May 1992. Average daily oil production increased from 229 Bbls to over 3,300 Bbls within 26 months of initiating water injection and in December 1995 was 2,986 Bbls. Remaining proved reserves, net to the Company's 43.8% working interest, were estimated by the Company's independent engineers to be 2,511 Mbbls at December 31, 1995. Chadbourne Ranch. The Company obtained 14 leases in the West Fort Chadbourne Field located in Coke and Runnels Counties, Texas in September 1993 as part of the acquisition of MJM. The Company has also leased 240 offsetting acres. While there are multiple pay zones in this field, 55 the production is primarily from the Odom formation at a depth of approximately 5,500 feet. The Company has drilled 18 wells in this field. In December 1995, the average daily production was 632 Bbls and 1,670 Mcf from 39 wells. The Company has produced, net to its interest, 559 Mbbls and 1,379 Mmcf since acquisition. The Company has identified four additional drilling locations. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 1,089 Mbbls and 3,151 Mmcf at December 31, 1995. McElroy. On July 1, 1991, the Company acquired a 100% working interest in the Hardwicke University Section 48 lease in Upton County, Texas. The lease is on the eastern flank of the McElroy Field and produces from the Grayburg/San Andres formation from an average depth of 3,600 feet. Cumulative primary production from this 160 acre lease is over 3.0 Mmbbls of primary oil. In October 1992, the Company initiated a waterflood program by drilling six injection wells and one producing well and converting one existing well to injection. In September 1993, the Company acquired a 100% working interest in four offsetting leases totaling 240 acres. Response from the waterflood has not met the initial projections of the Company's engineers and as a result, the expansion of waterflood operations on these leases will not occur until performance on the existing waterflood improves. Average production in the field in December 1995 was 112 Bbls and 143 Mcf per day. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 1,755 Mbbls and 754 Mmcf at December 31, 1995. S.M.A. Unit "B". In March 1991, the Company acquired the S.M.A. Unit "B" along with six smaller leases in the Wichita County Regular Field in Wichita County, Texas. Initially, the Company acquired only an 89% working interest in the S.M.A. Unit "B." Later in 1991, the Company purchased the remaining 11% working interest. At the time of acquisition, there were 37 producing wells and 24 water injection wells producing 165 Bbls per day from an average depth of 1,750 feet. The Company has since implemented a five spot waterflood pattern by drilling 60 producing wells and 46 water injection wells and converting 15 wells to water injection. Average daily production in December 1995 was 475 Bbls from 94 producing wells and 77 water injection wells. The Company has identified 14 additional drilling locations. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 1,597 Mbbls at December 31, 1995. The Company is planning to install a pilot test of an enhanced recovery process on this property in 1996. Cutter South Mississippian Unit. In June 1993, the Company acquired nine leases and assumed operations of 11 producing wells in the Cutter South Field in Stevens County, Kansas. Average daily production was 80 Bbls when the Company took over operation of these leases. Production is from the Chester formation at an average depth of 6,000 feet, which lies below the Hugoton Gas Field. While performing its evaluation prior to acquisition, the Company recognized that these properties could be successfully exploited by secondary recovery. The Company acquired three additional edge leases in this field in 1994 and 1995. On June 1, 1995, the Company was able to complete the unitization of the field. The injection of water into the producing formation began in November 1995. Ultimately, the Company plans to have 14 water injection wells in the unit. The Company's working interest in the unit is 93.5% and average daily production was 82 Bbls in December 1995. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 793 Mbbls and 110 Mmcf at December 31, 1995. B.A. Bywaters. The Company acquired a 100% working interest in the B.A. Bywaters lease on July 1, 1991. This lease is in the Wichita County Special Field in Wichita County, Texas and produces from multiple Pennsylvanian sands ranging from 300 to 2,000 feet. There were 26 wells producing 85 Bbls per day when the Company took over operations in July 1991. The Company has since drilled 33 producing wells and 29 injector wells and converted seven wells to water injection. Production from 55 wells in December 1995 averaged 372 Bbls per day. The Company has identified four additional drilling locations. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 1,101 Mbbls and 104 Mmcf at December 31, 1995. 56 L.K. Johnson. The Company acquired a 50% working interest in, and the operations of, the L.K. Johnson lease in Foard County, Texas as part of the MJM acquisition in September 1993. The Company has since acquired an additional 1.5% working interest in the lease. In September 1993, production from 18 wells averaged 163 Bbls per day from five productive horizons ranging in depth from 2,400 to 4,000 feet. The Company has since drilled eight additional producing wells. A pilot waterflood project began in February 1996 in the Cisco "K" field on this lease. Average daily production was 160 Bbls and 309 Mcf in December 1995. The Company has identified 14 additional drilling locations. Remaining proved reserves, net to the Company's interest, were estimated by the Company's independent engineers to be 763 Mbbls and 1,104 Mmcf at December 31, 1995. MARKETING With the exception of the Taurus operations (see "--Gas Plants and Gathering Systems Operations" below), the Company does not refine or process any of the oil and natural gas it produces. The Company's oil and natural gas production is sold to various purchasers typically in the areas where the oil or natural gas is produced. The Company is currently able to sell, under contract or in the spot market, all of the oil and most of the natural gas it is capable of producing at current market prices. Substantially all of the Company's oil and natural gas is sold under short term contracts or contracts providing for periodic adjustments or in the spot market; therefore, its revenue streams are highly sensitive to changes in current market prices. Certain of the Company's oil purchasers have paid in the past and are currently paying a premium over posted prices and have eliminated certain quality and marketing deductions for a portion of the Company's oil production due to the Company's control over a significant volume of oil production in its core geographic areas. The Company's principal market for natural gas is pipeline companies as opposed to end users. In an effort to reduce the effects of the volatility of the price of crude oil and natural gas on the Company's operations, management has adopted a policy of hedging oil and gas prices whenever market prices are in excess of the prices anticipated in the Company's operating budget and profit plan through the use of commodity futures, options and swap agreements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations--Changes in Prices and Hedging Activities" and Note 7 of Notes to the Company's Historical Financial Statements. During the year ended December 31, 1994, sales of oil and natural gas to Amoco Production Company and EOTT Energy Operating Limited Partnership, a subsidiary of Enron ("EOTT"), accounted for 13% and 22%, respectively, of the Company's consolidated revenues. During the year ended December 31, 1995, sales of oil and natural gas to Amoco Production Company and EOTT accounted for 10% and 18%, respectively, of the Company's consolidated revenues. EOTT is a subsidiary of Enron and an affiliate of the Company, ECT and ECT Securities, Inc. See "Certain Transactions." Management believes that in the event these purchasers were to discontinue their purchases, the Company could quickly locate other buyers and, therefore, the loss of these purchasers would not have a material impact on the Company's financial condition or results of operations. However, short term disruptions could occur while the Company sought alternative buyers. OIL AND NATURAL GAS RESERVES The following tables summarize certain information regarding the Company's estimated proved oil and natural gas reserves as of December 31, 1993, 1994 and 1995. Such estimated reserves, as set forth herein and in Note 10 of Notes to Consolidated Financial Statements, are based upon reports prepared by Lee Keeling and Associates, Inc., independent consulting petroleum engineers. A summary of the December 31, 1995 report is included in this Prospectus as Annex A. Reserve estimates as of December 31, 1993 for Diamond were prepared by Diamond's in-house engineers. All such reserves are located in the United States. All reserves are evaluated at contract temperature and pressure which can affect the measurement of natural gas reserves. For further information, see Note 57 10 of Notes to Consolidated Financial Statements. Reserve estimates are inherently imprecise and there can be no assurance that the reserves set forth below will ultimately be produced at all or at the prices and costs assumed in the estimates of future net revenues. See "Risk Factors--Reliance on Estimates of Proved Reserves and Future Net Revenues" and "Experts." The following table sets forth proved reserves considered to be economically recoverable under normal operating methods and existing conditions, at prices and operating costs prevailing at the dates indicated below.
DECEMBER 31, ----------------------------------------- 1993 1994 1995 ------------- ------------- ------------- (in thousands) OIL GAS OIL GAS OIL GAS (BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF) ------ ------ ------ ------ ------ ------ Proved developed reserves............ 16,230 30,573 20,151 32,890 25,877 31,496 Proved undeveloped reserves.......... 13,854 5,623 19,056 6,918 16,713 5,634 ------ ------ ------ ------ ------ ------ Total proved reserves.............. 30,084 36,196 39,207 39,808 42,590 37,130 ====== ====== ====== ====== ====== ======
No major discovery or other favorable or adverse event is believed to have caused a significant change in these estimates of the Company's proved reserves since January 1, 1996. Except for Form EIA 23, "Annual Survey of Domestic Oil and Gas Reserves," filed with the United States Department of Energy, no other estimates of total proven net oil or gas reserves have been filed by the Company with, or included in any report to, any United States authority or agency pertaining to the Company's individual reserves since the beginning of the Company's last fiscal year. Reserves reported in Form EIA 23 are comparable to the reserves reported by the Company herein. OPERATIONS DATA Productive Wells. The following table sets forth the total gross and net productive wells in which the Company owned an interest as of December 31, 1995. Substantially all of the Company's wells are under 10,000 feet deep.
GROSS (1) NET (1) ---------- ---------- OIL(2) GAS OIL(2) GAS ------ --- ------ --- Texas................................................ 1,802 16 1,561 8 Oklahoma............................................. 258 27 145 8 Kansas............................................... 76 5 67 4 Other................................................ 6 -- 1 -- ----- --- ----- --- Total.............................................. 2,142 48 1,774 20 ===== === ===== ===
-------- (1) The number of gross wells is the total number of wells in which a fractional working interest is owned. The number of net wells is the sum of the fractional working interests owned by the Company in gross wells. (2) The oil well category includes 615 gross and 524 net active water injection and utility wells which are necessary for the operation of the Company's waterflood projects. Production Economics. The following table shows the approximate net production attributable to the Company's oil and natural gas interests, the average sales price and the average production and depletion, depreciation and amortization expenses per Bbl of oil and Mcf of natural gas attributable to the Company's oil and natural gas production for the periods indicated. Production and sales information relating to properties acquired or disposed of is reflected in this table only since or up to the closing date of their respective acquisition or sale and may affect the comparability of the data between the periods presented. 58
YEARS ENDED DECEMBER 31, -------------------------- 1993 1994 1995 -------- -------- -------- OIL AND NATURAL GAS PRODUCTION Oil (Mbbls)...................................... 1,766 2,650 3,165 Natural gas (Mmcf)............................... 4,703 4,982 4,416 AVERAGE SALES PRICES (1) Oil (Bbl)........................................ $16.88 $15.86 $17.08 Natural gas (Mcf)................................ 1.92 1.74 1.57 PRODUCTION COST (2) Per equivalent Bbl (3)........................... $6.90 $6.22 $6.95 Per dollar of sales.............................. 0.45 0.43 0.44 DEPLETION, DEPRECIATION AND AMORTIZATION Per equivalent Bbl (3)........................... $4.15 $4.27 $4.33 Per dollar of sales.............................. 0.27 0.29 0.28
-------- (1) Before deduction of production taxes and net of hedging results for the three years ended December 31, 1995. (2) Excludes depletion, depreciation and amortization. Production cost includes lease operating expenses and production and ad valorem taxes, if applicable. (3) Natural gas production is converted to equivalent barrels of oil at the rate of six Mcf of natural gas per barrel, representing the estimated relative energy content of natural gas and oil. The following table sets forth the results of the Company's annual drilling activities (wells completed or abandoned) as of fiscal year end. During the four months ended April 30, 1996, the Company drilled eight wells. At April 30, 1996, the Company was in the process of drilling one well.
1993 1994 1995 --------------- --------------- --------------- GROSS(1) NET(1) GROSS(1) NET(1) GROSS(1) NET(1) -------- ------ -------- ------ -------- ------ EXPLORATORY: Oil........................ -- -- -- -- -- -- Gas........................ -- -- 1 0.38 2 0.75 Dry........................ -- -- -- -- -- -- --- ----- --- ----- --- ----- Total.................... -- -- 1 0.38 2 0.75 === ===== === ===== === ===== DEVELOPMENT: Oil........................ 57 55.09 86 66.68 109 98.88 Gas........................ -- -- -- -- -- -- Dry........................ -- -- 1 0.50 -- -- --- ----- --- ----- --- ----- Total.................... 57 55.09 87 67.18 109 98.88 === ===== === ===== === ===== TOTAL: Oil........................ 57 55.09 86 66.68 109 98.88 Gas........................ -- -- 1 0.38 2 0.75 Dry........................ -- -- 1 0.50 -- -- --- ----- --- ----- --- ----- Total.................... 57 55.09 88 67.56 111 99.63 === ===== === ===== === =====
-------- (1) The number of gross wells is the total number of wells in which the Company owns a fractional working interest. The number of net wells is the sum of the fractional working interests owned by the Company in gross wells. For purposes of the table above, an "exploratory well" is a well drilled to find and produce oil or natural gas in an unproved area, to find a reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir. A "development well" is a well drilled within the proven boundaries of an oil or natural gas reservoir with the intention of completing the 59 stratigraphic horizon known to be productive. A "dry well" is an exploratory or development well found to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or natural gas well. DEVELOPED AND UNDEVELOPED ACREAGE The following table sets forth the approximate gross acres and net acres of productive properties in which the Company owned a leasehold interest as of December 31, 1995. Gross acres refers to the total acres in which the Company has a working interest, and net acres refers to the fractional working interests owned by or attributable to the Company multiplied by the gross acres in which the Company has a working interest. Developed acreage is that acreage spaced or assignable to productive wells. Undeveloped acreage is considered to be that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves. At December 31, 1995, the Company had no significant amount of undeveloped acreage.
DEVELOPED -------------- GROSS NET ------- ------ Texas....................................................... 93,615 51,998 Oklahoma.................................................... 49,585 24,559 Kansas...................................................... 16,199 13,856 Other....................................................... 5,341 1,817 ------- ------ Total..................................................... 164,740 92,230 ======= ======
Essentially all of the Company's oil and gas interests are leasehold working interests or overriding royalty interests under standard onshore oil and natural gas leases, rather than mineral or fee interests. GAS PLANTS AND GATHERING SYSTEM OPERATIONS On April 29, 1994, the Company acquired by merger all of the issued and outstanding common stock of Taurus, in exchange for 1.5 million shares of Coda's Common Stock, valued at approximately $7.3 million, and approximately $3.3 million in cash. The Company assumed existing Taurus indebtedness of approximately $9.8 million. Taurus owns and operates three natural gas processing facilities and approximately 700 miles of natural gas gathering systems, primarily located in west central Texas. Taurus represented approximately nine percent of the Company's consolidated 1995 EBITDA of approximately $37.3 million. In July 1994, Taurus acquired ownership of the Shackelford gas processing plant and gathering system ("Shackelford"). Taurus had previously been operating the Shackelford system and plant under operating leases. Shackelford consists of approximately 250 miles of pipeline located in Shackelford, Callahan, Stephens and Throckmorton Counties, Texas. The plant is a 30,000 Mcf per day capacity refrigerated lean oil absorption plant located near Putnam, Texas. The steel gathering lines range in size from 3 inches to 10 inches in diameter. There are over 100 purchase, check and sales meters. The system utilizes 20 compressors with over 4,500 total horsepower. In January 1995, Taurus acquired the remaining 42% interest in the Hamlin gas processing plant and gathering system ("Hamlin"). The Hamlin gathering system consists of about 450 miles of low pressure gathering lines and twelve compressor stations in Fisher, Cottle, Taylor, Stonewall, Jones, Haskell, King and Knox Counties, Texas. The Hamlin plant utilizes a cryogenic process and has a processing capacity of 20,000 Mcf per day. Gas supply to the system consists almost entirely of high BTU casinghead gas. The Hamlin plant produces a demethanized stream which is delivered into a products pipeline. 60 The following table shows certain financial data in respect of the Company's gas gathering and processing operations, including Taurus, for the three years ended December 31, 1995.
1993 1994 1995 ------ ------- ------- (IN THOUSANDS) Gas sales.......................................... $ -- $12,261 $21,038 Natural gas liquids sales.......................... 732 7,771 14,597 Operating margin................................... 162 2,724 5,161 EBITDA............................................. 7 2,073 3,354 Total assets....................................... 1,157 32,577 38,040
The Merger Agreement originally required as a condition to JEDI's consummation of the Merger that the Company sell Taurus on terms acceptable to JEDI. However, negotiations with prospective purchasers for Taurus failed to progress beyond preliminary stages and by December 1995, the Company's management and JEDI had concluded a timely sale of Taurus upon terms satisfactory to JEDI was not feasible or likely. Subsequently, the Merger Agreement was amended to remove this condition. The Company intends to study alternatives for maximizing the value of its investment in Taurus. These alternatives could include a sale of Taurus, whether by merger, sale of all or substantially all of the assets of Taurus or sale of all of the capital stock of Taurus. Sales and markets. Taurus' two largest plants and gathering systems, Shackelford and Hamlin, account for the majority of Taurus' revenue. Taurus sells its residue gas from Shackelford to a variety of large natural gas purchasers under short-term contracts at market sensitive prices. Residue gas from Shackelford can be delivered into either one of two major pipeline systems. These connections provide significant marketing flexibility by giving access to major marketing hubs in east Texas, west Texas and the Gulf Coast. Major natural gas consuming markets in California, the Midwest, the Northeast and along the Texas Gulf Coast can be accessed through these market hubs. Generally, residue gas is sold under short-term contracts either at the tailgate of the Shackelford Plant or out of the intrastate pipeline. The Shackelford Plant produces a demethanized stream which is delivered into a products pipeline. Ethane, normal butane and natural gasoline components of the product stream are generally sold as they enter the pipeline. The remaining components of the product stream are then sold under short term agreements to various customers at a central marketing point in Mont Belvieu, Texas. A transportation and fractionation fee is paid on all gallons not sold to the pipeline owner. Residue gas from Hamlin can be delivered into either the Palo Duro Pipeline or the Lone Star Gas pipeline. These connections afford Taurus the opportunity to offer residue gas from both Hamlin and Shackelford as a package which increases the marketing flexibility and leverage of both plants. Since assuming operation of Hamlin, Taurus has sold all residue gas under short term contracts at market sensitive prices to a variety of large purchasers. The Hamlin Plant produces a demethanized stream which is delivered into a products pipeline. All of Hamlin's liquids production is being sold under agreements that provide for market index prices less a transportation and fractionation fee. Purchases. Taurus purchases gas for Shackelford from approximately 250 wells in Shackelford, Callahan, Stephens and Throckmorton Counties, Texas. The majority of the production connected to the gathering system is low volume casinghead gas. The system is operated at low pressure with lateral line pressures ranging from 15 to 150 psi. The mainline pressure averages about 300 psi. 61 Taurus utilizes two base forms of gas purchase agreements: percentage of proceeds and fixed price. Percentage contracts provide that the seller is allocated its proportionate share of residue gas sales and natural gas liquids production. Fixed price contracts, which generally provide for acreage dedications, are for primary terms of up to 20 years with annual renewals thereafter. The purchase price to be paid is stated in the contract and is subject to annual price redetermination if certain specific conditions are met. The natural gas connected to Shackelford is purchased under both percentage and fixed price contracts. The majority of the natural gas connected to Hamlin is being purchased utilizing percentage of proceeds contracts. There are about 200 natural gas purchase agreements covering over 450 wells connected to Hamlin. Less than two percent of Taurus' purchases are from the Company's wells. MARKETS AND COMPETITION The oil and natural gas industry is highly competitive. Competitors include major oil companies, other independent oil and natural gas concerns, and individual producers and operators, many of which have financial resources, staffs and facilities substantially greater than those of the Company. In addition, the Company encounters substantial competition in acquiring oil and natural gas properties, marketing oil and natural gas and securing trained personnel. When possible, the Company tries to avoid open competitive bidding for acquisition opportunities. The principal means of competition with respect to the sale of oil and natural gas production are product availability and price. While it is not possible for the Company to state accurately its position in the oil and natural gas industry, the Company believes that it represents a minor competitive factor. The market for oil, natural gas and natural gas liquids produced by the Company depends on factors beyond its control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, natural gas and natural gas liquids, the price of imports of oil and natural gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. The oil and natural gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. REGULATION The Company's operations are affected in various degrees by political developments, federal and state laws and regulations. In particular, oil and natural gas production operations and economics are affected by price controls, tax and other laws relating to the petroleum industry, by changes in such laws and by changes in administrative regulations and the interpretation and application of such rules and regulations. Sales of oil and natural gas liquids by the Company are not regulated and are made at market prices. The price the Company receives from the sale of these products is affected by the cost of transporting the products to market. Effective as of January 1, 1995, the Federal Energy Regulatory Commission implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rates to inflation, subject to certain conditions and limitations. These regulations could increase the cost of transporting oil and natural gas liquids by pipeline, although the most recent adjustment generally decreased rates. These regulations are subject to pending petitions for judicial review. The Company is not able to predict with certainty what effect, if any, these regulations will have on it, but, other factors being equal, the regulations may, over time, tend to increase transportation costs or reduce wellhead prices for oil and natural gas liquids. 62 ENVIRONMENTAL MATTERS Operations of the Company are subject to numerous and constantly changing federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production, restrict or prohibit drilling activities that could impact wetlands, endangered or threatened species or other protected natural resources and impose substantial liabilities for pollution resulting from the Company's operations. Such laws and regulations may substantially increase the cost of exploring for, developing or producing oil and natural gas and may prevent or delay the commencement or continuation of a given project. In the opinion of the Company's management, the Company is in substantial compliance with current applicable environmental laws and regulations, and the cost of compliance with such laws and regulations has not been material and is not expected to be material during the next fiscal year. However, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on the operating costs of the Company, as well as the oil and natural gas industry in general. For instance, legislation has been proposed in Congress from time to time that would reclassify certain oil and natural gas production wastes as "hazardous wastes," which reclassification would make exploration and production wastes subject to much more stringent handling, disposal and clean-up requirements. State initiatives to further regulate the disposal of oil and natural gas wastes and naturally occurring radioactive materials are also pending in certain states, including Texas, and these various initiatives could have a similar impact on the Company. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Company is able to control directly the operation of only those wells with respect to which it acts as operator. Notwithstanding the Company's lack of control over wells operated by others, the failure of the operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to the Company. The Company has no material commitments for capital expenditures to comply with existing environmental requirements. EMPLOYEES As of March 31, 1996, the Company's staff consisted of 156 full-time employees, of whom 67 were administrative personnel, 60 were field and service- related personnel, and 29 were personnel whose duties related to Taurus. The Company also engages independent consulting petroleum engineers, environmental professionals, geologists, landmen, accountants and attorneys on a fee basis. LEGAL PROCEEDINGS The Company is a defendant or codefendant in minor lawsuits that have arisen in the ordinary course of business. The Company does not expect any of these to have a material adverse effect on the Company's consolidated financial position. 63 MANAGEMENT The executive officers and directors of the Company following completion of the Merger are listed below, together with a description of their experience and certain other information. Each of the directors serve for a one year term. Executive officers are appointed by the Board of Directors. The Company's Bylaws provide that the Chairman of the Board and the Vice Chairman of the Board (or the President if there is no Vice Chairman) shall be directors of the Company.
NAME AGE OFFICE SINCE POSITION WITH COMPANY ---- --- ------------ ------------------------------- Douglas H. Miller.............. 48 1989 Chairman of the Board and Chief Executive Officer Jarl P. Johnson................ 66 1994 President of Diamond, Vice Chairman of the Board and Chief Operating Officer Grant W. Henderson............. 37 1993 President, Chief Financial Officer and Director J. William Freeman............. 55 1990 Vice President--Engineering J.W. Spencer, III.............. 45 1991 Vice President--Operations Randell A. Bodenhamer.......... 41 1995 Vice President--Land Richard A. Causey.............. 36 1995 Director James V. Derrick, Jr........... 51 1995 Director Gene E. Humphrey............... 49 1995 Director C. John Thompson............... 43 1995 Director
Douglas H. Miller was elected Chairman of the Board and Chief Executive Officer of the Company in October 1989 and has served as a director of Coda since 1987. Beginning in 1983, Mr. Miller also served as president of a securities broker/dealer which Mr. Miller sold in 1993. Jarl P. Johnson has been active in the oil and natural gas industry since 1953. Mr. Johnson worked for Phillips Petroleum from 1953 to 1955, and for Kewanee Oil Co. from 1955 to 1978 where he served as Manager of Engineering for 14 years. He worked for Hamilton Brothers Oil Company from 1978 to 1980 as Vice President of Engineering. From 1980 to 1986 he was Vice President of Operations for Ensource Inc. Mr. Johnson formed his own company, PetroJarl, Inc., in 1986 to own non-operated oil and gas interests. He became President and a director of Diamond in October 1989. Mr. Johnson joined the Company as Vice Chairman of the Company in 1994 in connection with the Company's acquisition of Diamond and became Chief Operating Officer of the Company upon consummation of the Merger. Grant W. Henderson joined the Company in October 1993 as Executive Vice President and Chief Financial Officer of the Company. He was elected a director of Coda in 1995 and became President of the Company upon consummation of the Merger. Mr. Henderson also will continue to serve as Chief Financial Officer of the Company. Mr. Henderson was previously employed by NationsBank, beginning 1981, last serving as a Senior Vice President in its Energy Banking Group. J. William Freeman is a registered Professional Engineer in the State of Texas and joined the Company in 1990 as its senior reservoir and economics engineer. Mr. Freeman has worked in the oil and natural gas industry for 27 years, principally in the area of acquisitions of oil and natural gas properties. Prior to 1985 Mr. Freeman was employed by Gulf Oil Corporation. From 1985 to November 1989 he worked as an independent oil and gas engineer. 64 J.W. Spencer, III has been involved in production and reservoir engineering since 1973. From 1985 until March 1991, when he joined the Company as Vice President--Operations of the Company, he was manager of production operations for Conquest Exploration Company. Prior to 1985, Mr. Spencer was employed as an engineer by Gulf Oil Corporation. Randell A. Bodenhamer joined the Company in 1994 as Executive Vice President of Diamond in conjunction with the Company's acquisition of Diamond. Mr. Bodenhamer was appointed Vice President--Land of the Company in August 1995. Prior to joining Diamond as an employee, Mr. Bodenhamer was owner of R.A. Bodenhamer & Associates, Inc., a Tulsa-based land service company. From 1986 through 1994, Mr. Bodenhamer worked primarily for Diamond acquiring and unitizing waterflood projects on its behalf. Richard A. Causey currently is a Vice President of ECT and is responsible for the treasury activities of ECT. He has been associated with ECT since 1991. James V. Derrick, Jr. is Senior Vice President and General Counsel of Enron. He serves on the Management Committee of Enron and is a director of Enron Global Power & Pipelines LLC, a New York Stock Exchange-listed entity that owns interests in certain international pipeline and power projects. He has been associated with Enron since 1991. Gene E. Humphrey has been with ECT since its inception in 1990, most recently serving as Managing Director. Previously, he was a Vice President in Citibank's Petroleum Department where he specialized in financial and investment banking services for the oil and natural gas industry. C. John Thompson has been employed by ECT since its inception in 1990, serving as Vice President of the Domestic Corporate Finance Group. Previously, he was a Partner with James C. Cooper, Inc., an investment banking firm based in Houston, Texas. 65 SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The following table sets forth the name and address of the only stockholder of the Company who is known by the Company to beneficially own more than five percent of the Company's outstanding common stock, the number of shares beneficially owned by such stockholder, and the percentage of outstanding common stock so owned, as of May 1, 1996. As of May 1, 1996, there were 913,611 shares of common stock outstanding.
AMOUNT AND NAME AND ADDRESS NATURE OF PERCENT OF TITLE OF CLASS OF BENEFICIAL OWNER BENEFICIAL OWNERSHIP CLASS -------------- -------------------------------- -------------------- ---------- Common Joint Energy Development 900,000 98.5 Stock Investments Limited Partnership 1400 Smith Street Houston, Texas 77002
The table appearing below sets forth information as of May 1, 1996 with respect to shares of common stock beneficially owned by each of the Company's directors, the Company's Chief Executive Officer and the four other most highly compensated executive officers for 1995, and all directors and executive officers as a group, and the percent of the outstanding common stock so owned by each.
AMOUNT AND NATURE OF BENEFICIAL PERCENT OF TITLE OF CLASS DIRECTORS AND NAMED EXECUTIVE OFFICERS OWNERSHIP (1) CLASS -------------- -------------------------------------- ------------- ---------- Common Stock Richard A. Causey..................... -- -- Common Stock James V. Derrick, Jr.................. -- -- Common Stock T. W. Eubank (2)...................... -- -- Common Stock Grant W. Henderson.................... 4,750(4) (8) Common Stock Gene E. Humphrey...................... -- -- Common Stock Jarl P. Johnson....................... 3,800(5) (8) Common Stock Tommie E. Lohman(3)................... -- -- Common Stock Douglas H. Miller..................... 23,750(6) 2.5 Common Stock C. John Thompson...................... -- -- Common Stock All directors and executive officers as a group (12 persons)......................... 39,425(7) 4.2
- -------- (1) Unless otherwise indicated, all shares are owned directly by the named person and such person has sole voting and investment power with respect to such shares. (2) Mr. Eubank retired from the Company in February 1996. (3) Mr. Lohman retired from Taurus in April 1996. (4) Includes options to purchase 2,375 shares exercisable within 60 days. (5) Includes options to purchase 1,185 shares exercisable within 60 days. (6) Includes options to purchase 23,750 shares exercisable within 60 days. (7) Includes all options referenced in notes (3) through (5) above; 4,708 shares held directly by other executive officers of the Company and options to purchase 2,417 shares exercisable within 60 days held by other executive officers of the Company. (8) Less than one percent. 66 EXECUTIVE COMPENSATION AND OTHER INFORMATION SUMMARY COMPENSATION TABLE The following table sets forth the annual and long-term compensation for the Company's Chief Executive Officer and the four other most highly compensated executive officers for 1995, as well as the total compensation paid to each such individual during the Company's last three fiscal years. Such individuals are sometimes referred to as the "named executive officers."
LONG-TERM COMPENSATION ------------ ANNUAL COMPENSATION AWARDS -------------------------------------- ------------ SECURITIES OTHER ANNUAL UNDERLYING NAME AND COMPENSATION OPTIONS/SARS ALL OTHER PRINCIPAL POSITION YEAR SALARY($) BONUS($) ($)(6) (#) COMPENSATION($) ------------------ ---- --------- -------- ------------ ------------ --------------- Douglas H. Miller....... 1995 218,968 16,826 13,500(7) -- 7,340(12) Chief Executive 1994 201,469 15,938 12,000(7) 28,865 7,131(13) Officer; Chairman of 1993 181,563 24,811 12,000(7) 17,500 6,769(14) the Board T. W. Eubank(1)......... 1995 187,687 14,644 13,500(7) -- 9,650(15) President; Chief 1994 172,688 13,604 12,000(7) 24,750 9,629(16) Operating Officer 1993 155,625 21,498 12,000(7) 15,000 9,320(17) Grant W. Henderson(2)........... 1995 156,406 12,338 9,750(7)(8) 100,000(11) 5,335(18) Executive Vice 1994 143,906 10,919 -- 20,620 4,958(19) President; Chief 1993 30,501 3,996 -- 25,000 -- Financial Officer Tommie E. Lohman(3).............. 1995 152,474 8,275 13,500(7) -- 7,439(20) President--Taurus 1994 100,781 7,475 6,500(7)(9) 107,500(11) 4,928(21) Energy Corp. 1993 -- -- -- -- -- Jarl P. Johnson(4)...... 1995 175,000 9,165 13,500(7) -- 7,627(22) Vice Chairman of the 1994 45,854 31,104(5) 1,500(7)(10) 108,750(11) 2,100(23) Board; President-- 1993 -- -- -- -- -- Diamond Energy Operating Company
- -------- (1) Mr. Eubank retired from the Company in February 1996. (2) Mr. Henderson's employment did not commence until October 15, 1993, when he joined the Company as Executive Vice President and Chief Financial Officer. Mr. Henderson's compensation is therefore reported from October 15, 1993 through December 31, 1995. (3) Mr. Lohman's employment did not commence until April 29, 1994, when the Company acquired Taurus. Mr. Lohman's compensation is therefore reported from May 1, 1994 through December 31, 1995. Mr. Lohman retired from Taurus in April 1996. (4) Mr. Johnson's employment did not commence until September 30, 1994, when the Company acquired Diamond. Mr. Johnson's compensation is therefore reported from October 1, 1994 through December 31, 1995. (5) Includes $27,936 paid to Mr. Johnson as compensation pursuant to the terms of the acquisition of Diamond. (6) For each of the named executive officers, the aggregate amount of perquisites and other personal benefits did not exceed the lesser of $50,000 or 10% of the officer's total annual salary and bonus. (7) Reflects director's fees paid by the Company of $12,000 per year (in years prior to 1995 as $6,000 in cash and $6,000 in Common Stock, calculated quarterly at the average market price per quarter, and during 1995 as $9,000 in cash and $3,000 in Common Stock, calculated quarterly at the average market price per quarter, all of which Common Stock was paid in the first two quarters of 1995). The cash portion of the director's fees is paid in the quarter earned while the stock portion of the director's fees is paid after the end of such quarter. (8) Director's fees paid to Mr. Henderson were prorated to reflect his becoming a director on March 15, 1995. 67 (9) Director's fees paid to Mr. Lohman were prorated to reflect his becoming a director on April 29, 1994. Although Mr. Lohman accrued $8,000 in director's fees, only $6,500 of those fees were paid in fiscal year 1994. See Note (7). (10) Director's fees paid to Mr. Johnson were prorated to reflect his becoming a director on September 30, 1994. Although Mr. Johnson accrued $3,000 in director's fees, only $1,500 of those fees were paid in fiscal year 1994. See Note (7). (11) Includes a warrant for the purchase of up to 100,000 shares which is awarded to each director of the Company on the date of his election or selection and vests 25,000 shares per year beginning on the first anniversary of the grant. (12) Includes $6,930 attributable to the Company's matching contribution to its 401(k) Plan, and $410 paid by the Company for term life insurance premium. (13) Includes $6,742 attributable to the Company's matching contribution to its 401(k) Plan, and $389 paid by the Company for term life insurance premium. (14) Includes $6,381 attributable to the Company's matching contribution to its 401(k) Plan, and $389 paid by the Company for term life insurance premium. (15) Includes $9,240 attributable to the Company's matching contribution to its 401(k) Plan, and $410 paid by the Company for term life insurance premium. (16) Includes $9,240 attributable to the Company's matching contribution to its 401(k) Plan, and $389 paid by the Company for term life insurance premium. (17) Includes $8,931 attributable to the Company's matching contribution to its 401(k) Plan, and $389 paid by the Company for term life insurance premium. (18) Includes $4,925 attributable to the Company's matching contribution to its 401(k) Plan, and $410 paid by the Company for term life insurance premium. (19) Includes $4,569 attributable to the Company's matching contribution to its 401(k) Plan, and $389 paid by the Company for term life insurance premium. (20) Includes $7,029 attributable to the Company's matching contribution to its 401(k) Plan, and $410 paid by the Company for term life insurance premium. (21) Includes $4,747 attributable to the Company's matching contribution to its 401(k) Plan, and $181 paid by the Company for term life insurance premium. (22) Includes $7,217 attributable to the Company's matching contribution to its 401(k) Plan, and $410 paid by the Company for term life insurance premium. (23) Consists of $2,100 paid by the Company for term life insurance premium. The following table sets forth certain information concerning options/SARs granted during 1995 to the named executive officers of the Company.
INDIVIDUAL GRANTS ------------------------------------------------ POTENTIAL REALIZABLE PERCENT OF VALUE AT ASSUMED NUMBER OF TOTAL ANNUAL RATES OF STOCK SECURITIES OPTIONS/SARS PRICE APPRECIATION FOR UNDERLYING GRANTED TO EXERCISE OR OPTION TERM(1) OPTIONS/SARS EMPLOYEES IN BASE PRICE EXPIRATION ---------------------- NAME GRANTED FISCAL YEAR ($/SH) DATE 5%($) 10%($) ---- ------------ ------------ ----------- ---------- ----- ----------- Douglas H. Miller....... -- -- -- -- -- -- T.W. Eubank............. -- -- -- -- -- -- Grant W. Henderson...... 100,000 100 6.00 3/15/05 377,337 956,245 Tommie E. Lohman........ -- -- -- -- -- -- Jarl P. Johnson......... -- -- -- -- -- --
- -------- (1) The amounts disclosed in these columns, which reflect appreciation at the 5% and 10% rates dictated by the Commission, are not intended to be a forecast of Common Stock price and are not necessarily indicative of the actual values which may be realized by the named executive officers. 68 The following table shows aggregated option/SAR exercises in the last fiscal year and fiscal year end option/SAR values for each of the named executive officers:
VALUE OF UNEXERCISED NUMBER OF SECURITIES IN-THE MONEY UNDERLYING UNEXERCISED OPTIONS/SARS SHARES OPTIONS/SARS AT FY-END ($) ACQUIRED ON VALUE AT FY-END (#) EXERCISABLE/ NAME EXERCISE(#) REALIZED ($) EXERCISABLE/UNEXERCISABLE UNEXERCISABLE(1) ---- ----------- ------------ ------------------------- ---------------- Douglas H. Miller....... -- -- 558,660/18,955 2,422,723/35,994 T.W. Eubank............. -- -- 76,000/18,750 266,188/35,078 Grant W. Henderson...... -- -- 25,829/119,791 43,428/177,927 Tommie E. Lohman........ -- -- 27,500/80,000 68,594/201,250 Jarl P. Johnson......... -- -- 27,917/80,833 22,475/62,135
- -------- (1) Values are calculated by subtracting the exercise price per share from the market value per share of the Company's Common Stock at fiscal year end, multiplied by the number of shares of Common Stock underlying the "in-the- money" options, and assumes a fair market value at fiscal year end of $7.4375 per share (the closing price of the Company's Common Stock on December 29, 1995). DIRECTORS' COMPENSATION Following completion of the Merger, members of the Company's Board of Directors will not receive compensation for any services provided in their capacities as directors, other than the reimbursement of reasonable expenses incurred in attending meetings of the Board of Directors. Prior to completion of the Merger, the directors were compensated pursuant to the terms of the Compensation Plan for Directors adopted during 1990 (the "Plan"), which applied equally to non-employee directors and directors who were also employees of the Company. The Plan provided a quarterly director's fee of $3,000, half in cash and half in Common Stock (at the average market price for the quarter), plus the one time grant to each director of a warrant to purchase up to 100,000 shares of Common Stock, at an exercise price equal to the greater of $3.00 per share or the closing trade price on the date of the grant. Pursuant to the Merger, each of the outstanding warrants (irrespective of whether or not such warrant was currently exercisable) was canceled in exchange for either (i) the cash payment of the "in-the-money" position of the warrant or (ii) equity positions with the Company following the Merger. Pursuant to the Plan, the cash portion of the director's compensation was paid monthly in the month earned. The stock portion of the director's compensation was paid quarterly, at the beginning of the quarter immediately following the quarter in which the compensation was earned. The Plan was amended on September 27, 1995 to provide that, effective July 1, 1995, all of the compensation was to be paid in cash. During 1995, each director, except for Mr. Henderson, was paid $9,000 in cash and 703 shares of Common Stock under the Plan. Mr. Henderson was paid $8,000 in cash and 261 shares of Common Stock under the Plan. Additionally, Messrs. Earl Ellis, David Keener and Worthy Warnack received $20,000, $15,000 and $15,000, respectively, for their service on the Board of Directors' Special Committee which was formed in April 1995. EMPLOYMENT AGREEMENTS Messrs. Douglas H. Miller, Jarl P. Johnson, Grant W. Henderson, Randell A. Bodenhamer, J. William Freeman and J.W. Spencer, III, have entered into employment agreements (the "Employment Agreements") with the Company which became effective on February 16, 1996. The Employment Agreements are for a period of five years from February 16, 1996 (three years in the case of Messrs. Johnson and Spencer) and provide for the payment of base salaries, together with other benefits generally available to employees of the Company, and positions with the Company as set forth below: 69
NAME POSITION WITH THE COMPANY ANNUAL BASE SALARY ---- ------------------------- ------------------ Randell A. Bodenhamer.. Vice President--Land $145,000 J. William Freeman..... Vice President--Engineering $170,000 Grant W. Henderson..... President and Chief Financial Officer $225,000 Jarl P. Johnson........ Vice Chairman of the Board and Chief $250,000 Operating Officer Douglas H. Miller...... Chairman of the Board and Chief Executive $350,000 Officer J.W. Spencer, III...... Vice President--Operations $170,000
Each of these persons would receive his salary for the remaining term of his Employment Agreement if the Company were to terminate his Employment Agreement other than for cause. The Employment Agreements provide that the employees agree not to compete with the Company for a period of six months after their voluntary termination or termination for cause; in the case of Mr. Miller, the covenant not to compete is for a period of two years, except that the noncompetition period is one year in the event of incapacity, involuntary termination other than for cause or his resignation due to a breach by the Company of Mr. Miller's Employment Agreement. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION The Board of Directors had a Compensation Committee consisting of Walter Hailey and Frank Horlock. This committee did not meet in 1995. CERTAIN TRANSACTIONS CERTAIN INDEBTEDNESS In connection with the acquisition of Taurus, Mr. Lohman made a loan to the Company for the sum of $1.0 million in exchange for a subordinated promissory note from the Company having a term of three years, payable in three equal annual installments of principal plus accrued interest calculated at the rate of 7% per annum. Such amount represented the highest outstanding balance owed by the Company to Mr. Lohman in 1995. On December 31, 1995, the principal balance remaining on the promissory note was $666,667. On February 16, 1996, the Company repaid Mr. Lohman the aggregate amount of principal and interest owed by the Company to Mr. Lohman. Douglas H. Miller, Chairman of the Board and Chief Executive Officer of the Company, was indebted to the Company in an aggregate amount of $83,589 as of June 30, 1995. Such amount represented the highest outstanding balance owed by Mr. Miller to the Company in 1995. The indebtedness consisted of three promissory notes, dated as of May 31, 1992, October 1, 1994, and May 31, 1995, in the original principal amounts of $19,022, $19,250 and $69,526, respectively. The October 1, 1994 note bore interest at 3.75%, and the remaining two notes bore interest at the prime rate charged by NationsBank plus one percent. Except for the promissory note in the original principal amount of $19,250, the proceeds from which were used to purchase Common Stock under the Company's 1994 Employee Stock Purchase Plan, all indebtedness represented Mr. Miller's miscellaneous personal expenses. On February 20, 1996, Mr. Miller repaid the Company an aggregate amount of $90,105 representing all indebtedness owed by Mr. Miller to the Company. In May 1995, Jarl P. Johnson, Vice Chairman of the Board and President of Diamond, repaid Diamond the sum of $236,194, representing full payment of indebtedness evidenced by a promissory note, payable on demand, bearing interest at the rate of 10% per annum. Such amount represented the highest outstanding balance owed by Mr. Johnson to the Company in 1995. The indebtedness was 70 secured by a pledge of certain shares of Common Stock owned by Mr. Johnson. The indebtedness arose in June 1990, prior to the Company's acquisition of Diamond, when Mr. Johnson and certain other Diamond shareholders obtained certain properties of Diamond Energy Operating Company in exchange for notes. The properties were then contributed to Diamond A Inc. in exchange for shares of Diamond A Inc., which shares were in turn pledged to secure the notes. SUBSCRIPTION AGREEMENT CAI entered into a Subscription Agreement dated as of October 30, 1995, as amended by Amendment No. 1 to Subscription Agreement dated as of January 10, 1996, with members of the Management Group (as amended, the "Subscription Agreement") which provided for the acquisition by such persons of CAI common stock and the grant to them of nonqualified stock options to purchase shares of post-Merger common stock (the "Replacement Options") of Coda. Under the Subscription Agreement, each member of the Management Group who acquired CAI common stock paid $100 per share for shares thereof, which is the same price per share paid by JEDI for the remaining shares of CAI common stock. Under the Subscription Agreement, the Management Group acquired CAI common stock immediately prior to the effective time of the Merger in exchange for varying combinations of (i) proceeds from limited recourse promissory notes payable to CAI in the aggregate principal amount of $937,300 (the "Promissory Notes"), (ii) Common Stock, which was valued for this purpose at $7.75 per share, and (iii) cash. The CAI common stock so acquired was not registered under the Securities Act or any state securities laws and does not have the benefit of any registration rights, but is subject to the Stockholders Agreement described below. See "--Stockholders Agreement." By virtue of the Merger, each share of CAI common stock was converted into one share of Coda common stock. The Subscription Agreement provided that the Specified Options (representing certain options to purchase Common Stock held by certain members of the Management Group) and Specified Warrants (representing certain warrants to purchase Common Stock held by certain members of the Management Group) would not be exercised prior to the effective time of the Merger and would, as of the effective time, be canceled without exercise and without payment of consideration. Concurrently, the Management Group entered into Nonstatutory Stock Option Agreements governing the Replacement Options that provided for the right for a period of 10 years from and after the effective time of the Merger to purchase shares of post-Merger Coda common stock for $0.01 per share. However, the Replacement Options may only be exercised while the holder remains an employee of the Company and for a limited period of time thereafter. The number of shares of Coda common stock underlying the Replacement Options each member of the Management Group received is based on the amount of cash the holder would have received if his Specified Options or Specified Warrants had been converted into cash in the Merger on the same basis as other outstanding options and warrants to purchase Common Stock were converted, divided by the $100 per share purchase price paid by JEDI and the other Management Group members for their shares of CAI common stock. Thus, if the Replacement Options are exercised, the holders will have effectively paid the same purchase price per share as JEDI and the Management Group paid for their shares of common stock of Coda. The Promissory Notes will be due on February 16, 2001, bear interest at the mid-term applicable federal rate (annual compounding) for the month February 1996 (5.61%), are secured by the Company common stock purchased with the proceeds thereof and certain rights of the maker under the Stockholders Agreement described below, and provide that in no event will an individual maker's liability thereunder for any deficiency on his respective Promissory Note (after the sale and disposition of all collateral securing same) exceed 35% of the original principal balance of the Promissory Note. 71 STOCKHOLDERS AGREEMENT CAI, JEDI and the Management Group entered into a Stockholders Agreement dated as of October 30, 1995, as amended by Amendment No. 1 to Stockholders Agreement dated as of January 10, 1996 (as amended, the "Stockholders Agreement"), which provides generally that all parties, including JEDI and the Management Group, (i) have rights of first refusal to acquire additional shares of common stock of Coda that may be issued by Coda and (ii) are restricted from transferring their Coda common stock. Coda has a right to match any third party offer to purchase shares of Coda common stock from any stockholder, and, in the event that Coda does not purchase those shares, the other stockholders may have a right to include a pro rata portion of their Coda common stock in the transaction. The Stockholders Agreement provides that, if the employment of a member of the Management Group terminates for any reason (including death or disability) other than his voluntary termination (except upon retirement at age 65 or older or the expiration of the term of any employment agreement he has with Coda) or his termination by Coda for cause, then Coda shall have a right to purchase such member's shares of Coda common stock at a purchase price to be determined from time to time by Coda pursuant to a formula that values the shares on the basis of a comparison of the discretionary cash flow and EBITDA (as defined therein) of the Company and a group of peer companies. The Stockholders Agreement also provides that, if the employment of a member of the Management Group terminates for any reason other than voluntary termination or termination of such member for cause, then such member shall have the right to require Coda to purchase such member's shares of Coda common stock based on the previously described formula. The purchase price under the formula will vary depending on the financial performance of the Company and the group of peer companies. The Stockholders Agreement provides that each member of the Management Group shall have the right (the "Special Management Rights") to receive from JEDI, upon the occurrence of certain events (generally an initial public offering, a business combination with another person or the liquidation of Coda) (each, a "Trigger Event"), an amount, which is payable in cash or additional shares of Coda common stock depending upon the cause of the Trigger Event, designed to result in the Management Group receiving in connection with the Trigger Event one-third of the proceeds, attributable to the shares of Coda common stock purchased by JEDI, above the amount of proceeds necessary for JEDI to achieve an internal annual rate of return on that investment of 15%. The individual member's interest in such Special Management Rights is proportional to such member's ownership of the fully diluted common stock of Coda. The Stockholders Agreement also provides that if the employment of a member of the Management Group terminates, his Special Management Rights shall terminate and, if the termination is other than a voluntary termination or a termination for cause, he may be entitled to receive an amount based on the discretionary cash flow and EBITDA formula discussed above. The Stockholders Agreement further provides that, after the effective time of the Merger, Coda will establish an employee benefit plan for the benefit of its employees who are not members of the Management Group and will contribute to the plan 1,900 shares of Coda common stock. Furthermore, pursuant to the Stockholders Agreement, 4% of the Special Management Rights will be allocated thereto. The Stockholders Agreement will terminate and no party thereto will have any further obligations or rights thereunder upon the earliest to occur of (i) the termination of the Merger Agreement in accordance with its terms, (ii) October 30, 2005, (iii) the date on which an initial public offering of Coda common stock or any business transaction involving Coda whereby Coda common stock becomes a publicly traded security is consummated, (iv) the date of the dissolution, liquidation or winding-up of Coda and (v) the date of the delivery to Coda of a written termination notice executed by certain parties to the Stockholders Agreement. 72 ENRON Enron is the parent of ECT and accordingly may be deemed to control indirectly both JEDI and the Company. Enron and certain of its subsidiaries and other affiliates collectively participate in nearly all phases of the oil and natural gas industry and are, therefore, competitors of the Company. In addition, ECT and JEDI have provided, and may in the future provide, and ECT Securities Corp. has assisted, and may in the future assist, in arranging, financing to non-affiliated participants in the oil and natural gas industry who are or may become competitors of the Company. Because of these various conflicting interests, ECT, the Company, JEDI and the Management Group have entered into the Business Opportunity Agreement which is intended to make it clear that Enron and its affiliates have no duty to make business opportunities available to the Company in most circumstances. The Business Opportunity Agreement also provides that ECT and its affiliates may pursue certain business opportunities to the exclusion of the Company. The Business Opportunity Agreement may limit the business opportunities available to the Company. In addition, pursuant to the Business Opportunity Agreement there may be circumstances in which the Company will offer business opportunities to certain affiliates of Enron. If an Enron affiliate is offered such an opportunity and decides to pursue it, the Company may be unable to pursue it. See "Offer and Resale" for a discussion of ECT Securities, Inc.'s involvement in the Offering. During the fiscal year ended December 31, 1995, EOTT made payments to the Company aggregating approximately $17.7 million for oil purchases. See "Business--Marketing." Furthermore, during the fiscal year ended December 31, 1995, Enron Industrial Natural Gas Company, an indirect subsidiary of Enron and an affiliate of JEDI, made payments aggregating approximately $1.8 million for purchases of natural gas from Taurus. 73 DESCRIPTION OF EXCHANGE NOTES GENERAL The Exchange Notes will be issued pursuant to an Indenture (the "Indenture") among the Company, the initial Guarantors and Texas Commerce Bank National Association, as trustee (the "Trustee"). The Exchange Notes will evidence the same indebtedness as the Private Notes (which they replace) and will be issued under, and be entitled to the benefits of, the Indenture. The form and terms of the Exchange Notes are the same as the form and terms of the Private Notes except that (i) the Exchange Notes will bear the Series B designation, (ii) the Exchange Notes will have been registered under the Securities Act and, therefore, the Exchange Notes will not bear legends restricting the transfer thereof and (iii) holders of the Exchange Notes will not be entitled to certain rights of holders of the Private Notes under the Registration Rights Agreement, which rights will terminate upon consummation of the Exchange Offer. The terms of the Notes include those stated in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939 (the "Trust Indenture Act"). The Notes are subject to all such terms, and Holders of Notes are referred to the Indenture and the Trust Indenture Act for a statement thereof. 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, including the definitions therein of certain terms used below. The definitions of certain terms used in the following summary are set forth below under "--Certain Definitions." The Notes will be general unsecured obligations of the Company and will be subordinated in right of payment to Senior Debt. See "Risk Factors-- Subordination." The Notes will be guaranteed on a senior subordinated basis by all of the Company's current Subsidiaries and future Restricted Subsidiaries. The obligation of the Restricted Subsidiaries under such guarantees will be general unsecured obligations of such Restricted Subsidiaries and will be subordinated in right of payment to all obligations of such Restricted Subsidiaries in respect of Senior Debt. See "--Subsidiary Guarantees" and "Risk Factors--Subordination." While Coda itself owns and operates a significant portion of the Company's consolidated assets, Coda currently depends to a large degree on cash flow generated by Diamond, and to a lesser degree on cash flow generated by Taurus. Electra does not currently hold or operate any assets. All of Coda's current subsidiaries are guarantors of the Notes and are not obligors on any indebtedness for borrowed money (excluding intercompany indebtedness and as guarantors under the Credit Agreement). There are no contractual restrictions on the ability to pay dividends or make any other distributions of funds by the Guarantors to Coda. The corporation laws of each of the states under which the Guarantors are chartered contain certain restrictions on the ability of corporations to pay dividends or make other distributions to holders of such corporation's capital stock. As of the date of the Indenture, all of the Company's Subsidiaries will be Restricted Subsidiaries. However, under certain circumstances, the Company will be able to designate current or future Subsidiaries as Unrestricted Subsidiaries. Unrestricted Subsidiaries will not be subject to many of the restrictive covenants set forth in the Indenture. For purposes of this section, the term "Company" means Coda Energy, Inc. and the term "Taurus" has the meaning given under the caption "--Certain Definitions." SUBORDINATION The payment of principal of, premium, if any, and interest and Liquidated Damages, if any, on the Notes and any other payment obligations of the Company in respect of the Notes (including any obligation to repurchase the Notes) will be subordinated in certain circumstances in right of payment, as set forth in the Indenture, to the prior payment in full of all Senior Debt, whether outstanding on the date of the Indenture or thereafter incurred. 74 Upon any distribution to creditors of the Company in a liquidation or dissolution of the Company or in a bankruptcy, reorganization, insolvency, receivership or similar proceeding relating to the Company or its property, or in an assignment for the benefit of creditors or any marshalling of the Company's assets and liabilities, the holders of Senior Debt will be entitled to receive payment in full of all Obligations due in respect of such Senior Debt (including interest after the commencement of any such proceeding at the rate specified in the applicable Senior Debt) before the Holders of Notes will be entitled to receive any payment with respect to the Notes, and until all Obligations with respect to Senior Debt are paid in full, any distribution to which the Holders of Notes would be entitled shall be made to the holders of Senior Debt (except that Holders of Notes may receive securities that are subordinated at least to the same extent as the Notes to Senior Debt and any securities issued in exchange for Senior Debt (provided that receipt of such securities will not cause the Notes to be treated in any case or proceeding or similar event described in this paragraph in the same class of claims as Senior Debt or any class of claims pari passu with Senior Debt for any payment or distribution) and payments made from the trust described under "--Legal Defeasance and Covenant Defeasance"). The Company also may not make any payment upon or in respect of the Notes (except in such subordinated securities or from the trust described under "-- Legal Defeasance and Covenant Defeasance") if (i) a default in the payment of the principal of, premium, if any, or interest on Designated Senior Debt occurs and is continuing beyond any applicable period of grace or (ii) any other default occurs and is continuing with respect to Designated Senior Debt that permits, or with the giving of notice or passage of time or both (unless cured or waived) will permit, holders of the Designated Senior Debt as to which such default relates to accelerate its maturity and the Trustee receives a notice of such default (a "Payment Blockage Notice") from the Company or the holders of any Designated Senior Debt. Payments on the Notes shall be resumed (a) in the case of a payment default, upon the date on which such default is cured or waived and (b) in case of a nonpayment default, the earlier of the date on which such nonpayment default is cured or waived or 179 days after the date on which the applicable Payment Blockage Notice is received, unless the maturity of any Designated Senior Debt has been accelerated. No new period of payment blockage may be commenced unless and until (i) 360 days have elapsed since the date of commencement of the payment blockage period resulting from the immediately prior Payment Blockage Notice and (ii) all scheduled payments of principal, premium, if any, and interest on the Notes that have come due have been paid in full in cash. No nonpayment default that existed or was continuing on the date of delivery of any Payment Blockage Notice to the Trustee shall be, or be made, the basis for a subsequent Payment Blockage Notice. The Indenture will further require that the Company promptly notify holders of Senior Debt if payment of the Notes is accelerated because of an Event of Default. As a result of the subordination provisions described above, in the event of a liquidation or insolvency of the Company, Holders of Notes may recover less ratably than creditors of the Company who are holders of Senior Debt. On a pro forma basis, after giving effect to the Merger and the sale of the Private Notes and the application of the proceeds therefrom, the principal amount of Senior Debt outstanding at December 31, 1995 would have been approximately $86.9 million, which includes $85.3 million of borrowings under the Credit Agreement. See "Description of Other Debt." The Indenture will limit, subject to certain financial tests, the amount of additional Indebtedness, including Senior Debt, that the Company and its Restricted Subsidiaries can incur. See "--Certain Covenants--Incurrence of Indebtedness and Issuance of Preferred Stock." SUBSIDIARY GUARANTEES The Company's payment obligations under the Notes will be jointly and severally and unconditionally guaranteed (the "Subsidiary Guarantees") by the Guarantors. The Subsidiary 75 Guarantee of each Guarantor will be subordinated (to the same extent and in the same manner as the Notes are subordinated to the Senior Debt) to the prior payment in full of all Senior Debt of such Guarantor, which, on a pro forma basis, after giving effect to the Merger and the sale of the Private Notes and the application of proceeds therefrom, would have been approximately $86.9 million as of December 31, 1995. The obligations of each Guarantor under its Subsidiary Guarantee will be limited so as not to constitute a fraudulent conveyance under applicable law. See, however, "Risk Factors--Fraudulent Conveyances." The Indenture will provide that no Guarantor may consolidate with or merge with or into (whether or not such Guarantor is the surviving Person), another corporation, Person or entity whether or not affiliated with such Guarantor unless (i) subject to the provisions of the following paragraph, the Person formed by or surviving any such consolidation or merger (if other than such Guarantor) assumes all the obligations of such Guarantor, pursuant to a supplemental indenture in form and substance reasonably satisfactory to the Trustee in respect of the Notes, the Indenture and such Guarantor's Subsidiary Guarantee; (ii) immediately after giving effect to such transaction, no Default or Event of Default exists; and (iii) such transaction does not violate any of the covenants described under the heading "--Certain Covenants." The Indenture will provide that in the event of a sale or other disposition of all or substantially all of the assets of any Guarantor to a third party or an Unrestricted Subsidiary in a transaction that does not violate any of the covenants in the Indenture, by way of merger, consolidation or otherwise, or a sale or other disposition of all of the capital stock of any Guarantor, then such Guarantor (in the event of a sale or other disposition, by way of such a merger, consolidation or otherwise, of all of the capital stock of such Guarantor) or the corporation acquiring the property (in the event of a sale or other disposition of all of the assets of such Guarantor) will be released from and relieved of any obligations under its Subsidiary Guarantee; provided that the Net Proceeds of such sale or other disposition are applied in accordance with the covenant described under the caption "--Repurchase at the Option of Holders--Asset Sales." Any Guarantor that is designated an Unrestricted Subsidiary in accordance with the terms of the Indenture shall be released from and relieved of its obligations under its Subsidiary Guarantee and any Unrestricted Subsidiary that ceases to be an Unrestricted Subsidiary will be required to execute a Subsidiary Guarantee in accordance with the terms of the Indenture. PRINCIPAL, MATURITY AND INTEREST The Notes will be limited in aggregate principal amount to $110.0 million and will mature on April 1, 2006. Interest on the Notes will accrue at the rate of 10 1/2% per annum and will be payable semiannually in arrears on April 1 and October 1, commencing on October 1, 1996, to Holders of record on the immediately preceding March 15 and September 15. Interest on the Notes will accrue from the most recent date on which interest has been paid or, if no interest has been paid, from the date of original issuance of the Exchange Notes, plus an amount equal to the accrued interest on the Private Notes from the date of initial delivery to the date of exchange thereof for the Exchange Notes. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months. Principal, premium, if any, interest and Liquidated Damages, if any, on the Notes will be payable at the office or agency of the Company maintained for such purpose within the City and State of New York or, at the option of the Company, payment of interest and Liquidated Damages, if any, may be made by check mailed to the Holders of the Notes at their respective addresses set forth in the register of Holders of Notes; provided that all payments with respect to Notes having an aggregate principal amount of $5.0 million or more the Holders of which have given wire transfer instructions to the Company at least ten business days prior to the applicable payment date will be required to be made by wire transfer of immediately available funds to the accounts specified by the Holders thereof. Until otherwise designated by the Company, the Company's office or agency in New York will be the office of the 76 Trustee maintained for such purpose. The Exchange Notes will be issued in registered form, without coupons, and in denominations of $1,000 and integral multiples of $1,000 in excess thereof. OPTIONAL REDEMPTION The Notes will not be redeemable at the Company's option prior to April 1, 2001, except as provided below. Thereafter, the Notes will be subject to redemption at the option of the Company, in whole or in part, upon not less than 30 nor more than 60 days' notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest and Liquidated Damages, if any, thereon to the applicable redemption date, if redeemed during the twelve-month period beginning on April 1 of the years indicated below:
YEAR PERCENTAGE ---- ---------- 2001........................................................... 105.25% 2002........................................................... 102.625% 2003 and thereafter............................................ 100%
Notwithstanding the foregoing, before March 12, 1999, the Company may, on any one or more occasions, redeem up to $27.5 million in aggregate principal amount of Notes at a redemption price of 110.5% of the principal amount thereof plus accrued and unpaid interest and Liquidated Damages, if any, thereon to the redemption date, with the net proceeds of an offering of common equity of the Company; provided that at least $82.5 million in aggregate principal amount of Notes must remain outstanding immediately after the occurrence of such redemption; and provided, further, that any such redemption shall occur within 75 days of the date of the closing of such offering of common equity of the Company. SELECTION AND NOTICE If less than all of the Notes are to be redeemed at any time, selection of Notes for redemption will be made by the Trustee in compliance with the requirements of the principal national securities exchange, if any, on which the Notes are listed, or, if the Notes are not so listed, on a pro rata basis, by lot or by such method as the Trustee shall deem fair and appropriate; provided that no Notes of $1,000 or less shall be redeemed in part. Notices of redemption shall be mailed by first class mail at least 30 but not more than 60 days before the redemption date to each Holder of Notes to be redeemed at its registered address. If any Note is to be redeemed in part only, the notice of redemption that relates to such Note shall state the portion of the principal amount thereof to be redeemed. A new Note in principal amount equal to the unredeemed portion thereof will be issued in the name of the Holder thereof upon cancellation of the original Note. On and after the redemption date, interest ceases to accrue on Notes or portions of them called for redemption. MANDATORY REDEMPTION Except as set forth below under "--Repurchase at the Option of Holders," the Company is not required to make mandatory redemption or sinking fund payments with respect to the Notes. REPURCHASE AT THE OPTION OF HOLDERS Change of Control Upon the occurrence of a Change of Control (as defined below under "--Certain Definitions"), each Holder of Notes will have the right to require the Company to repurchase all or any part (equal to $1,000 or an integral multiple thereof) of such Holder's Notes pursuant to the offer described below (the "Change of Control Offer") at an offer price in cash equal to 101% of the aggregate principal amount thereof plus accrued and unpaid interest and Liquidated Damages, if any, thereon to the date 77 of purchase (the "Change of Control Payment"). Within 30 days following any Change of Control, the Company will mail a notice to each Holder describing the transaction or transactions that constitute the Change of Control and offering to repurchase Notes pursuant to the procedures required by the Indenture and described in such notice. The Company will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent such laws and regulations are applicable in connection with the repurchase of the Notes as a result of a Change of Control. On the Change of Control Payment Date, the Company will, to the extent lawful, (i) accept for payment all Notes or portions thereof properly tendered pursuant to the Change of Control Offer, (ii) deposit with the Paying Agent an amount equal to the Change of Control Payment in respect of all Notes or portions thereof so tendered and (iii) deliver or cause to be delivered to the Trustee the Notes so accepted together with an Officers' Certificate stating the aggregate principal amount of Notes or portions thereof being purchased by the Company. The Paying Agent will promptly mail to each Holder of Notes so tendered the Change of Control Payment for such Notes, and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each Holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each such new Note will be in a principal amount of $1,000 or an integral multiple thereof. The Indenture will provide that, prior to complying with the provisions of this covenant, but in any event within 90 days following a Change of Control, the Company will either repay all outstanding Senior Debt or obtain the requisite consents, if any, under all agreements governing outstanding Senior Debt to permit the repurchase of Notes required by this covenant. The degree to which the Company is leveraged upon a Change of Control could prevent it from repaying outstanding Senior Debt (or obtaining the consent of the senior lenders to a repurchase of Notes) and from repurchasing Exchange Notes tendered to it upon such Change of Control. The Company will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Payment Date. Holders of not less than a majority in aggregate principal amount of Notes then outstanding may waive these Change of Control repurchase requirements. The Change of Control provisions described above will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture does not contain provisions that permit the Holders of the Notes to require that the Company repurchase or redeem the Notes in the event of a takeover, recapitalization or similar transaction. The Company will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by the Company and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer. The definition of Change of Control encompasses a transaction which is approved by the Company's Board of Directors. The definition also includes a phrase relating to the sale, lease, transfer, conveyance or other disposition of "all or substantially all" of the assets of the Company and its Subsidiaries taken as a whole. Although there is a developing body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a Holder of Notes to require the Company to repurchase such Notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Company and its Subsidiaries taken as a whole to another Person or group may be uncertain. The Credit Agreement currently prohibits the Company from purchasing any Notes, and also provides that certain change of control events with respect to the Company would constitute a default thereunder. Any future credit agreements or other agreements relating to Senior Indebtedness to which the Company becomes a party may contain similar restrictions and provisions. In the event a Change 78 of Control occurs at a time when the Company is prohibited from purchasing Notes, the Company could seek the consent of its lenders to the purchase of Notes or could attempt to refinance the borrowings that contain such prohibition. If the Company does not obtain such a consent or repay such borrowings, the Company will remain prohibited from purchasing Notes. In such case, the Company's failure to purchase tendered Notes would constitute an Event of Default under the Indenture. In such circumstances, the subordination provisions in the Indenture would likely restrict payments to the Holders of Notes by either Coda or the Guarantors. The existence of a Holder's right to require the Company to repurchase such Holder's Notes upon the occurrence of a Change of Control may deter a third party from seeking to acquire the Company in a transaction that would constitute a Change of Control. Asset Sales The Indenture will provide that the Company will not, and will not permit any of its Restricted Subsidiaries to, engage in an Asset Sale unless (i) the Company (or the Restricted Subsidiary, as the case may be) receives consideration at the time of such Asset Sale at least equal to the fair market value (as determined by a resolution of the Board of Directors set forth in an Officers' Certificate delivered to the Trustee, which determination shall be conclusive evidence of compliance with this provision) of the assets or Equity Interests issued or sold or otherwise disposed of and (ii) at least 85% of the consideration therefor received by the Company or such Restricted Subsidiary is in the form of cash or Cash Equivalents; provided that the amount of (x) any liabilities (as shown on the Company's or such Restricted Subsidiary's most recent balance sheet), of the Company or any Restricted Subsidiary (other than contingent liabilities and liabilities that are by their terms subordinated to the Notes or any guarantee thereof) that are assumed by the transferee of any such assets pursuant to a customary novation agreement that releases the Company or such Restricted Subsidiary from further liability and (y) any Liquid Securities received by the Company or any such Restricted Subsidiary from such transferee that are converted by the Company or such Restricted Subsidiary into cash within 180 days of closing such Asset Sale, shall be deemed to be cash for purposes of this provision (to the extent of the cash received). Within 270 days after the receipt of any Net Proceeds from an Asset Sale, the Company may apply such Net Proceeds, at its option, (a) to reduce Senior Debt, (b) to acquire a controlling interest in another Oil and Gas Business, to make a Permitted Business Investment, to make capital expenditures in respect of the Company's or its Restricted Subsidiaries' Oil and Gas Business, or to purchase long-term assets that are used or useful in the Oil and Gas Business or (c) in the case of any Net Proceeds derived from an Asset Sale in respect of Taurus, to redeem JEDI Preferred Stock. Pending the final application of any such Net Proceeds, the Company may temporarily reduce Senior Debt that is revolving debt or otherwise invest such Net Proceeds in any manner that is not prohibited by the Indenture. Any Net Proceeds from Asset Sales that are not applied or invested as provided in the first sentence of this paragraph will (after the expiration of the periods specified in this paragraph) be deemed to constitute "Excess Proceeds." When the aggregate amount of Excess Proceeds exceeds $10.0 million, the Company will be required to make an offer to all Holders of Notes and, to the extent required by the terms thereof, to all holders or lenders of Pari Passu Indebtedness (an "Asset Sale Offer") to purchase the maximum principal amount of Notes and any such Pari Passu Indebtedness to which the Asset Sale Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount thereof plus accrued and unpaid interest and Liquidated Damages, if any, thereon to the date of purchase, in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Indebtedness, as applicable. To the extent that the aggregate amount of Notes tendered or Pari Passu Indebtedness tendered pursuant to an Asset Sale Offer is less than the Excess Proceeds, the Company may use any remaining Excess Proceeds for 79 general corporate purposes. If the aggregate principal amount of Notes surrendered by Holders thereof and Pari Passu Indebtedness surrendered by holders or lenders thereof, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes and Pari Passu Indebtedness to be purchased on a pro rata basis, based on the aggregate principal amount (or accreted value, as applicable) thereof surrendered in such Asset Sale Offer. Upon completion of such Asset Sale Offer, the amount of Excess Proceeds shall be reset at zero. The Credit Agreement may prohibit the Company from purchasing any Notes and also provides that certain change of control events with respect to the Company would constitute a default thereunder. Any future credit agreements or other agreements relating to Senior Debt to which the Company becomes a party may contain similar restrictions and provisions. In the event a Change of Control or Asset Sale Offer occurs at a time when the Company is prohibited from purchasing Notes, the Company could seek the consent of its lenders to the purchase of or could attempt to refinance the borrowings that contain such prohibition. If the Company does not obtain such a consent or repay such borrowings, the Company may remain prohibited from purchasing Notes. In such case, the Company's failure to purchase tendered Notes would constitute an Event of Default under the Indenture which would, in turn, constitute a default under the Credit Agreement. In such circumstances, the subordination provisions in the Indenture would likely restrict payments to the Holders of Notes. CERTAIN COVENANTS Restricted Payments The Indenture will provide that the Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly: (i) declare or pay any dividend or make any other payment or distribution on account of the Company's Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving the Company) or to the direct or indirect holders of the Company's Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of the Company); (ii) purchase, redeem or otherwise acquire or retire for value any Equity Interests of the Company or any direct or indirect parent or other Affiliate of the Company that is not a Subsidiary of the Company; (iii) make any principal payment on, or purchase, redeem, defease or otherwise acquire or retire for value any Indebtedness that is subordinated to the Notes, except at final maturity; or (iv) make any Restricted Investment (all such payments and other actions set forth in clauses (i) through (iv) above being collectively referred to as "Restricted Payments"), unless, at the time of and after giving effect to such Restricted Payment: (a) no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof; and (b) the Company would, at the time of such Restricted Payment and after giving pro forma effect thereto as if such Restricted Payment had been made at the beginning of the applicable four-quarter period, have been permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described below under the caption "--Incurrence of Indebtedness and Issuance of Preferred Stock"; and (c) such Restricted Payment, together with the aggregate of all other Restricted Payments made by the Company and its Restricted Subsidiaries after the date of the Indenture (excluding Restricted Payments permitted by clauses (2), (3), (5), (6) and (7) of the next succeeding paragraph), is less than the sum of (i) 50% of the Consolidated Net Income of the Company for the period (taken as one accounting period) from the beginning of the first fiscal quarter commencing after the date of the Indenture to the end of the Company's most recently ended fiscal quarter for which internal financial statements are available at the time of such Restricted 80 Payment (or, if such Consolidated Net Income for such period is a deficit, less 100% of such deficit), plus (ii) 100% of the aggregate net cash proceeds received by the Company from the issue or sale since the date of the Indenture of Equity Interests of the Company (other than the JEDI Preferred Stock) or of debt securities of the Company that have been converted into or exchanged for such Equity Interests (other than Equity Interests (or convertible debt securities) sold to a Subsidiary of the Company and other than Disqualified Stock or debt securities that have been converted into Disqualified Stock), plus (iii) to the extent that any Restricted Investment that was made after the date of the Indenture is sold for cash or otherwise liquidated or repaid for cash, the lesser of (A) the net proceeds of such sale, liquidation or repayment and (B) the initial amount of such Restricted Investment, plus (iv) 50% of any dividends received by the Company or a Wholly Owned Restricted Subsidiary after the date of the Indenture from an Unrestricted Subsidiary of the Company. The foregoing provisions will not prohibit (1) the payment of any dividend within 60 days after the date of declaration thereof, if at said date of declaration such payment would have complied with the provisions of the Indenture; (2) the redemption, repurchase, retirement or other acquisition of any Equity Interests of the Company in exchange for, or out of the proceeds of, the substantially concurrent sale (other than to a Subsidiary of the Company) of other Equity Interests of the Company (other than any Disqualified Stock); provided that the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement or other acquisition shall be excluded from clause (c)(ii) of the preceding paragraph; (3) the defeasance, redemption or repurchase of subordinated Indebtedness with the net cash proceeds from an incurrence of Permitted Refinancing Debt or the substantially concurrent sale (other than to a Subsidiary of the Company) of Equity Interests of the Company (other than Disqualified Stock); provided that the amount of any such net cash proceeds that are utilized for any such redemption, repurchase, retirement or other acquisition shall be excluded from clause (c)(ii) of the preceding paragraph; (4) the repurchase, redemption or other acquisition or retirement for value of any Equity Interests of the Company or any Restricted Subsidiary of the Company held by any of the Company's (or any of its Subsidiaries') employees pursuant to any management equity subscription agreement or stock option agreement in effect as of the date of the Indenture; provided that the aggregate price paid for all such repurchased, redeemed, acquired or retired Equity Interests shall not exceed $1.5 million in any twelve-month period (plus the aggregate cash proceeds received by the Company during such twelve-month period from any issuance of Equity Interests by the Company to any Principal and to employees of the Company and its Subsidiaries); and provided further that no Default or Event of Default shall have occurred and be continuing immediately after such transaction; (5) the redemption of the JEDI Preferred Stock, at a redemption price equal to the liquidation preference thereof plus accrued dividends thereon to the date of redemption, in each case calculated in accordance with the provisions thereof as the same are in effect on the date of the Indenture, with the net proceeds from the sale of the Equity Interests in or all or substantially all of the assets of Taurus in accordance with the covenant described under the caption "--Repurchase at the Option of Holders--Asset Sales"; (6) repurchases of Equity Interests deemed to occur upon exercise of stock options if such Equity Interests represent a portion of the exercise price of such options; (7) the repayment of all amounts due in respect of the JEDI Debt; and (8) other Restricted Payments in an aggregate amount not to exceed $5.0 million. The amount of all Restricted Payments (other than cash) shall be the fair market value (as determined by a resolution of the Board of Directors set forth in an Officers' Certificate delivered to the Trustee, which determination shall be conclusive evidence of compliance with this provision) on the date of the Restricted Payment of the asset(s) proposed to be transferred by the Company or the applicable Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment. Not later than five days after the date of making any Restricted Payment, the Company shall deliver to the Trustee an Officers' Certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by the covenant "Restricted Payments" were computed. 81 The Board of Directors may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if such designation would not cause a Default; provided that in no event shall the properties currently operated by Diamond be transferred to or held by an Unrestricted Subsidiary. For purposes of making such determination, all outstanding Investments by the Company and its Restricted Subsidiaries (except to the extent repaid in cash) in the Subsidiary so designated will be deemed to be Restricted Payments at the time of such designation and will reduce the amount available for Restricted Payments under clause (c) of the first paragraph of this covenant and/or the applicable provisions of the second paragraph of this covenant, as appropriate. All such outstanding Investments will be deemed to constitute Investments in an amount equal to the greatest of (x) the net book value of such Investments at the time of such designation, (y) the fair market value of such Investments at the time of such designation and (z) the original fair market value of such Investments at the time they were made. Such designation will only be permitted if such Restricted Payment would be permitted at such time and if such Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. Incurrence of Indebtedness and Issuance of Disqualified Stock The Indenture will provide that the Company will not, and will not permit any of its Subsidiaries to, directly or indirectly, create, incur, issue, assume, guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, "incur") any Indebtedness (including Acquired Debt) and that the Company will not issue any Disqualified Stock and will not permit any of its Subsidiaries to issue any shares of preferred stock; provided, however, that the Company may incur Indebtedness (including Acquired Debt) or issue shares of Disqualified Stock if: (i) the Fixed Charge Coverage Ratio for the Company's most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock is issued would have been at least 2.5 to 1, determined on a pro forma basis as set forth in the definition of Fixed Charge Coverage Ratio; and (ii) no Default or Event of Default shall have occurred and be continuing at the time such additional Indebtedness is incurred or such Disqualified Stock is issued or would occur as a consequence of the incurrence of the additional Indebtedness or the issuance of the Disqualified Stock. Notwithstanding the foregoing, the Indenture will not prohibit any of the following (collectively, "Permitted Indebtedness"): (a) the Indebtedness evidenced by the Notes; (b) the incurrence by the Company of Indebtedness pursuant to Credit Facilities, so long as the aggregate principal amount of all Indebtedness outstanding under all Credit Facilities does not, at any one time, exceed the Borrowing Base, provided that if the Company incurs any Indebtedness pursuant to this clause (b) that would cause the total principal amount of Indebtedness under this clause (b) to exceed an amount equal to $150.0 million (less the aggregate amount of all Net Proceeds of Asset Sales including, without limitation, an Asset Sale involving Taurus, applied to reduce Senior Debt pursuant to clause (a) of the second paragraph of the covenant described under the caption "--Repurchase at the Option of Holders--Asset Sales"), the Fixed Charge Coverage Ratio for the Company's most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred would have been at least 2.0 to 1, determined on a pro forma basis as set forth in the definition of Fixed Charge Coverage Ratio; (c) the guarantee by the Guarantors of any Indebtedness that is permitted by the Indenture to be incurred by the Company; (d) Existing Indebtedness; (e) intercompany Indebtedness between or among the Company and any of its Wholly Owned Restricted Subsidiaries; provided, however, that (i) if the Company is the obligor on such Indebtedness, such Indebtedness is expressly subordinate to the payment in full of all Obligations with respect to the Notes and (ii)(A) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than the Company or a Wholly Owned Restricted Subsidiary and (B) any sale or other transfer of any such Indebtedness to a 82 Person that is not either the Company or a Wholly Owned Restricted Subsidiary shall be deemed, in each case, to constitute an incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be; (f) Indebtedness in connection with one or more standby letters of credit, Guarantees, performance bonds or other reimbursement obligations, in each case, issued in the ordinary course of business and not in connection with the borrowing of money or the obtaining of advances or credit (other than advances or credit on open account, includible in current liabilities, for goods and services in the ordinary course of business and on terms and conditions which are customary in the Oil and Gas Business, and other than the extension of credit represented by such letter of credit, Guarantee or performance bond itself), not to exceed in the aggregate at any given time 5% of Total Assets; (g) the incurrence by the Company or any of its Restricted Subsidiaries of Indebtedness in connection with the acquisition of assets or a new Subsidiary; provided that such Indebtedness was incurred by the prior owner of such assets or such Subsidiary prior to such acquisition by the Company or one of its Restricted Subsidiaries and was not incurred in connection with, or in contemplation of, such acquisition by the Company or one of its Restricted Subsidiaries; and provided further that (i) the Fixed Charge Coverage Ratio for the Company's most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred would have been at least 2.5 to 1, determined on a pro forma basis as set forth in the definition of Fixed Charge Coverage Ratio and (ii) no Default or Event of Default shall have occurred and be continuing at the time such additional Indebtedness is incurred or would occur as a consequence of the incurrence of such additional Indebtedness; (h) Indebtedness under Interest Rate Hedging Agreements entered into for the purpose of limiting interest rate risks, provided that the obligations under such agreements are related to payment obligations on Indebtedness otherwise permitted by the terms of this covenant and that the aggregate notional principal amount of such agreements does not exceed the principal amount of the Indebtedness to which such agreements relate; (i) Indebtedness under Oil and Gas Hedging Contracts, provided that such contracts were entered into in the ordinary course of business for the purpose of limiting risks that arise in the ordinary course of business of the Company and its Subsidiaries; (j) the incurrence by the Company of Indebtedness not otherwise permitted to be incurred pursuant to this paragraph, provided that the aggregate principal amount (or accreted value, as applicable) of all Indebtedness incurred pursuant to this clause (j), together with all Permitted Refinancing Debt incurred pursuant to clause (k) of this paragraph in respect of Indebtedness previously incurred pursuant to this clause (j), does not exceed $15.0 million at any one time outstanding; (k) Permitted Refinancing Debt incurred in exchange for, or the net proceeds of which are used to refinance, extend, renew, replace, defease or refund, Indebtedness that was permitted by the Indenture to be incurred (including Indebtedness previously incurred pursuant to this clause (k)); (l) accounts payable or other obligations of the Company or any Subsidiary to trade creditors created or assumed by the Company or such Subsidiary in the ordinary course of business in connection with the obtaining of goods or services; (m) Indebtedness consisting of obligations in respect of purchase price adjustments, guarantees or indemnities in connection with the acquisition or disposition of assets; (n) the incurrence by the Company's Unrestricted Subsidiaries of Non-Recourse Debt, provided, however, that if any such Indebtedness ceases to be Non-Recourse Debt of an Unrestricted Subsidiary, such event shall be deemed to constitute an incurrence of Indebtedness by a Restricted Subsidiary of the Company; and (o) production imbalances that do not, at any one time outstanding, exceed two percent of the Total Assets of the Company. No Senior Subordinated Debt The Indenture will provide that (i) the Company will not incur, create, issue, assume, guarantee or otherwise become liable for any Indebtedness that is subordinate or junior in right of payment to any Senior Debt and senior in any respect in right of payment to the Notes and (ii) no Guarantor will directly or indirectly incur, create, issue, assume, guarantee or otherwise become liable for any Indebtedness that is subordinate or junior in right of payment to any Guarantees issued in respect of Senior Debt 83 and senior in any respect in right of payment to the Subsidiary Guarantees, provided, however, that the foregoing limitations will not apply to distinctions between categories of Indebtedness that exist by reason of any Liens arising or created in respect of some but not all such Indebtedness. Liens The Indenture will provide that the Company will not, and will not permit any of its Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien securing Indebtedness of any kind (other than Permitted Liens) upon any of its property or assets, now owned or hereafter acquired. Sale and Leaseback Transactions The Indenture will provide that the Company will not, and will not permit any of its Restricted Subsidiaries to, enter into any sale and leaseback transaction; provided that the Company may enter into a sale and leaseback transaction if (i) the Company could have (a) incurred Indebtedness in an amount equal to the Attributable Debt relating to such sale and leaseback transaction pursuant to the test set forth in the first paragraph of the covenant described above under the caption "--Incurrence of Additional Indebtedness and Issuance of Disqualified Stock" and (b) incurred a Lien to secure such Indebtedness pursuant to the covenant described above under the caption "--Liens," (ii) the gross cash proceeds of such sale and leaseback transaction are at least equal to the fair market value (as determined in good faith by a resolution the Board of Directors set forth in an Officers' Certificate delivered to the Trustee, which determination shall be conclusive evidence of compliance with this provision) of the property that is the subject of such sale and leaseback transaction and (iii) the transfer of assets in such sale and leaseback transaction is permitted by, and the Company applies the net proceeds of such transaction in compliance with, the covenant described above under the caption "--Repurchase at the Option of Holders--Asset Sales." Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries The Indenture will provide that the Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or otherwise cause or suffer to exist or become effective any encumbrance or restriction on the ability of any Restricted Subsidiary to (i)(x) pay dividends or make any other distributions to the Company or any of its Restricted Subsidiaries (1) on its Capital Stock or (2) with respect to any other interest or participation in, or measured by, its profits, or (y) pay any indebtedness owed to the Company or any of its Restricted Subsidiaries, (ii) make loans or advances to the Company or any of its Restricted Subsidiaries or (iii) transfer any of its properties or assets to the Company or any of its Restricted Subsidiaries, except for such encumbrances or restrictions existing under or by reason of (a) the Credit Agreement as in effect as of the date of the Indenture, and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings thereof or any other Credit Facility, provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements, refinancings or other Credit Facilities are no more restrictive with respect to such dividend and other payment restrictions than those contained in the Credit Agreement as in effect on the date of the Indenture, (b) the Indenture and the Notes, (c) applicable law, (d) any instrument governing Indebtedness or Capital Stock of a Person acquired by the Company or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except, in the case of Indebtedness, to the extent such Indebtedness was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person and its Subsidiaries, or the property or assets of the Person and its Subsidiaries, so acquired, provided that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the Indenture to be incurred, (e) by reason of customary non-assignment provisions in leases entered into in the ordinary course of business and consistent with past practices, 84 (f) purchase money obligations for property acquired in the ordinary course of business that impose restrictions of the nature described in clause (iii) above on the property so acquired, or (g) Permitted Refinancing Debt, provided that the restrictions contained in the agreements governing such Permitted Refinancing Debt are no more restrictive than those contained in the agreements governing the Indebtedness being refinanced. Merger, Consolidation, or Sale of Assets The Indenture will provide that the Company may not consolidate or merge with or into (whether or not the Company is the surviving corporation), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to another Person and the Company may not permit any of its Restricted Subsidiaries to enter into any such transaction or series of transactions if such transaction or series of transactions would, in the aggregate, result in a sale, assignment, transfer, lease, conveyance, or other disposition of all or substantially all of the properties or assets of the Company to another Person unless (i) the Company is the surviving corporation or the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made is a corporation organized or existing under the laws of the United States, any state thereof or the District of Columbia; (ii) the Person formed by or surviving any such consolidation or merger (if other than the Company) or to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made assumes all the obligations of the Company under the Notes and the Indenture pursuant to a supplemental indenture in a form reasonably satisfactory to the Trustee; (iii) immediately before and after giving effect to such transaction no Default or Event of Default exists; and (iv) except in the case of a merger of the Company with or into a Wholly Owned Subsidiary of the Company, the Company or the Person formed by or surviving any such consolidation or merger (if other than the Company), or to which such sale, assignment, transfer, lease, conveyance or other disposition shall have been made (A) will have Total Assets immediately after the transaction equal to or greater than the Total Assets of the Company immediately preceding the transaction and (B) will, at the time of such transaction and after giving pro forma effect thereto as if such transaction had occurred at the beginning of the applicable four-quarter period, be permitted to incur at least $1.00 of additional Indebtedness pursuant to the test set forth in the first paragraph of the covenant described above under the caption "--Incurrence of Indebtedness and Issuance of Preferred Stock." Transactions with Affiliates The Indenture will provide that the Company will not, and will not permit any of its Restricted Subsidiaries to, make any payment to, or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any of its Affiliates (each of the foregoing, an "Affiliate Transaction"), unless (i) such Affiliate Transaction is on terms that are no less favorable to the Company or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by the Company or such Restricted Subsidiary with an unrelated Person and (ii) the Company delivers to the Trustee (a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $1.0 million, a resolution of the Board of Directors set forth in an Officers' Certificate certifying that such Affiliate Transaction complies with clause (i) above and that such Affiliate Transaction has been approved by a majority of the members of the Board of Directors who are disinterested with respect to such Affiliate Transaction, which resolution shall be conclusive evidence of compliance with this provision, and (b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $5.0 million, an opinion as to the fairness to the Holders of such Affiliate Transaction from a financial point of view issued by an accounting, appraisal, engineering or investment banking firm of national standing; provided that the following shall not be 85 deemed Affiliate Transactions: (1) any sale of hydrocarbons or other mineral products or the entering into or performance of Oil and Gas Hedging Contracts, gas gathering, transportation or processing contracts or oil or natural gas marketing or exchange contracts, in each case, in the ordinary course of business, so long as the terms of any such transaction are approved by a majority of the members of the Board of Directors who are disinterested with respect to such transaction as being the most favorable of at least (x) two bids, quotes or proposals, at least one of which is from a Person that is not an Affiliate of the Company (in the event that the Company determines in good faith that it is able to obtain only two bids, quotes or proposals with respect to such transaction) or (y) three bids, quotes or proposals, at least two of which are from Persons that are not Affiliates of the Company (in all other circumstances), (2) the repayment of all amounts due in respect of the JEDI Debt, (3) the sale to an Affiliate of the Company of Equity Interests in the Company that do not constitute Disqualified Stock, (4) transactions contemplated by any employment agreement or other compensation plan or arrangement entered into by the Company or any of its Restricted Subsidiaries in the ordinary course of business and consistent with the past practice of the Company or such Restricted Subsidiary, including those described in this Prospectus under the caption "Executive Compensation and Other Information-- Employment Agreements," (5) transactions between or among the Company and/or its Restricted Subsidiaries, (6) Restricted Payments and Permitted Investments that are permitted by the provisions of the Indenture described above under the caption "--Restricted Payments," (7) the transactions described in this Prospectus under the caption "Certain Transactions" and (8) the payment of dividends on, or the redemption of, the JEDI Preferred Stock, in either case, to the extent otherwise permitted by the Indenture. Additional Subsidiary Guarantees The Indenture will provide that if the Company or any of its Subsidiaries shall acquire or create another Subsidiary after the date of the Indenture, then such newly acquired or created Subsidiary will be required to execute a Subsidiary Guarantee and deliver an opinion of counsel, in accordance with the terms of the Indenture, provided that the foregoing requirement shall not apply to any newly acquired or created Subsidiary that has been properly designated as an Unrestricted Subsidiary in accordance with the Indenture for so long as it continues to constitute an Unrestricted Subsidiary. Business Activities The Company and the Guarantors will not, and will not permit any Restricted Subsidiary to, engage in any material respect in any business other than the Oil and Gas Business. Reports Pursuant to Section 15(d) of the Exchange Act, upon effectiveness of the Registration Statement, the Company and the Guarantors will be required to file with the Commission reports on Form 10-K, Form 10-Q and Form 8-K for the remainder of 1996, at a minimum. In addition, the Company and the Guarantors have covenanted to file with the Commission, to the extent such filings are accepted by the Commission and whether or not the Company has a class of securities registered under the Exchange Act, the annual reports, quarterly reports and other documents that the Company and the Guarantors would be required to file if the Company were subject to Section 13 or 15 of the Exchange Act, in each case on or before the dates on which such reports and other documents would have been required to have been filed with the Commission if the Company had been subject to Section 13 or 15 of the Exchange Act beginning with the Company's fiscal quarter ended March 31, 1996. The Company will also be required (a) to file with the Trustee (with exhibits), and provide to each Holder of Notes (without exhibits), without cost to such Holder, copies of such reports and documents within 15 days after the date on which the Company files such reports and documents with the Commission or the date on which the Company would be required to file such reports and documents if the Company were so required and (b) if filing such reports and documents with the Commission is not accepted by 86 the Commission or is prohibited under the Exchange Act, to supply at the Company's cost copies of such reports and documents (including any exhibits thereto) to any Holder of Notes promptly upon written request. In addition, the Company and the Guarantors have agreed that, for so long as any Notes remain outstanding, they will furnish to the Holders and to prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act. EVENTS OF DEFAULT AND REMEDIES The Indenture will provide that each of the following constitutes an Event of Default: (i) default for 30 days in the payment when due of interest on the Notes (whether or not prohibited by the subordination provisions of the Indenture); (ii) default in payment when due of the principal of or premium, if any, on the Notes (whether or not prohibited by the subordination provisions of the Indenture); (iii) failure by the Company for 30 days after notice from the Trustee or the Holders of at least 25% in aggregate principal amount of the Notes then outstanding to comply with the provisions described under the captions "--Repurchase at the Option of Holders--Change of Control," "-- Repurchase at the Option of Holders--Asset Sales," "--Certain Covenants-- Restricted Payments," "--Certain Covenants--Incurrence of Indebtedness and Issuance of Preferred Stock" or "--Certain Covenants--Merger, Consolidation, or Sale of Assets"; (iv) failure by the Company for 60 days after notice from the Trustee or the Holders of at least 25% in aggregate principal amount of the Notes then outstanding to comply with any of its other agreements in the Indenture or the Notes; (v) except as permitted by the Indenture, any Subsidiary Guarantee of a Significant Subsidiary shall be held in any judicial proceeding to be unenforceable or invalid or shall cease for any reason to be in full force and effect or any Guarantor that is a Significant Subsidiary, or any Person acting on behalf of any such Guarantor, shall deny or disaffirm its obligations under its Subsidiary Guarantee; (vi) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries) whether such Indebtedness or Guarantee now exists, or is created after the date of the Indenture, which default (a) is caused by a failure to pay principal of or premium, if any, or interest on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a "Payment Default") or (b) results in the acceleration of such Indebtedness prior to its express maturity and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there is then existing a Payment Default or the maturity of which has been so accelerated, aggregates $10.0 million or more; (vii) failure by the Company or any of its Restricted Subsidiaries to pay final, non-appealable judgments aggregating in excess of $5.0 million, which judgments remain unpaid or undischarged for a period of 60 days; and (viii) certain events of bankruptcy or insolvency with respect to the Company or any of its Restricted Subsidiaries that constitute a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary. If any Event of Default occurs and is continuing, the Trustee or the Holders of at least 25% in principal amount of the then outstanding Notes may declare all the Notes to be due and payable immediately. Notwithstanding the foregoing, in the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to the Company, any Restricted Subsidiary that constitutes a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all outstanding Notes will become due and payable without further action or notice. Holders of the Notes may not enforce the Indenture or the Notes except as provided in the Indenture. Subject to certain limitations, Holders of a majority in principal amount of the then outstanding Notes may direct the Trustee in its exercise of any trust or power. The Trustee may withhold from Holders of the Notes notice of any continuing Default or Event of Default (except a Default or Event of Default relating to the payment of principal or interest) if it determines that withholding notice is in their interest. 87 In the case of any Event of Default occurring by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Company with the intention of avoiding payment of the premium that the Company would have had to pay if the Company then had elected to redeem the Notes pursuant to the optional redemption provisions of the Indenture, an equivalent premium shall also become and be immediately due and payable to the extent permitted by law upon the acceleration of the Notes. If an Event of Default occurs prior to April 1, 2001 by reason of any willful action (or inaction) taken (or not taken) by or on behalf of the Company with the intention of avoiding the prohibition on redemption of the Notes prior to April 1, 2001, then the premium specified in the Indenture shall also become immediately due and payable to the extent permitted by law upon the acceleration of the Notes. The Holders of a majority in aggregate principal amount of the Notes then outstanding by notice to the Trustee may on behalf of the Holders of all of the Notes waive any existing Default or Event of Default and its consequences under the Indenture except a continuing Default or Event of Default in the payment of interest, premium or Liquidated Damages, if any, on, or the principal of, the Notes. The Company is required to deliver to the Trustee annually a statement regarding compliance with the Indenture, and the Company is required, within five business days of becoming aware of any Default or Event of Default, to deliver to the Trustee a statement specifying such Default or Event of Default. NO PERSONAL LIABILITY OF DIRECTORS, OFFICERS, EMPLOYEES AND STOCKHOLDERS No director, officer, employee, incorporator or stockholder of the Company, as such, shall have any liability for any obligations of the Company under the Notes or the Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder of Notes, by accepting a Note, waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the Commission that such a waiver is against public policy. LEGAL DEFEASANCE AND COVENANT DEFEASANCE The Company may, at its option and at any time, elect to have all of its obligations discharged with respect to the outstanding Notes ("Legal Defeasance") except for (i) the rights of Holders of outstanding Notes to receive payments in respect of the principal of, premium, if any, interest and Liquidated Damages, if any, on such Notes when such payments are due from the trust referred to below, (ii) the Company's obligations with respect to the Notes concerning issuing temporary Notes, registration of Notes, mutilated, destroyed, lost or stolen Notes and the maintenance of an office or agency for payment and money for security payments held in trust, (iii) the rights, powers, trusts, duties and immunities of the Trustee, and the Company's obligations in connection therewith and (iv) the Legal Defeasance provisions of the Indenture. In addition, the Company may, at its option and at any time, elect to have the obligations of the Company released with respect to certain covenants that are described in the Indenture ("Covenant Defeasance") and thereafter any omission to comply with such obligations shall not constitute a Default or Event of Default with respect to the Notes. In the event Covenant Defeasance occurs, certain events (not including non-payment, bankruptcy, receivership, rehabilitation and insolvency events) described under "Events of Default" will no longer constitute an Event of Default with respect to the Notes. In order to exercise either Legal Defeasance or Covenant Defeasance, (i) the Company or the Guarantors must irrevocably deposit with the Trustee, in trust, for the benefit of the Holders of the Notes, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, premium, if any, interest and Liquidated Damages, if any, on the outstanding Notes on the stated maturity or on the applicable redemption date, as the case may be, 88 and the Company or the Guarantors must specify whether the Notes are being defeased to maturity or to a particular redemption date; (ii) in the case of Legal Defeasance, the Company or the Guarantors shall have delivered to the Trustee an opinion of counsel in the United States reasonably acceptable to the Trustee confirming that (A) the Company or the Guarantors has received from, or there has been published by, the Internal Revenue Service a ruling or (B) since the date of the Indenture, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel shall confirm that, the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred; (iii) in the case of Covenant Defeasance, the Company or the Guarantors shall have delivered to the Trustee an opinion of counsel in the United States reasonably acceptable to the Trustee confirming that the Holders of the outstanding Notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred; (iv) no Default or Event of Default shall have occurred and be continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit) or insofar as Events of Default from bankruptcy or insolvency events are concerned, at any time in the period ending on the 91st day after the date of deposit; (v) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under any material agreement or instrument (other than the Indenture) to which the Company or any of its Restricted Subsidiaries is a party or by which the Company or any of its Restricted Subsidiaries is bound; (vi) the Company or the Guarantors must have delivered to the Trustee an opinion of counsel to the effect that after the 91st day following the deposit, the trust funds will not be subject to the effect of any applicable bankruptcy, insolvency, reorganization or similar laws affecting creditors' rights generally; (vii) the Company or the Guarantors must deliver to the Trustee an Officers' Certificate stating that the deposit was not made by the Company or the Guarantors, as applicable, with the intent of preferring the Holders of Notes over the other creditors of the Company or the Guarantors, as applicable, with the intent of defeating, hindering, delaying or defrauding creditors of the Company or the Guarantors, as applicable, or others; and (viii) the Company must deliver to the Trustee an Officers' Certificate and an opinion of counsel, each stating that all conditions precedent provided for relating to the Legal Defeasance or the Covenant Defeasance have been complied with. TRANSFER AND EXCHANGE A Holder may transfer or exchange Notes in accordance with the Indenture. The Registrar and the Trustee may require a Holder, among other things, to furnish appropriate endorsements and transfer documents and the Company may require a Holder to pay any taxes and fees required by law or permitted by the Indenture. The Company is not required to transfer or exchange any Note selected for redemption. Also, the Company is not required to transfer or exchange any Note for a period of 15 days before a selection of Notes to be redeemed. The registered Holder of a Note will be treated as the owner of it for all purposes. AMENDMENT, SUPPLEMENT AND WAIVER Except as provided in the next two succeeding paragraphs, the Indenture or the Notes may be amended or supplemented with the consent of the Holders of at least a majority in principal amount of the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes), and any existing default or compliance with any provision of the Indenture or the Notes may be waived with the consent of the Holders of a majority in principal amount of the then outstanding Notes (including consents obtained in connection with a tender offer or exchange offer for Notes). 89 Without the consent of each Holder affected, an amendment or waiver may not (with respect to any Notes held by a non-consenting Holder): (i) reduce the principal amount of Notes whose Holders must consent to an amendment, supplement or waiver, (ii) reduce the principal of or change the fixed maturity of any Note or alter the provisions with respect to the redemption of the Notes (other than provisions relating to the covenants described above under the caption "--Repurchase at the Option of Holders"), (iii) reduce the rate of or change the time for payment of interest or Liquidated Damages on any Note, (iv) waive a Default or Event of Default in the payment of principal of or premium, if any, or interest or Liquidated Damages, if any, on the Notes (except a rescission of acceleration of the Notes by the Holders of at least a majority in aggregate principal amount of the Notes and a waiver of the payment default that resulted from such acceleration), (v) make any Note payable in money other than that stated in the Notes, (vi) make any change in the provisions of the Indenture relating to waivers of past Defaults or the rights of Holders of Notes to receive payments of principal of or premium, if any, or interest or Liquidated Damages, if any, on the Notes, (vii) waive a redemption payment with respect to any Note (other than a payment required by one of the covenants described above under the caption "--Repurchase at the Option of Holders") or (viii) make any change in the foregoing amendment and waiver provisions. Without the consent of at least 66 2/3% in aggregate principal amount of the Notes then outstanding (including consents obtained in connection with a purchase of, or tender offer or exchange offer for, Notes), no waiver or amendment to the Indenture may make any change in the provisions described above under the captions "--Repurchase at the Option of Holders--Change of Control" and "--Repurchase at the Option of Holders--Assets Sales" that adversely affect the rights of any Holder of Notes. In addition, any amendment to the provisions of Article 10 of the Indenture (which relate to subordination) will require the consent of the Holders of at least 66 2/3% in aggregate principal amount of the Notes then outstanding if such amendment would adversely affect the rights of Holders of Notes. Notwithstanding the foregoing, without the consent of any Holder of Notes, the Company and the Trustee may amend or supplement the Indenture or the Notes to cure any ambiguity, defect or inconsistency, to provide for uncertificated Notes in addition to or in place of certificated Notes, to provide for the assumption of the Company's obligations to Holders of Notes in the case of a merger or consolidation, to make any change that would provide any additional rights or benefits to the Holders of Notes or that does not adversely affect the legal rights under the Indenture of any such Holder, or to comply with requirements of the Commission in order to effect or maintain the qualification of the Indenture under the Trust Indenture Act. CONCERNING THE TRUSTEE The Indenture contains certain limitations on the rights of the Trustee, should it become a creditor of the Company, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the Commission for permission to continue or resign. The Trustee is a lender to the Company under the Credit Agreement and is an affiliate of Chemical Securities Inc. See "Description of Other Indebtedness--Credit Agreement" and "Offer and Resale." The Holders of a majority in principal amount of the then outstanding Notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the Trustee, subject to certain exceptions. The Indenture provides that in case an Event of Default shall occur (which shall not be cured), the Trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the Trustee will be under no obligation to exercise any of its rights or powers under the Indenture at the request of any Holder of Notes, unless such Holder shall have offered to the Trustee security and indemnity satisfactory to it against any loss, liability or expense. 90 BOOK-ENTRY, DELIVERY AND FORM The Notes to be issued as set forth herein will initially be issued in the form of one or more permanent global certificates in definitive, fully- registered form ("Global Note"). Each Global Note will be deposited on the date of the closing of the exchange of the Private Notes for the Exchange Notes offered hereby (the "Closing Date") with, or on behalf of, DTC and registered in the name of Cede & Co., as nominee of the Depositary (such nominee being referred to herein as the "Global Note Holder"). The Depositary is a limited-purpose trust company that was created to hold securities for its participating organizations (collectively, the "Participants" or the "Depositary's Participants") and to facilitate the clearance and settlement of transactions in such securities between Participants through electronic book-entry changes in accounts of its Participants. The Depositary's Participants include securities brokers and dealers (including the Initial Purchasers), banks and trust companies, clearing corporations and certain other organizations. Access to the Depositary's system is also available to other entities such as banks, brokers, dealers and trust companies (collectively, the "Indirect Participants" or the "Depositary's Indirect Participants") that clear through or maintain a custodial relationship with a Participant, either directly or indirectly. Persons who are not Participants may beneficially own securities held by or on behalf of the Depositary only thorough the Depositary's Participants or the Depositary's Indirect Participants. The Company expects that pursuant to procedures established by the Depositary (i) upon deposit of the Global Note, the Depositary will credit the accounts of Participants designated by the Initial Purchasers with portions of the principal amount of the Global Note and (ii) ownership of the Notes evidenced by the Global Note will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by the Depositary (with respect to the interests of the Depositary's Participants), the Depositary's Participants and the Depositary's Indirect Participants. Prospective purchasers are advised that the laws of some states require that certain persons take physical delivery in definitive form of securities that they own. Consequently, the ability to transfer Notes evidenced by the Global Note will be limited to such extent. So long as the Global Note Holder is the registered owner of any Notes, the Global Note Holder will be considered the sole Holder under the Indenture of any Notes evidenced by the Global Note. Beneficial owners of Notes evidenced by the Global Note will not be considered the owners or Holders thereof under the Indenture for any purpose, including with respect to the giving of any directions, instructions or approvals to the Trustee thereunder. Neither the Company nor the Trustee will have any responsibility or liability for any aspect of the records of the Depositary or for maintaining, supervising or reviewing any records of the Depositary relating to the Notes. Payments in respect of the principal of, premium, if any, and interest on any Notes registered in the name of the Global Note Holder on the applicable record date will be payable by the Trustee to or at the direction of the Global Note Holder in its capacity as the registered Holder under the Indenture. Under the terms of the Indenture, the Company and the Trustee may treat the persons in whose names Notes, including the Global Note, are registered as the owners thereof for the purpose of receiving such payments. Consequently, neither the Company nor the Trustee has or will have any responsibility or liability for the payment of such amounts to beneficial owners of Notes. The Company believes, however, that it is currently the policy of the Depositary to immediately credit the accounts of the relevant Participants with such payments, in amounts proportionate to their respective holdings of beneficial interests in the relevant security as shown on the records of the Depositary. Payments by the Depositary's Participants and the Depositary's Indirect Participants to the beneficial owners of Notes will be governed by standing instructions and customary practice and will be the responsibility of the Depositary's Participants or the Depositary's Indirect Participants. 91 DTC has advised the Company that neither DTC nor Cede & Co. will consent or vote with respect to the Notes. Under its usual procedures, DTC mails an omnibus proxy to the issuer as soon as possible after the record date. The omnibus proxy assigns Cede & Co.'s consenting or voting rights to those Participants to whose accounts the Notes are credited on the record date (identified in a listing attached to the omnibus proxy). DTC may discontinue providing its services as securities depository with respect to the Notes at any time. Neither the Company, the Trustee nor any registrar or paying agent will have any responsibility for the performance by DTC or its Participants or Indirect Participants of their respective obligations under the rules and procedures governing their operations. The information in this section concerning DTC and DTC's book-entry system has been obtained from sources that the Company believes to be reliable, but the Company takes no responsibility for the accuracy thereof. Certificated Securities Subject to certain conditions, any person having a beneficial interest in the Global Note may, upon request to the Trustee, exchange such beneficial interest for Notes in the form of Certificated Securities. Upon any such issuance, the Trustee is required to register such Certificated Securities in the name of, and cause the same to be delivered to, such person or persons (or the nominee of any thereof). In addition, if (i) the Depositary notifies the Company that the Depositary is no longer willing or able to act as a depositary and the Company is unable to locate a qualified successor within 90 days or (ii) the Company, at its option, notifies the Trustee in writing that it elects to cause the issuance of Notes in the form of Certificated Securities under the Indenture, then, upon surrender by the Global Note Holder of its Global Note, Notes in such form will be issued to each person that the Global Note Holder and the Depositary identify as being the beneficial owner of the related Notes. Neither the Company nor the Trustee will be liable for any delay by the Global Note Holder or the Depositary in identifying the beneficial owners of Notes and the Company and the Trustee may conclusively rely on, and will be protected in relying on, instructions from the Global Note Holder or the Depositary for all purposes. Same-Day Settlement and Payment The Indenture will require that payments in respect of the Notes represented by the Global Note (including principal, premium, if any, and interest) be made by wire transfer of immediately available funds to the accounts specified by the Global Note Holder. With respect to Certificated Securities, the Company will make all payments of principal, premium, if any, and interest, by wire transfer of immediately available funds to the accounts specified by the Holders thereof that hold at least $5.0 million in aggregate principal amount of the Notes or, if no such account is specified or if a Holder holds less than $5.0 million in aggregate principal amount of the Notes, by mailing a check to each such Holder's registered address. The Notes represented by the Global Note are expected to be eligible to trade in the Depositary's Same-Day Funds Settlement System, and any permitted secondary market trading activity in such Notes will, therefore, be required by the Depositary to be settled in immediately available funds. CERTAIN DEFINITIONS Set forth below are certain defined terms used in the Indenture. Reference is made to the Indenture for a full disclosure of all such terms, as well as any other capitalized terms used herein for which no definition is provided. "Acquired Debt" means, with respect to any specified Person, (i) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such 92 specified Person, including, without limitation, Indebtedness incurred in connection with, or in contemplation of, such other Person merging with or into or becoming a Subsidiary of such specified Person, and (ii) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person. "Affiliate" of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, "control" (including, with correlative meanings, the terms "controlling," "controlled by" and "under common control with"), as used with respect to any Person, shall mean the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise; provided that beneficial ownership of 10% or more of the voting securities of a Person shall be deemed to be control. "Asset Sale" means (i) the sale, lease, conveyance or other disposition (but excluding the creation of a Lien) of any assets including, without limitation, by way of a sale and leaseback (provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of the Company and its Subsidiaries taken as a whole will be governed by the provisions of the Indenture described above under the caption "--Repurchase at the Option of Holders--Change of Control" and/or the provisions described above under the caption "--Certain Covenants--Merger, Consolidation, or Sale of Assets" and not by the provisions described above under "--Repurchase at the Option of Holders--Asset Sales"), and (ii) the issue or sale by the Company or any of its Restricted Subsidiaries of Equity Interests of any of the Company's Subsidiaries (including the sale by a Restricted Subsidiary of Equity Interests in an Unrestricted Subsidiary), in the case of either clause (i) or (ii), whether in a single transaction or a series of related transactions (a) that have a fair market value in excess of $2.0 million or (b) for net proceeds in excess of $2.0 million. Notwithstanding the foregoing, the following shall not be deemed to be Asset Sales: (i) a transfer of assets by the Company to a Wholly Owned Subsidiary of the Company or by a Wholly Owned Subsidiary of the Company to the Company or to another Wholly Owned Subsidiary of the Company, (ii) an issuance of Equity Interests by a Wholly Owned Subsidiary of the Company to the Company or to another Wholly Owned Subsidiary of the Company, (iii) a Restricted Payment or Permitted Investment that is permitted by the covenant described above under the caption "--Certain Covenants--Restricted Payments," (iv) the sale or transfer (whether or not in the ordinary course of business) of oil and gas properties or direct or indirect interests in real property, provided that at the time of such sale or transfer such properties do not have associated with them any proved reserves, (v) the abandonment, farm- out, lease or sublease of developed or undeveloped oil and gas properties in the ordinary course of business, (vi) the trade or exchange by the Company or any Subsidiary of the Company of any oil and gas property owned or held by the Company or such Subsidiary for any oil and gas property owned or held by another Person or (vii) the sale or transfer of hydrocarbons or other mineral products or surplus or obsolete equipment in the ordinary course of business. "Attributable Debt" in respect of a sale and leaseback transaction means, at the time of determination, the present value (discounted at the rate of interest implicit in such transaction, determined in accordance with GAAP) of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction (including any period for which such lease has been extended or may, at the option of the lessor, be extended). "Borrowing Base" means, as of any date, the aggregate amount of borrowing availability as of such date under all Credit Facilities that determine availability on the basis of a borrowing base or other asset-based calculation, provided that in no event shall the Borrowing Base exceed $250.0 million. "Capital Lease Obligation" means, at the time any determination thereof is to be made, the amount of the liability in respect of a capital lease that would at such time be required to be capitalized on a balance sheet in accordance with GAAP. 93 "Capital Stock" means (i) in the case of a corporation, corporate stock, (ii) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock, (iii) in the case of a partnership, partnership interests (whether general or limited) and (iv) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person. "Cash Equivalents" means (i) United States dollars, (ii) securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality thereof having maturities of not more than six months from the date of acquisition, (iii) certificates of deposit and eurodollar time deposits with maturities of six months or less from the date of acquisition, bankers' acceptances with maturities not exceeding six months and overnight bank deposits, in each case with any lender party to the Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $500 million and a Thompson Bank Watch Rating of "B" or better, (iv) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (ii) and (iii) above entered into with any financial institution meeting the qualifications specified in clause (iii) above and (v) commercial paper having a rating of at least P1 from Moody's Investors Service, Inc. and a rating of at least A1 from Standard & Poor's Corporation. "Change of Control" means the occurrence of any of the following: (i) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any "person" (as such term is used in Section 13(d)(3) of the Exchange Act) other than a Person controlled by the Principals, (ii) the adoption of a plan relating to the liquidation or dissolution of the Company, (iii) the consummation of any transaction (including, without limitation, any purchase, sale, acquisition, disposition, merger or consolidation) the result of which is that (x) the Principals cease to "beneficially own" (as such term is described in Rule 13d-3 and Rule 13d-5 under the Exchange Act), in the aggregate, at least 33% of the aggregate voting power of all classes of Capital Stock of the Company having the right to elect directors under ordinary circumstances or (y) any "person" (as defined above) becomes the "beneficial owner" (as such term is defined in Rule 13d-3 and Rule 13d-5 under the Exchange Act) of more of the aggregate voting power of all classes of Capital Stock of the Company having the right to elect directors under ordinary circumstances than is owned at that time by the Principals in the aggregate or (iv) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors. "Commission" means the Securities and Exchange Commission. "Consolidated Cash Flow" means, with respect to any Person for any period, the Consolidated Net Income of such Person for such period plus (i) an amount equal to any extraordinary loss plus any net loss realized in connection with an Asset Sale (together with any related provision for taxes), to the extent such losses were deducted in computing such Consolidated Net Income, plus (ii) provision for taxes based on income or profits of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was included in computing such Consolidated Net Income, plus (iii) consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (including, without limitation, amortization of original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers' acceptance financings, and net payments (if any) pursuant to Interest Rate Hedging Agreements), to the extent that any such expense was deducted in computing such Consolidated Net Income, plus (iv) depreciation, depletion and amortization expenses (including amortization of goodwill and other intangibles but excluding amortization of prepaid cash expenses that were paid in a prior 94 period) for such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion and amortization expenses were deducted in computing such Consolidated Net Income, plus (v) other non-cash charges (excluding any such non-cash charge to the extent that it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such other non-cash charges were deducted in computing such Consolidated Net Income, in each case, on a consolidated basis and determined in accordance with GAAP. Notwithstanding the foregoing, the provision for taxes on the income or profits of, and the depreciation, depletion and amortization and other non-cash charges and expenses of, a Restricted Subsidiary of the referent Person shall be added to Consolidated Net Income to compute Consolidated Cash Flow only to the extent (and in same proportion) that the Net Income of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior governmental approval (that has not been obtained), and without direct or indirect restriction pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders. "Consolidated Net Income" means, with respect to any Person for any period, the aggregate of the Net Income of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP; provided that (i) the Net Income (but not loss) of any Person that is not a Restricted Subsidiary or that is accounted for by the equity method of accounting shall be included only to the extent of the amount of dividends or distributions paid in cash to the referent Person or a Wholly Owned Restricted Subsidiary thereof, (ii) the Net Income of any Restricted Subsidiary shall be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that Net Income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, (iii) the Net Income of any Person acquired in a pooling of interests transaction for any period prior to the date of such acquisition shall be excluded, (iv) the cumulative effect of a change in accounting principles shall be excluded and (v) the Net Income of any Unrestricted Subsidiary shall be excluded, whether or not distributed to the Company or one of its Subsidiaries. "Consolidated Net Working Capital" of any Person as of any date of determination means the difference (shown on the balance sheet of such Person and its consolidated Subsidiaries determined on a consolidated basis in accordance with GAAP as of the end of the most recent fiscal quarter of such Person for which internal financial statements are available) between (i) all current assets of such Person and its consolidated Subsidiaries and (ii) all current liabilities of such Person and its consolidated Subsidiaries except the current portion of long-term Indebtedness. "Continuing Directors" means, as of any date of determination, any member of the Board of Directors of the Company who (i) was a member of such Board of Directors on the date of the Indenture or (ii) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board at the time of such nomination or election. "Credit Agreement" means that certain Credit Agreement, dated as of February 14, 1996, by and among the Company and NationsBank of Texas, N.A., as agent and as a lender, and certain other institutions, as lenders, providing for up to $250.0 million of Indebtedness, including any related notes, guarantees, collateral documents, instruments and agreements executed in connection therewith, and in each case as amended, restated, modified, renewed, refunded, replaced or refinanced, in whole or in part, from time to time. 95 "Credit Facilities" means, with respect to the Company, one or more debt facilities (including, without limitation, the Credit Agreement) or commercial paper facilities with banks or other institutional lenders providing for revolving credit loans, term loans, production payments, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time. Indebtedness under Credit Facilities outstanding on the date on which Notes are first issued and authenticated under the Indenture shall be deemed to have been incurred on such date in reliance on the exception provided by clause (b) of the definition of Permitted Indebtedness. "Default" means any event that is or with the passage of time or the giving of notice or both would be an Event of Default. "Designated Senior Debt" means (i) the Credit Agreement and (ii) any other Senior Debt permitted under the Indenture the principal amount of which is $25 million or more and that has been designated by the Company as "Designated Senior Debt." "Disqualified Stock" means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the Holder thereof, in whole or in part, on or prior to the date that is 91 days after the date on which the Notes mature, provided that the JEDI Preferred Stock shall not constitute Disqualified Stock. "Dollar-Denominated Production Payments" means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith. "Equity Interests" means Capital Stock and all warrants, options or other rights to acquire Capital Stock (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock). "Existing Indebtedness" means up to $3.0 million in aggregate principal amount of Indebtedness of the Company and its Subsidiaries (other than Indebtedness under the Credit Facilities and the JEDI Debt) in existence on the date of the Indenture, until such amounts are repaid. "Fixed Charges" means, with respect to any Person for any period, the sum of (i) the consolidated interest expense of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (including, without limitation, amortization of original issue discount, non-cash interest payments, the interest component of any deferred payment obligations, the interest component of all payments associated with Capital Lease Obligations, imputed interest with respect to Attributable Debt, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers' acceptance financings, and net payments (if any) pursuant to Interest Rate Hedging Agreements) and (ii) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period, and (iii) any interest expense on Indebtedness of another Person that is Guaranteed by such Person or any of its Restricted Subsidiaries or secured by a Lien on assets of such Person or any of its Restricted Subsidiaries (whether or not such Guarantee or Lien is called upon) and (iv) the product of (a) all cash dividend payments (and non-cash dividend payments in the case of a Person that is a Restricted Subsidiary) on any series of preferred stock of such Person or any of its Restricted Subsidiaries, times (b) a fraction, the numerator of which is one and the denominator of which is one minus the then current combined federal, state and local statutory tax rate of such Person, expressed as a decimal, in each case, on a consolidated basis and in accordance with GAAP. 96 "Fixed Charge Coverage Ratio" means with respect to any Person for any period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the Company or any of its Restricted Subsidiaries incurs, assumes, Guarantees or redeems any Indebtedness (other than revolving credit borrowings) or issues preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated but prior to the date on which the calculation of the Fixed Charge Coverage Ratio is made (the "Calculation Date"), then the Fixed Charge Coverage Ratio shall be calculated giving pro forma effect to such incurrence, assumption, Guarantee or redemption of Indebtedness, or such issuance or redemption of preferred stock, as if the same had occurred at the beginning of the applicable four-quarter reference period. In addition, for purposes of making the computation referred to above, (i) acquisitions that have been made by the Company or any of its Restricted Subsidiaries, including through mergers or consolidations and including any related financing transactions, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date (including, without limitation, any acquisition to occur on the Calculation Date) shall be deemed to have occurred on the first day of the four-quarter reference period and Consolidated Cash Flow for such reference period shall be calculated without giving effect to clause (iii) of the proviso set forth in the definition of Consolidated Net Income, (ii) the net proceeds of Indebtedness incurred or Disqualified Stock issued by the Company pursuant to the first paragraph of the covenant described under the caption "--Certain Covenants--Incurrence of Indebtedness and Issuance of Preferred Stock" during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date shall be deemed to have been received by the Company on the first day of the four-quarter reference period and applied to its intended use on such date, (iii) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, shall be excluded, and (iv) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses disposed of prior to the Calculation Date, shall be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the referent Person or any of its Restricted Subsidiaries following the Calculation Date. "GAAP" means generally accepted accounting principles set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as have been approved by a significant segment of the accounting profession, which are in effect from time to time. "Guarantee" means a guarantee (other than by endorsement of negotiable instruments for collection in the ordinary course of business), direct or indirect, in any manner (including, without limitation, letters of credit and reimbursement agreements in respect thereof), of all or any part of any Indebtedness. "Guarantors" means each of (i) Diamond Energy Operating Company, Taurus Energy Corp. and Electra Resources, Inc. and (ii) any other subsidiary of the Company that executes a Subsidiary Guarantee in accordance with the provisions of the Indenture, and, in each case, their respective successors and assigns. "Indebtedness" means, with respect to any Person, without duplication, (a) any indebtedness of such Person, whether or not contingent, (i) in respect of borrowed money, (ii) evidenced by bonds, notes, debentures or similar instruments, (iii) evidenced by letters of credit (or reimbursement agreements in respect thereof) or banker's acceptances, (iv) representing Capital Lease Obligations, (v) representing the balance deferred and unpaid of the purchase price of any property, except any such balance that constitutes an accrued expense or trade payable, (vi) representing any obligations in respect of Interest Rate Hedging Agreements or Oil and Gas Hedging Contracts, (vii) in respect of 97 obligations to pay rent or other amounts with respect to a sale and leaseback transaction to which such Person is a party, and (viii) in respect of any Production Payment, (b) all indebtedness of others secured by a Lien on any asset of such Person (whether or not such indebtedness is assumed by such Person), (c) obligations of such Person in respect of production imbalances and (d) to the extent not otherwise included in the foregoing, the Guarantee by such Person of any indebtedness of any other Person, provided that the indebtedness described in clauses (a)(i), (ii), (iv) and (v) shall be included in this definition of Indebtedness only if, and to the extent that, the indebtedness described in such clauses would appear as a liability upon a balance sheet of such Person prepared in accordance with GAAP. "Interest Rate Hedging Agreements" means, with respect to any Person, the obligations of such Person under (i) interest rate swap agreements, interest rate cap agreements and interest rate collar agreements and (ii) other agreements or arrangements designed to protect such Person against fluctuations in interest rates. "Investments" means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the forms of direct or indirect loans (including guarantees of Indebtedness or other obligations, but excluding trade credit and other ordinary course advances customarily made in the oil and gas industry), advances or capital contributions (excluding commission, travel and similar advances to officers and employees made in the ordinary course of business), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities, together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that the following shall not constitute Investments: (i) an acquisition of assets, Equity Interests or other securities by the Company for consideration consisting of common equity securities of the Company, (ii) Interest Rate Hedging Agreements entered into in accordance with the limitations set forth in clause (h) of the second paragraph of the covenant described under the caption "--Certain Covenants--Incurrence of Indebtedness and Issuance of Disqualified Stock" and (iii) Oil and Gas Hedging Agreements entered into in accordance with the limitations set forth in clause (i) of the second paragraph of the covenant described under the caption "--Certain Covenants--Incurrence of Indebtedness and Issuance of Disqualified Stock." If the Company or any Subsidiary of the Company sells or otherwise disposes of any Equity Interests of any direct or indirect Subsidiary of the Company such that, after giving effect to any such sale or disposition, such Person is no longer a Subsidiary of the Company, the Company shall be deemed to have made an Investment on the date of any such sale or disposition equal to the fair market value of the Equity Interests of such Subsidiary not sold or disposed of. "JEDI Preferred Stock" means all outstanding shares of the Company's 15% Cumulative Preferred Stock held by JEDI as in effect on the date of the Indenture, including any shares of the Company's 15% Cumulative Preferred Stock issued thereafter as payment of accrued dividends thereon in accordance with the terms thereof as in effect on the date of the Indenture. "Lien" means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law (including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction). "Liquid Securities" means securities (i) of an issuer that is not an Affiliate of the Company and (ii) that are publicly traded on the New York Stock Exchange, the American Stock Exchange or the Nasdaq National Market; provided, that securities meeting the requirements of clauses (i) and (ii) above shall be treated as Liquid Securities from the date of receipt thereof until and only until the earlier of (x) the date on which such securities are sold or exchanged for cash or cash equivalents and 98 (y) 180 days following the date of the closing of the Asset Sale in connection with which such Liquid Securities were received. In the event such securities are not sold or exchanged for cash or cash equivalents within such 180-day period, for purposes of determining whether the transaction pursuant to which the Company or a Restricted Subsidiary received the securities was in compliance with the covenant described under the caption "--Repurchase at the Option of Holders--Asset Sales," such securities shall be deemed not to have been Liquid Securities at any time. "Net Income" means, with respect to any Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends, excluding, however, (i) any gain (but not loss), together with any related provision for taxes on such gain (but not loss), realized in connection with (a) any Asset Sale (including, without limitation, dispositions pursuant to sale and leaseback transactions) or (b) the disposition of any securities by such Person or any of its Restricted Subsidiaries or the extinguishment of any Indebtedness of such Person or any of its Restricted Subsidiaries and (ii) any extraordinary or nonrecurring gain (but not loss), together with any related provision for taxes on such extraordinary or nonrecurring gain (but not loss). "Net Proceeds" means the aggregate cash proceeds received by the Company or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without limitation, any cash received upon the sale or other disposition of Liquid Securities or any other any non-cash consideration received in any Asset Sale, but excluding cash amounts placed in escrow, until such amounts are released to the Company), net of the direct costs relating to such Asset Sale (including, without limitation, legal, accounting and investment banking fees, and sales commissions) and any relocation expenses incurred as a result thereof, taxes paid or payable as a result thereof (after taking into account any available tax credits or deductions and any tax sharing arrangements), amounts required to be applied to the repayment of Indebtedness (other than Indebtedness under any Credit Facility) secured by a Lien on the asset or assets that were the subject of such Asset Sale and any reserve for adjustment in respect of the sale price of such asset or assets established in accordance with GAAP and any reserve established for future liabilities. "Non-Recourse Debt" means Indebtedness (i) as to which neither the Company nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable (as a guarantor or otherwise), or (c) constitutes the lender; and (ii) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness of the Company or any of its Restricted Subsidiaries to declare a default on such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; and (iii) as to which the lenders have been notified in writing that they will not have any recourse to the stock or assets of the Company or any of its Restricted Subsidiaries. "Obligations" means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness. "Oil and Gas Business" means (i) the acquisition, exploration, development, operation and disposition of interests in oil, gas and other hydrocarbon properties, (ii) the gathering, marketing, treating, processing, storage, selling and transporting of any production from such interests or properties, (iii) any business relating to exploration for or development, production, treatment, processing, storage, transportation or marketing of oil, gas and other minerals and products produced in association therewith and (iv) any activity that is ancillary to or necessary or appropriate for the activities described in clauses (i) through (iii) of this definition. 99 "Oil and Gas Hedging Contracts" means any oil and gas purchase or hedging agreement, and other agreement or arrangement, in each case, that is designed to provide protection against oil and gas price fluctuations. "Pari Passu Indebtedness" means Indebtedness that ranks pari passu in right of payment to the Notes. "Permitted Business Investments" means investments made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively exploiting, exploring for, acquiring, developing, processing, gathering, marketing or transporting oil and gas through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including, without limitation, (i) ownership interests in oil and gas properties, processing facilities, gathering systems or ancillary real property interests and (ii) Investments in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements and other similar agreements with third parties. "Permitted Indebtedness" has the meaning given in the covenant described under the caption "--Certain Covenants--Incurrence of Indebtedness and Issuance of Disqualified Stock." "Permitted Investments" means (a) any Investment in the Company or in a Wholly Owned Restricted Subsidiary of the Company; (b) any Investment in Cash Equivalents or securities issued or directly and fully guaranteed or insured by the United States government or any agency or instrumentality thereof having maturities of not more than one year from the date of acquisition; (c) any Investment by the Company or any Subsidiary of the Company in a Person, if as a result of such Investment and any related transactions that, at the time of such Investment are contractually mandated to occur (i) such Person becomes a Wholly Owned Restricted Subsidiary of the Company or (ii) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, the Company or a Wholly Owned Restricted Subsidiary of the Company; (d) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption "--Repurchase at the Option of Holders--Asset Sales"; (e) other Investments in any Person having an aggregate fair market value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (e) that are at the time outstanding, not to exceed the greater of $5.0 million or two percent of Total Assets of the Company; (f) Permitted Business Investments; (g) any Investment acquired by the Company in exchange for Equity Interests in the Company (other than Disqualified Stock); (h) Investments in Unrestricted Subsidiaries with net cash proceeds contributed to the common equity capital of the Company since the date of the Indenture, provided that the amount of any such net cash proceeds that are utilized for any such Investment shall be excluded from clause (c)(ii) of the first paragraph of the covenant described under the caption "--Certain Covenants-- Restricted Payments" and (i) shares of Capital Stock received in connection with any good faith settlement of a bankruptcy proceeding involving a trade creditor. "Permitted Liens" means (i) Liens securing Indebtedness of a Subsidiary or Senior Debt that is outstanding on the date of issuance of the Notes or that is permitted by the terms of the Indenture to be incurred; (ii) Liens securing Attributable Debt with respect to sale and leaseback transactions permitted by the terms of the Indenture; (iii) Liens in favor of the Company; (iv) Liens on property existing at the time of acquisition thereof by the Company or any Subsidiary of the Company and Liens 100 on property or assets of a Subsidiary existing at the time it became a Subsidiary, provided that such Liens were in existence prior to the contemplation of the acquisition and do not extend to any assets other than the acquired property; (v) Liens incurred or deposits made in the ordinary course of business in connection with workers' compensation, unemployment insurance or other kinds of social security, or to secure the payment or performance of tenders, statutory or regulatory obligations, surety or appeal bonds, performance bonds or other obligations of a like nature incurred in the ordinary course of business (including lessee or operator obligations under statutes, governmental regulations or instruments related to the ownership, exploration and production of oil, gas and minerals on state or federal lands or waters); (vi) Liens existing on the date of the Indenture; (vii) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded, provided that any reserve or other appropriate provision as shall be required in conformity with GAAP shall have been made therefor; (viii) statutory liens of landlords, mechanics, suppliers, vendors, warehousemen, carriers or other like Liens arising in the ordinary course of business; (ix) judgment Liens not giving rise to an Event of Default so long as any appropriate legal proceeding that may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such proceeding may be initiated shall not have expired; (x) Liens on, or related to, properties or assets to secure all or part or the costs incurred in the ordinary course of the Oil and Gas Business for the exploration, drilling, development, or operation thereof; (xi) Liens in pipeline or pipeline facilities that arise under operation of law; (xii) Liens arising under operating agreements, joint venture agreements, partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, transportation or exchange of oil or natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements and other agreements that are customary in the Oil and Gas Business; (xiii) Liens reserved in oil and gas mineral leases for bonus or rental payments and for compliance with the terms of such leases; (xiv) Liens not otherwise permitted by clauses (i) through (xiii) and that are incurred in the ordinary course of business of the Company or any Subsidiary of the Company with respect to obligations that do not exceed $5.0 million at any one time outstanding; and (xv) Liens on assets of Unrestricted Subsidiaries that secure Non-Recourse Debt of Unrestricted Subsidiaries. "Permitted Refinancing Debt" means any Indebtedness of the Company or any of its Restricted Subsidiaries issued in exchange for, or the net proceeds of which are used to extend, refinance, renew, replace, defease or refund other Indebtedness (other than Indebtedness incurred under a Credit Facility) of the Company or any of its Restricted Subsidiaries; provided that: (i) the principal amount (or accreted value, if applicable) of such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Indebtedness so extended, refinanced, renewed, replaced, defeased or refunded (plus the amount of reasonable expenses incurred in connection therewith); (ii) such Permitted Refinancing Indebtedness has a final maturity date on or later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; (iii) if the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded is subordinated in right of payment to the Notes, such Permitted Refinancing Indebtedness has a final maturity date later than the final maturity date of, and is subordinated in right of payment to, the Notes on terms at least as favorable to the Holders of Notes as those contained in the documentation governing the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded; and (iv) such Indebtedness is incurred either by the Company or by the Restricted Subsidiary who is the obligor on the Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded. "Principal(s)" means (a) Enron Corp., (b) the California Public Employees Retirement System, or (c) JEDI or another entity or entities, as long as JEDI or such other entity or entities is controlled by (i) Enron Corp., (ii) the California Public Employees' Retirement System, (iii) any direct or indirect wholly owned subsidiary of either such entity or (iv) any combination of any of the foregoing entities. 101 "Production Payments" means Dollar-Denominated Production Payments and Volumetric Production Payments, collectively. "Restricted Investment" means an Investment other than a Permitted Investment. "Restricted Subsidiary" of a Person means any Subsidiary of the referent Person that is not an Unrestricted Subsidiary. "Senior Debt" means (i) Indebtedness of the Company or any Subsidiary of the Company under or in respect of any Credit Facility and (ii) any other Indebtedness permitted under the terms of the Indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is on a parity with or subordinated in right of payment to the Notes. Notwithstanding anything to the contrary in the foregoing sentence, Senior Debt will not include (w) any liability for federal, state, local or other taxes owed or owing by the Company, (x) any Indebtedness of the Company to any of its Subsidiaries or other Affiliates, (y) any trade payables or (z) any Indebtedness that is incurred in violation of the Indenture (other than Indebtedness under any Credit Facility that is incurred on the basis of a representation by the Company to the applicable lenders that it is permitted to incur such Indebtedness under the Indenture). "Significant Subsidiary" means any Subsidiary that would be a "significant subsidiary" as defined in Article 1, Rule 1-02 of Regulation S-X, promulgated pursuant to the Act, as such Regulation is in effect on the date hereof. "Subsidiary" means, with respect to any Person, (i) any corporation, association or other business entity of which more than 50% of the total voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof is at the time owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person (or a combination thereof) and (ii) any partnership (a) the sole general partner or the managing general partner of which is such Person or a Subsidiary of such Person or (b) the only general partners of which are such Person or of one or more Subsidiaries of such Person (or any combination thereof). "Taurus" means the Company's gas gathering and processing business and the properties and other assets related thereto, whether or not held by Taurus Energy Corp. "Total Assets" means, with respect to any Person, the total consolidated assets of such Person and its Restricted Subsidiaries, as shown on the most recent balance sheet of such Person. "Unrestricted Subsidiary" means (i) any Subsidiary (other than Diamond or any successor to Diamond) that is designated by the Board of Directors as an Unrestricted Subsidiary pursuant to a Board Resolution, and any Subsidiary of an Unrestricted Subsidiary; but only to the extent that such Subsidiary: (a) has no Indebtedness other than Non-Recourse Debt; (b) is not party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary of the Company unless the terms of any such agreement, contract, arrangement or understanding are no less favorable to the Company or such Restricted Subsidiary than those that might be obtained at the time from Persons who are not Affiliates of the Company; (c) is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (x) to subscribe for additional Equity Interests or (y) to maintain or preserve such Person's financial condition or to cause such Person to achieve any specified levels of operating results; (d) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of the Company or any of its Restricted Subsidiaries; and (e) has at least one director on its board of directors that is not a director or executive officer of the Company or any of its Restricted Subsidiaries and has at least one executive officer that is not a director or executive officer of the Company or any of its Restricted 102 Subsidiaries, provided, however, that the death or resignation of any such director or executive officer shall not cause a Subsidiary that would otherwise be an Unrestricted Subsidiary to be deemed to be a Restricted Subsidiary unless ten days has elapsed in which the Company has failed to appoint or elect a successor to replace such director or executive officer who satisfies the criteria set forth in this clause (e). Any such designation by the Board of Directors shall be evidenced to the Trustee by filing with the Trustee a certified copy of the Board Resolution giving effect to such designation and an Officers' Certificate certifying that such designation complied with the foregoing conditions and was permitted by the covenant described above under the caption "--Certain Covenants--Restricted Payments." If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be incurred by a Restricted Subsidiary of the Company as of such date (and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption "-- Certain Covenants--Incurrence of Indebtedness and Issuance of Disqualified Stock," the Company shall be in default of such covenant). The Board of Directors of the Company may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that such designation shall be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of the Company of any outstanding Indebtedness of such Unrestricted Subsidiary and such designation shall only be permitted if (i) such Indebtedness is permitted under the covenant described under the caption "--Certain Covenants--Incurrence of Indebtedness and Issuance of Disqualified Stock," and (ii) no Default or Event of Default would be in existence following such designation. "Volumetric Production Payments" means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith. "Weighted Average Life to Maturity" means, when applied to any Indebtedness at any date, the number of years obtained by dividing (i) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect thereof, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment, by (ii) the then outstanding principal amount of such Indebtedness. "Wholly Owned Restricted Subsidiary" of any Person means a Restricted Subsidiary of such Person all of the outstanding Capital Stock or other ownership interests of which (other than directors' qualifying shares) shall at the time be owned, directly or indirectly, by such Person or by one or more Wholly Owned Restricted Subsidiaries of such Person. 103 DESCRIPTION OF OTHER INDEBTEDNESS CREDIT AGREEMENT On February 14, 1996, the Company entered into the Credit Agreement with NationsBank, as lender and as agent, and additional lenders named therein. The Credit Agreement is guaranteed by all of the Company's subsidiaries and provides for a revolving credit facility in the amount of $250.0 million. The current borrowing base is $115.0 million and is subject to redetermination: (i) semi-annually, (ii) upon the sale of Taurus and (iii) upon issuance of public subordinated debt in an amount greater than $100.0 million. The lenders under the Credit Agreement have agreed to waive their right to redetermine the borrowing base with respect to the issuance of the Notes. At March 31, 1996, $80.0 million was outstanding under the Credit Agreement and $35.0 million was available for borrowing thereunder. See "Use of Proceeds." The Credit Agreement is unsecured. The Company has provided the lenders with first lien deeds of trust on its oil and natural gas assets which will not become effective, and the lenders have agreed not to file, unless (i) 80% of any outstanding borrowings in excess of the borrowing limit is not repaid within a 90 day period, (ii) cash collateral securing a hedge transaction exceeds 20% of the borrowing limit or (iii) an event of default or a material adverse event, as defined in the Credit Agreement, occurs. So long as no default (as defined in the Credit Agreement) is continuing, the Company has the option of having all or any portion of the amount borrowed under the Credit Agreement be the subject of one of the following interest rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base and (iii) LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base. The Company must also pay a commitment fee of between 0.375% to 0.425% on the unused portion of the credit facility. The Credit Agreement contains various restrictive covenants, including limitations on the granting of liens, restrictions on the issuance of additional debt, restrictions on investments, a requirement to maintain positive working capital, and restrictions on dividends and stock repurchases. The Credit Agreement also contains requirements that JEDI, Enron, CalPERS or any wholly owned subsidiary of either Enron or CalPERS must continue to own a majority of the outstanding equity of the Company and must have the ability to elect the majority of the Board of Directors and that certain members of management maintain specified levels of equity ownership in the Company and continue their employment with the Company. The Credit Agreement matures on February 16, 2001. 104 DESCRIPTION OF CAPITAL STOCK OF CODA COMMON STOCK The authorized common stock of Coda aggregates 1,000,000 shares, par value $0.01 per share. As of May 1, 1996, 913,611 shares of common stock were outstanding. The holders of shares of common stock possess full voting power for the election of directors and for all other purposes, each holder of common stock being entitled to one vote for each share of common stock held of record by such holder. The shares of common stock do not have cumulative voting rights. Holders of a majority of the shares of common stock represented at a meeting at which a quorum is present may currently approve most actions submitted to the stockholders except for certain corporate actions (e.g., mergers, sale of assets and charter amendments), which require the approval of holders of a majority of the total outstanding shares of common stock. Coda has never paid dividends on its common stock. Subject to the rights of holders of any outstanding shares of Preferred Stock, dividends may be paid on the common stock as and when declared by Coda's Board of Directors out of any funds of Coda legally available for the payment thereof. Holders of common stock have no subscription, redemption, sinking fund, conversion or preemptive rights, except for certain put and call rights described in "Certain Transactions." The outstanding shares of common stock are fully paid and nonassessable. After payment is made in full to the holders of any outstanding shares of Preferred Stock in the event of any liquidation, dissolution or winding up of the affairs of Coda, the remaining assets and funds of Coda will be distributed to the holders of common stock according to their respective shares. The common stock is held by 16 holders of record. There is no established trading market for the common stock. PREFERRED STOCK Under Coda's Restated Certificate of Incorporation, the Board of Directors is authorized to issue up to 40,000 shares of preferred stock, par value $0.01 per share. All 40,000 shares of preferred stock are designated as "15% Cumulative Preferred Stock." The holders of each share of Preferred Stock are entitled to receive, when and as declared by the Board of Directors, cumulative preferential dividends, at the rate of $150.00 per share per annum. There are currently 20,000 shares of Preferred Stock issued and outstanding. Shares of Preferred Stock in excess of such 20,000 shares shall be issuable only for the purpose of paying dividends on the Preferred Stock. As long as any shares of Preferred Stock are outstanding, no dividends whatsoever, whether paid in cash, stock or otherwise (except for dividends paid in shares of common stock, either in the form of a stock split or stock dividend), may be paid or declared, nor may any distribution be made, on any common stock to the holders of such stock, unless certain conditions are met. Coda's Restated Certificate of Incorporation requires that Coda redeem all the issued and outstanding shares of Preferred Stock at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption, if Coda has sufficient funds legally available for such redemption and if such redemption would not violate or conflict with any loan agreement, credit agreement, note agreement, indenture or other agreement relating to indebtedness to which Coda is a party, on or before the fifth business day after the earliest to occur of the following: (i) the closing of the sale by Coda of Taurus and (ii) a Trigger Event, as such term is defined in the Stockholders Agreement. The Preferred Stock may be redeemed by Coda at its option, as a whole or in part, to the extent Coda shall have funds legally available for such redemption, at any time or from time to time at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption. Such redemption, whether required or optional, is restricted by the Credit Agreement and the Indenture. 105 Upon the complete liquidation, dissolution, or winding up of Coda, whether voluntarily or involuntarily, the holders of Preferred Stock shall be entitled, after payment or provision for payment of the debts and other liabilities of Coda but before any distribution is made to the holders of any common stock, to be paid $1,000 per share plus all accrued and unpaid dividends (including undeclared dividends), and shall not be entitled to any further payment. Except as otherwise provided herein or required by law, the holders of shares of Preferred Stock shall not be entitled to vote on any matters to be voted on by the stockholders of Coda; provided, however, that so long as any shares of the Preferred Stock are outstanding, Coda shall not, without the written consent or the affirmative vote of holders of at least a majority of the total number of shares of Preferred Stock then outstanding and voting as a class, (i) amend its Certificate of Incorporation or Bylaws or (ii) authorize the merger (whether or not Coda is a surviving corporation in such merger) of Coda, in each case, if such amendment or merger would alter, change or abolish the powers, preference or rights of the Preferred Stock so as to affect the holders of the Preferred Stock adversely. CERTAIN FEDERAL INCOME TAX CONSIDERATIONS In the opinion of Haynes and Boone, LLP, counsel to the Company, the following discussion describes the material federal income tax consequences expected to result to holders whose Private Notes are exchanged for Exchange Notes in the Exchange Offer. Such opinion is based upon current provisions of the Internal Revenue Code of 1986, as amended (the "Code"), applicable Treasury regulations, judicial authority and administrative rulings and practice. There can be no assurance that the Internal Revenue Service (the "Service") will not take a contrary view, and no ruling from the Service has been or will be sought with respect to the Exchange Offer. Legislative, judicial or administrative changes or interpretations may be forthcoming that could alter or modify the statements and conclusions set forth herein. Any such changes or interpretations may or may not be retroactive and could affect the tax consequences to holders. Certain holders (including insurance companies, tax-exempt organizations, financial institutions, broker-dealers, foreign corporations and persons who are not citizens or residents of the United States) may be subject to special rules not discussed below. EACH HOLDER OF PRIVATE NOTES SHOULD CONSULT ITS OWN TAX ADVISOR AS TO THE PARTICULAR TAX CONSEQUENCES OF EXCHANGING PRIVATE NOTES FOR EXCHANGE NOTES, INCLUDING THE APPLICABILITY AND EFFECT OF ANY STATE, LOCAL OR FOREIGN LAWS. The exchange of Private Notes for Exchange Notes will be treated as a "non- event" for federal income tax purposes because the Exchange Notes will not be considered to differ materially in kind or extent from the Private Notes. As a result, no material federal income tax consequences will result to holders exchanging Private Notes for Exchange Notes. PLAN OF DISTRIBUTION Each broker-dealer that receives Exchange Notes for its own account pursuant to the Exchange Offer must acknowledge that it will deliver a prospectus in connection with any resale of such Exchange Notes. This Prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with the resales of Exchange Notes received in exchange for Private Notes where such Private Notes were acquired as a result of market- making activities or other trading activities. The Company has agreed that for a period of up to one year after the effective date of the Registration Statement, it will make this Prospectus, as amended or supplemented, available to any broker-dealer that requests such document in the Letter of Transmittal for use in connection with any such resale. 106 The Company will not receive any proceeds from any sale of Exchange Notes by broker-dealers or any other persons. Exchange Notes received by broker-dealers for their own account pursuant to the Exchange Offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the Exchange Notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such Exchange Notes. Any broker-dealer that resells Exchange Notes that were received by it for its own account pursuant to the Exchange Offer and any broker or dealer that participates in a distribution of such Exchange Notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of Exchange Notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The Letter of Transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. The Company has agreed to pay all expenses incident to the Company's performance of, or compliance with, the Registration Rights Agreement and will indemnify the holders of Private Notes (including any broker-dealers), and certain parties related to such holders, against certain liabilities, including liabilities under the Securities Act. LEGAL MATTERS Certain legal matters related to the Exchange Notes offered hereby are being passed upon for the Company by Mr. Joe Callaway, Vice President and General Counsel of the Company, and by Haynes and Boone, LLP, Dallas, Texas. Mr. Callaway currently holds 475 shares, and options to purchase 475 shares, of Coda common stock. EXPERTS The consolidated financial statements of the Company as of December 31, 1994 and 1995, and for each of the three years in the period ended December 31, 1995, appearing in this Prospectus and Registration Statement have been audited by Ernst & Young LLP, independent auditors, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such report given upon the authority of such firm as experts in accounting and auditing. The estimates as of December 31, 1991, 1992, 1993, 1994 and 1995 relating to the Company's proved oil and natural gas reserves, future net revenues of oil and natural gas reserves and present value of future net revenues of oil and natural gas reserves included herein are based upon estimates of such reserves prepared by Lee Keeling and Associates, Inc. in reliance upon its reports and upon the authority of this firm as experts in petroleum engineering, except that such estimates related to the reserves of Diamond as of December 31, 1991, 1992 and 1993 were prepared by Diamond's in-house engineers. 107 AVAILABLE INFORMATION The Company has filed with the Commission a Registration Statement on Form S-4 under the Securities Act with respect to the Exchange Notes offered hereby. As permitted by the rules and regulations of the Commission, this Prospectus omits certain information, exhibits and undertakings contained in the Registration Statement. For further information with respect to the Company and the Exchange Notes offered hereby, reference is made to the Registration Statement, including the exhibits thereto and the financial statements, notes and schedules filed as a part thereof. As a result of the Exchange Offer, the Company will become subject to the informational requirements of the Exchange Act. The Registration Statement (and the exhibits and schedules thereto), as well as the periodic reports and other information filed by the Company with the Commission, may be inspected and copied at the Public Reference Section of the Commission at Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the regional offices of the Commission located at Room 1400, 75 Park Place, New York, New York 10007 and Suite 1400, Northwestern Atrium Center, 500 West Madison Street, Chicago, Illinois 6061-2511. Copies of such materials may be obtained from the Public Reference Section of the Commission, Room 1024, Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549, and its public reference facilities in New York, New York and Chicago, Illinois at the prescribed rates. Statements contained in this Prospectus as to the contents of any contract or other document are not necessarily complete, and in each instance reference is made to the copy of such contract or document filed as an exhibit to the Registration Statement, each such statement being qualified in all respects by such reference. Pursuant to the Indenture, the Company has agreed that, to the extent such filings are accepted by the Commission and whether or not it has a class of securities registered under the Exchange Act, it will file the annual reports, quarterly reports and other documents that the Company would be required to file if it were subject to Section 13 or 15 of the Exchange Act, in each case on or before the dates on which such reports and other documents would have been required to have been filed with the Commission if the Company had been subject to Section 13 or 15 of the Exchange Act. The Company will also be required (i) to file with the Trustee (with exhibits), and provide to each holder of Notes (without exhibits), without cost to such holder, copies of such reports and documents within 15 days after the date on which the Company files such reports and documents with the Commission or the date on which the Company would be required to file such reports and documents if the Company were so required and (ii) if filing such reports and documents with the Commission is not accepted by the Commission or is prohibited under the Exchange Act, to supply at its cost copies of such reports and documents (including any exhibits thereto) to any holder of Notes promptly upon written request. The principal address of the Company is 5735 Pineland Drive, Suite 300, Dallas, Texas 75231, and the Company's telephone number is (214) 692-1800. 108 GLOSSARY The terms defined in this glossary are used throughout this Prospectus. "AVERAGE NYMEX PRICE." The average of the NYMEX closing prices for the near month. BBL. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons. BCF. One billion cubic feet of natural gas. "BEHIND THE PIPE." Hydrocarbons in a potentially producing horizon penetrated by a well bore the production of which has been postponed pending the production of hydrocarbons from another formation penetrated by the well bore. These hydrocarbons are classified as proved but non-producing reserves. BOE. Barrels of oil equivalent (converting six Mcf of natural gas to one Bbl of oil). "DEVELOPMENT WELL." A well drilled within the proven boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive. "GROSS WELLS." The total number of wells in which a working interest is owned. "INFILL WELL." A well drilled between known producing wells to better exploit the reservoir. MBBLS. One thousand barrels of crude oil or other liquid hydrocarbons. MBOE. One thousand barrels of oil equivalent. MMBTU. One million British thermal units. MCF. One thousand cubic feet of natural gas. M GALLONS. One thousand U.S. gallons liquid volume, used herein in reference to natural gas liquids. MMBBLS. One million barrels of crude oil or other liquid hydrocarbons. MMBOE. One million barrels of oil equivalent. MMCF. One million cubic feet of natural gas. "NET WELLS." The sum of the fractional working interests owned in gross wells. NYMEX. New York Mercantile Exchange. "PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES." The present value of estimated future net revenues is an estimate of future net revenues from a property at its acquisition date, at December 31, 1995, or as otherwise indicated, after deducting production and ad valorem taxes, future capital costs and operating expenses, but before deducting federal income taxes. The future net revenues have been discounted at an annual rate of 10% to determine their "present value." The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates have been made using constant oil and natural gas prices and operating costs at the acquisition date, at December 31, 1995, or as otherwise indicated. The Company believes that the present value of estimated future net revenues before 109 income taxes, while not in accordance with generally accepted accounting principles, is an important financial measure used by investors in independent oil and natural gas producers for evaluating the relative significance of oil and natural gas properties and acquisitions. The present value of estimated future net revenues should not be construed as an alternative to the Standardized Measure, as determined in accordance with generally accepted accounting principles. "PRODUCING WELL," "PRODUCTION WELL" OR "PRODUCTIVE WELL." A well that is producing oil or natural gas or that is capable of production. "PROVED DEVELOPED RESERVES." Proved developed reserves are those quantities of crude oil, natural gas and natural gas liquids that, upon analysis of geological and engineering data, are expected with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing economic and operating conditions. This classification includes: (a) proved developed producing reserves, which are those expected to be recovered from currently producing zones under continuation of present operating methods; and (b) proved developed non-producing reserves, which consist of (i) reserves from wells that have been completed and tested but are not yet producing due to lack of market or minor completion problems that are expected to be corrected, and (ii) reserves currently behind the pipe in existing wells which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the well. "PROVED RESERVES." The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. "PROVED UNDEVELOPED RESERVES." Proved reserves that may be expected to be recovered from existing wells that will require a relatively major expenditure to develop or from undrilled acreage adjacent to productive units that are reasonably certain of production when drilled. "ROYALTY INTEREST." An interest in an oil and natural gas property entitling the owner to a share of oil and natural gas production free of costs of production. "STANDARDIZED MEASURE." The standardized measure of discounted net cash flows related to the Company's proved oil, natural gas and natural gas liquids reserves net of future production and development costs and future income taxes calculated in accordance with generally accepted accounting principles. The calculation is based on a valuation of proved reserves using discounted cash flows based on year-end prices, costs and economic conditions and a 10% discount rate. "WORKING INTEREST." The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to a share of production, subject to all royalties, overriding royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith. 110 INDEX TO FINANCIAL STATEMENTS
PAGE ---- Pro Forma Condensed Financial Statements: Pro Forma Condensed Statement of Operations for the three months ended March 31, 1996......................................................... F-3 Pro Forma Condensed Statement of Operations for the year ended December 31, 1995............................................................... F-4 Notes to Pro Forma Condensed Financial Statements....................... F-5 Historical Financial Statements: Unaudited Consolidated Balance Sheet as of March 31, 1996............... F-8 Unaudited Consolidated Statements of Operations for the three months ended March 31, 1995, the 47 day period ended February 16, 1996 and the 44 day period ended March 31, 1996..................................... F-9 Unaudited Consolidated Statements of Cash Flows for the three months ended March 31, 1995, the 47 day period ended February 16, 1996 and the 44 day period ended March 31, 1996..................................... F-10 Unaudited Consolidated Statement of Stockholders' Equity for the 47 day period ended February 16, 1996 and the 44 day period ended March 31, 1996................................................................... F-11 Notes to Unaudited Consolidated Financial Statements.................... F-12 Report of Ernst and Young LLP, Independent Auditors..................... F-20 Consolidated Balance Sheets as of December 31, 1994 and 1995............ F-21 Consolidated Statements of Operations for the years ended December 31, 1993, 1994 and 1995.................................................... F-22 Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1994 and 1995.................................................... F-23 Consolidated Statements of Stockholders' Equity for the years ended December 31, 1993 1994 and 1995........................................ F-24 Notes to Consolidated Financial Statements.............................. F-25
F-1 CODA ENERGY, INC. AND SUBSIDIARIES PRO FORMA CONDENSED FINANCIAL STATEMENTS The accompanying unaudited pro forma condensed statements of operations of Coda Energy, Inc. (the "Company") for the year ended December 31, 1995 and the three months ended March 31, 1996, have been prepared as if the acquisition of the Snyder Properties, the Merger, the sale of the Private Notes and the Exchange Offer (each as more fully described in the notes to pro forma condensed financial statements) had occurred on January 1, 1995. Because the Exchange Notes are being issued under the same financial terms and conditions as the Private Notes, the Exchange Offer has no impact on the pro forma data. The historical financial information for the Company was obtained from the historical consolidated financial statements of the Company contained elsewhere in this document. The historical financial information of the Snyder Properties was obtained from internal reports prepared by the seller and is unaudited. The unaudited pro forma condensed financial statements do not purport to represent the results of operations which would have occurred had such transactions been consummated on the dates indicated or the results of operation for any future date or period. These unaudited pro forma condensed financial statements should be read in conjunction with the historical financial statements of the Company. F-2 CODA ENERGY, INC. AND SUBSIDIARIES PRO FORMA CONDENSED STATEMENT OF OPERATIONS THREE MONTHS ENDED MARCH 31, 1996 (UNAUDITED, IN THOUSANDS)
HISTORICAL PRO FORMA ---------------------- ADJUSTMENTS FOR 47 DAYS 44 DAYS THE MERGER, THE ENDED ENDED SALE OF THE PRIVATE FEBRUARY 16, MARCH 31, NOTES AND THE 1996 1996 EXCHANGE OFFER PRO FORMA ------------ --------- ------------------- --------- Revenues: Oil and gas sales..... $ 8,079 $ 8,964 $17,043 Gas gathering and processing........... 5,322 4,799 10,121 Other income.......... 168 201 369 ------- -------- ------- 13,569 13,964 27,533 ------- -------- ------- Costs and expenses: Oil and gas production........... 3,607 3,885 7,492 Gas gathering and processing........... 4,567 3,888 8,455 Depletion, depreciation and amortization......... 2,583 3,498 $ 816 (/1/) 6,897 General and administrative....... 320 352 672 (333)(/2/) Interest.............. 1,102 2,087 4,300 1,444 (/3/) Stock option compensation......... 3,199 -- (3,199)(/4/) -- Writedown of oil and gas properties....... -- 83,305 (83,305)(/5/) -- ------- -------- -------- ------- 15,378 97,015 (84,577) 27,816 ------- -------- -------- ------- Income (loss) before income taxes........... (1,809) (83,051) 84,577 (283) Income tax expense (benefit).............. (511) (29,915) 30,422 (/6/) (4) ------- -------- -------- ------- Net income (loss)....... (1,298) (53,136) 54,155 (279) Preferred stock dividend requirements........... -- 361 389 (/7/) 750 ------- -------- -------- ------- Net income (loss) available for common stockholders'.......... $(1,298) $(53,497) $ 53,766 $(1,029) ======= ======== ======== =======
F-3 CODA ENERGY, INC. AND SUBSIDIARIES PRO FORMA CONDENSED STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 1995 (IN THOUSANDS)
PRO FORMA PRO FORMA ADJUSTMENTS ADJUSTMENTS SNYDER FOR THE FOR THE MERGER, PROPERTIES ACQUISITION OF THE SALE OF THE COMPANY NINE MONTHS THE SNYDER PRIVATE NOTES AND HISTORICAL HISTORICAL PROPERTIES THE EXCHANGE OFFER PRO FORMA ---------- ----------- -------------- ------------------ --------- Revenues: Oil and gas sales..... $60,997 $5,159 $ 66,156 Gas marketing, gathering, and processing........... 35,634 35,634 Other income.......... 1,207 921 $ (921)(/8/) 1,207 ------- ------ ------- -------- 97,838 6,080 (921) 102,997 ------- ------ ------- -------- Costs and expenses: Oil and gas production........... 27,119 3,425 30,544 Gas gathering and processing........... 30,473 30,473 Depletion, depreciation, and amortization......... 19,715 1,295 (/9/) $ 7,499 (/1/) 28,509 General and administrative....... 2,898 (921)(/8/) 1,977 (2,562)(/2/) Interest.............. 8,676 899 (/1//0/) 18,563 11,550 (/3/) ------- ------ ------- --------- -------- 88,881 3,425 1,273 16,487 110,066 ------- ------ ------- --------- -------- Income (loss) before income taxes........... 8,957 2,655 (2,194) (16,487) (7,069) Income tax expense (benefit).............. 3,202 157 (/1//1/) (5,935)(/6/) (2,576) ------- ------ ------- --------- -------- Net income (loss)....... 5,755 2,655 (2,351) (10,552) (4,493) Preferred stock dividends.............. -- 3,000 (/7/) 3,000 ------- ------ ------- --------- -------- Net income (loss) applicable to common stockholders........... $ 5,755 $2,655 $(2,351) $ (13,552) $ (7,493) ======= ====== ======= ========= ========
F-4 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO PRO FORMA CONDENSED FINANCIAL STATEMENTS (UNAUDITED) NOTE A--PRO FORMA ADJUSTMENTS FOR THE MERGER, THE SALE OF THE PRIVATE NOTES AND THE EXCHANGE OFFER On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as of October 30, 1995 (as subsequently amended, the "Merger Agreement") by and among Coda Energy, Inc. ("Coda"), Joint Energy Development Investments Limited Partnership ("JEDI"), an affiliate of Enron Capital & Trade Resources Corp., and Coda Acquisition, Inc. ("Purchaser"), a subsidiary of JEDI, JEDI acquired Coda through a merger (the "Merger") at a price of $7.75 per share in cash. The sources and uses of funds related to the Merger are as follows (in millions): Sources of funds: Credit agreement...................................................... $ 95.0 JEDI debt............................................................. 100.0 Redeemable preferred stock issued to JEDI............................. 20.0 Common stock issued to JEDI........................................... 90.0 ------ $305.0 ====== Uses of funds: Payments to Coda stockholders, warrantholders and optionholders....... $176.2 Repayment of former credit facility and other indebtedness............ 122.7 Merger costs and other expenses....................................... 6.1 ------ $305.0 ======
Concurrently with the execution of the Merger Agreement, JEDI and Purchaser entered into certain agreements with members of management of the Company concerning their employment with and/or equity participation in the Company after the Merger. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired based on estimated fair values. As a result, the Company's financial position and operating results subsequent to the date of the Merger reflect a new basis of accounting and are not comparable to prior periods. Following the Merger, the Company issued $110 million principal amount of Senior Subordinated Notes due 2006 and used $100 million of the proceeds therefrom to repay all of the subordinated debt owed to JEDI. The remaining net proceeds together with the reimbursements described below and other available cash were used to repay approximately $10.0 million in debt outstanding under the Credit Agreement. ECT Securities Corp. refunded to the Company $2.0 million in fees paid in connection with the issuance of the JEDI debt. Further, the Purchasers of the Private Notes reimbursed the Company for costs and expenses in the amount of $550,000. The Company is offering to exchange the Exchange Notes for the Private Notes. The Private Notes were sold in transactions exempt from registration under the Securities Act on March 18, 1996. The Exchange Offer is intended to satisfy certain of the Company's obligations under the Registration Rights Agreement and Purchase Agreement. Because the Exchange Notes are being issued under the same financial terms and conditions as the Private Notes, the Exchange Offer has no impact on the pro forma data. F-5 The accompanying unaudited pro forma condensed statement of operations has been prepared as if the Merger, the sale of the Private Notes and the Exchange Offer had occurred on January 1, 1995 and reflects the following adjustments: (1) To adjust depletion, depreciation, and amortization to reflect JEDI's purchase price allocated to property and equipment. (2) To adjust interest expense to give effect to the net reduction of approximately $36.8 million under the Company's credit facility and repayment of the note payable to an officer of the Company, partially offset by an increase in the interest rate on borrowings under the new credit facility of .25%. (3) To record interest on the Notes at an interest rate of 10 1/2%. (4) To eliminate stock option compensation expense resulting from the Merger. (5) To eliminate the writedown of oil and gas properties resulting from the Merger. (6) To adjust the provision for income taxes for the change in financial taxable income resulting from adjustments (1), (2), (3), (4) and (5). (7) To record the cumulative dividend requirements of the redeemable preferred stock issued to JEDI. NOTE B--PRO FORMA ADJUSTMENTS FOR THE ACQUISITION OF THE SNYDER PROPERTIES In October 1995, the Company acquired interests in 63 producing oil and gas properties located in west Texas from Snyder Oil Company (the "Snyder Properties"). The aggregate purchase price was $17.1 million in cash, of which $16.0 million was financed by borrowings under the Company's then-existing credit agreement. The acquisition was accounted for by the purchase method of accounting. Prior to the acquisition, the Snyder Properties were included in the consolidated financial statements of the seller and were not accounted for as a separate entity. The accompanying unaudited pro forma condensed statement of operations has been prepared as if the acquisition of the Snyder Properties occurred on January 1, 1995 and reflects the following adjustments: (8) To reclassify fees from overhead charges billed to working interest owners, which are classified as a reduction of general and administrative expenses in the Company's consolidated statements of operations. (9) To adjust depletion, depreciation and amortization to reflect the effect of the acquisition of the Snyder Properties. Depletion, depreciation and amortization of oil and gas properties is computed using the unit-of- production method. (10) To adjust interest expense for the estimated amounts the Company would have incurred on the incremental borrowings pursuant to the Company's credit facility used to acquire the Snyder Properties. The interest rate used was based on the interest rate options provided for in the Company's credit facility in effect at the time. (11) To adjust the provision for income taxes for the change in financial taxable income resulting from inclusion of the historical results of the Snyder Properties and adjustments (9) and (10). F-6 NOTE C--PRO FORMA SUPPLEMENTAL OIL AND GAS RESERVE AND STANDARDIZED MEASURE INFORMATION The following summary of pro forma quantities of proved reserves was prepared by adjusting the Company's historical quantities for the effects of the acquisition of the Snyder Properties assuming such acquisition had been consummated January 1, 1995. PRO FORMA PROVED RESERVES
OIL (MBBLS) GAS (MMCF) ----------- ---------- December 31, 1994........................................ 43,789 47,093 Purchases of reserves in place........................... 3,017 492 Extensions............................................... 783 3,173 Revision of previous estimates........................... (1,011) 1,459 Production............................................... (3,440) (4,895) Sales of reserves in place............................... (548) (10,192) ------ ------- December 31, 1995........................................ 42,590 37,130 ====== ======= PRO FORMA PROVED DEVELOPED RESERVES OIL (MBBLS) GAS (MMCF) ----------- ---------- December 31, 1994........................................ 23,379 39,089 December 31, 1995........................................ 25,877 31,496
The following are the principal sources of changes in the pro forma standardized measure of discounted future net cash flows (in thousands): Pro forma standardized measure of discounted future net cash flows at December 31, 1994............................................... $188,132 Pro forma changes in the standardized measure of discounted future net cash flows: Sales and transfers of oil and gas produced, net of production costs............................................................ (35,612) Net changes in prices and production costs........................ 38,972 Extensions and discoveries, net of future development and production costs................................................. 15,932 Development costs incurred during the period...................... 14,464 Revisions of previous quantity estimates.......................... (19,084) Sales of reserves in place........................................ (6,323) Purchases of reserves in place.................................... 15,337 Accretion of discount............................................. 40,719 Changes in income taxes........................................... (31,795) -------- Net change...................................................... 32,610 -------- Standardized measure of discounted future net cash flows at December 31, 1995........................................................... $220,742 ========
F-7 CODA ENERGY, INC. AND SUBSIDIARIES UNAUDITED CONSOLIDATED BALANCE SHEET MARCH 31, 1996 (IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS) ASSETS Current Assets: Cash and cash equivalents......................................... $ 3,491 Accounts receivable--revenue...................................... 11,536 Accounts receivable--joint interest and other..................... 2,768 Other current assets.............................................. 2,303 -------- 20,098 -------- Oil and gas properties (full cost accounting method): Proved oil and gas properties..................................... 245,080 Unproved oil and gas properties................................... 1,000 Less accumulated depletion, depreciation and amortization....... 3,035 -------- 243,045 -------- Gas plants and gathering systems.................................... 33,705 Less accumulated depreciation..................................... 329 -------- 33,376 -------- Other properties, net............................................... 4,169 -------- Other assets........................................................ 3,747 -------- $304,435 ======== LIABILITIES AND SHAREHOLDERS' EQUITY Current liabilities: Current maturities of long-term debt and notes payable............ $ 120 Accounts payable--trade........................................... 6,213 Accounts payable--revenue and other............................... 3,572 Accrued interest.................................................. 738 Income taxes payable.............................................. 93 -------- 10,736 -------- Long-term debt--less current maturities............................. 81,719 -------- 10 1/2% Senior Subordinated Notes................................... 110,000 -------- Deferred income taxes............................................... 41,493 -------- Commitments and contingent liabilities 15% Cumulative redeemable preferred stock, 40 shares of $.01 par value authorized; 20 shares issued and outstanding................. 20,000 -------- Common stockholders' equity of management, subject to put and call rights............................................................. 4,560 Less related notes receivable..................................... (937) -------- 3,623 -------- Other common stockholders' equity: Common stock...................................................... 9 Additional paid-in capital........................................ 89,991 Retained earnings (deficit)....................................... (53,136) -------- 36,864 -------- $304,435 ========
See Notes to Unaudited Consolidated Financial Statements. F-8 CODA ENERGY, INC. AND SUBSIDIARIES UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS)
PRE MERGER POST MERGER ---------------------- ----------- THREE MONTHS 47 DAYS 44 DAYS ENDED ENDED ENDED MARCH 31, FEBRUARY 16, MARCH 31, 1995 1996 1996 --------- ------------ ----------- Revenues: Oil and gas sales........................................................................ $14,948 $ 8,079 $ 8,964 Gas gathering and processing............................................................. 7,904 5,322 4,799 Other income............................................................................. 187 168 201 ------- ------- -------- 23,039 13,569 13,964 ------- ------- -------- Costs and expenses: Oil and gas production................................................................... 6,563 3,607 3,885 Gas gathering and processing............................................................. 6,730 4,567 3,888 Depletion, depreciation and amortization................................................. 4,870 2,583 3,498 General and administrative............................................................... 707 320 352 Interest................................................................................. 2,068 1,102 2,087 Stock option compensation................................................................ -- 3,199 -- Writedown of oil and gas properties...................................................... -- -- 83,305 ------- ------- -------- 20,938 15,378 97,015 ------- ------- -------- Income (loss) before income taxes.......................................................... 2,101 (1,809) (83,051) Income tax expense (benefit)............................................................... 796 (511) (29,915) ------- ------- -------- Net income (loss).......................................................................... 1,305 (1,298) (53,136) Preferred stock dividend requirements...................................................... -- -- 361 ------- ------- -------- Net income (loss) available for common stockholders'....................................... $ 1,305 $(1,298) $(53,497) - -------------------------------------------------- ======= ======= ========
See Notes to Unaudited Consolidated Financial Statements F-9 CODA ENERGY, INC. AND SUBSIDIARIES UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
PRE MERGER POST MERGER ------------------------- ----------- THREE MONTHS 47 DAYS 44 DAYS ENDED ENDED ENDED MARCH 31, FEBRUARY 16, MARCH 31, 1995 1996 1996 ------------ ------------ ----------- Cash flows from operating activities: Net income (loss)...................................................................... $ 1,305 $(1,298) $ (53,136) Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation and amortization............................................. 4,870 2,583 3,498 Writedown of oil and gas properties.................................................. -- -- 83,305 Deferred income tax expense (benefit)................................................ 657 (511) (30,000) Stock option compensation............................................................ -- 3,199 -- Other................................................................................ 160 6 -- Effect of changes in: Accounts receivable................................................................. (628) 3,386 (4,630) Other current assets................................................................ (127) (63) (207) Accounts payable and other current liabilities...................................... (1,115) (4,166) 2,631 -------- ------- --------- Net cash provided by operating activities......................................... 5,122 3,136 1,461 -------- ------- --------- Cash flows from investing activities: Additions to oil and gas properties.................................................... (4,955) (1,717) (770) Proceeds from sale of assets........................................................... 1,193 110 53 Purchase of Coda by JEDI, net of $740 cash acquired.................................... -- -- (179,373) Gas plant and gathering systems and other property additions........................... (7,346) (114) (43) Investment in marketable equity securities............................................. (573) -- -- Payments received on amounts due from stockholders..................................... -- 130 124 Other.................................................................................. 52 -- -- -------- ------- --------- Net cash used by investing activities............................................. (11,629) (1,591) (180,009) -------- ------- --------- Cash flows from financing activities: Proceeds from bank borrowings.......................................................... 7,500 -- -- Proceeds from issuance of subordinated debt............................................ -- -- 210,000 Proceeds from issuances of common and preferred stock.................................. -- -- 110,026 Repayment of bank borrowings and subordinated debt..................................... (2,727) (5,019) (137,667) Proceeds from exercise of options and warrants......................................... 402 -- -- Repurchases of common stock............................................................ (2,125) -- -- Financing costs........................................................................ -- (390) (320) -------- ------- --------- Net cash provided (used) by financing activities.................................. 3,050 (5,409) 182,039 -------- ------- --------- Increase (decrease) in cash............................................................ (3,457) (3,864) 3,491 Cash at beginning of period............................................................ 6,474 4,604 -- -------- ------- --------- Cash at end of period.................................................................. $ 3,017 $ 740 $ 3,491 ======== ======= ========= Supplemental cash flow information: Interest paid.......................................................................... $ 2,545 $ 1,544 $ 1,317 ======== ======= ========= Income taxes paid...................................................................... $ 500 $ -- $ 120 - -------------------------------------------------- ======== ======= =========
See Notes to Unaudited Consolidated Financial Statements F-10 CODA ENERGY, INC. AND SUBSIDIARIES UNAUDITED CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (IN THOUSANDS)
15% CUMULATIVE COMMON STOCKHOLDERS' EQUITY REDEEMABLE OF MANAGEMENT, SUBJECT TO OTHER COMMON PREFERRED STOCK PUT AND CALL RIGHTS STOCKHOLDER'S EQUITY ----------------- ------------------------------ ----------------------- ADDITIONAL RETAINED NOTES PAR PAID-IN EARNINGS SHARES AMOUNT SHARES AMOUNT RECEIVABLE SHARES VALUE CAPITAL (DEFICIT) ------- --------- ------- --------- ----------- ------ ----- ---------- --------- Pre Merger: Balances at December 31, 1995.............. 22,089 $442 $68,671 $ 10,075 Stock option compensation.......... 3,199 Net loss for the period January 1, 1996 through February 16, 1996.................. (1,298) ----- --------- ------ --------- -------- ------ ---- ------- -------- Balances at February 16, 1996................... -- -- -- -- -- 22,089 $442 $71,870 $ 8,777 ===== ========= ====== ========= ======== ====== ==== ======= ======== Post Merger: Transactions related to the merger: Common stock issued to management investors in exchange for common stock, options, warrants, notes receivable and cash... 14 $4,560 $(937) Common stock issued to JEDI for cash......... 900 $ 9 $89,991 Preferred stock issued to JEDI for cash...... 20 $20,000 Net loss for the period from February 17, 1996 through March 31, 1996.................. $(53,136) ----- --------- ------ --------- -------- ------ ---- ------- -------- Balances at March 31, 1996................... 20 $20,000 14 $4,560 $(937) 900 $ 9 $89,991 $(53,136) ===== ========= ====== ========= ======== ====== ==== ======= ========
See Notes to Unaudited Consolidated Financial Statements F-11 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS 1. THE MERGER On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as of October 30, 1995 (as amended, the "Merger Agreement"), by and among Coda Energy, Inc. ("Coda" or together with its subsidiaries the "Company"), Joint Energy Development Investments Limited Partnership ("JEDI"), which is an affiliate of Enron Capital & Trade Resources Corp. ("ECT"), and Coda Acquisition, Inc. ("CAI"), which was a subsidiary of JEDI, JEDI acquired Coda through a merger (the "Merger") at a price of $7.75 per share in cash (for an aggregate purchase price of approximately $176.2 million). Concurrently with the execution of the Merger Agreement, JEDI and CAI entered into certain agreements with members of the Company's management (the "Management Group"), providing for a continuing role of management in the Company after the Merger. Following consummation of the Merger, the Management Group owns approximately 5% of Coda's common stock on a fully-diluted basis. JEDI owns the remaining 95%. The sources and uses of funds related to financing the Merger were as follows: SOURCES OF FUNDS (IN MILLIONS) Credit Agreement.................................................. $ 95.0 JEDI Debt(1)...................................................... 100.0 Redeemable Preferred Stock issued to JEDI......................... 20.0 Common Stock issued to JEDI....................................... 90.0 ------ Total........................................................... $305.0 ====== USES OF FUNDS (IN MILLIONS) Payments to Coda stockholders, warrantholders and optionholders... $176.2 Repayment of former credit facility and other indebtedness........ 122.7 Merger costs and other expenses................................... 6.1 ------ Total........................................................... $305.0 ======
-------- (1) Represents indebtedness incurred by CAI and assumed by Coda to fund a portion of the consideration paid in the Merger. The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired based on estimated fair values. As a result, the Company's financial position and operating results subsequent to the date of the Merger reflect a new basis of accounting and are not comparable to prior periods. The allocation of JEDI's purchase price to the assets and liabilities of Coda resulted in a significant increase in the carrying value of the Company's oil and gas properties. Under the full cost method of accounting, the carrying value of oil and gas properties (net of related deferred taxes) is generally not permitted to exceed the sum of the present value (10% discount rate) of estimated future net cash flows (after tax) from proved reserves, based on current prices and costs, plus the lower of cost or estimated fair value of unproved properties (the "cost center ceiling"). Based upon the allocation of JEDI's purchase price and estimated proved reserves and product prices in effect at the date of the F-12 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) Merger, the purchase price allocated to oil and gas properties was in excess of the cost center ceiling by approximately $83.3 million ($53.3 million net of related deferred taxes). The resulting writedown is a non-cash charge and has been included in the results of operations for the period ended March 31, 1996. 2. ACCOUNTING AND REPORTING POLICIES The consolidated financial statements include the accounts of Coda Energy, Inc., its majority-owned subsidiaries and its pro rata share of the assets, liabilities and operations of oil and gas partnerships and joint ventures. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to prior years' amounts to conform to the current year presentation. The accompanying consolidated financial statements, which should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 1995, reflect all adjustments (consisting only of normal recurring accruals) which are, in the opinion of management, necessary to present fairly the financial position as of March 31, 1996, and the results of operations and cash flows for the periods ended March 31, 1995, February 16, 1996 and March 31, 1996. The results for the period ended March 31, 1996, are not necessarily indicative of results for a full year. Fees from overhead charges billed to working interest owners, including the Company, of $1.2 million, $848,000 and $808,000 for the periods ended March 31, 1995, February 16, 1996 and March 31, 1996, respectively, have been classified as a reduction of general and administrative expenses in the accompanying consolidated statements of operations. 3. CREDIT AGREEMENT On February 14, 1996, the Company entered into a credit agreement with NationsBank of Texas, N.A. ("NationsBank"), as lender and as agent, and additional lenders named therein (the "Credit Agreement"). The Credit Agreement is guaranteed by all of the Company's subsidiaries and provides for a revolving credit facility in an amount up to $250.0 million. The current borrowing base is $115.0 million and is subject to redetermination: (i) semiannually, (ii) upon the sale of Taurus and (iii) upon issuance of public subordinated debt in an amount greater than $100.0 million. The lenders under the Credit Agreement have agreed to waive their right to redetermine the borrowing base with respect to the issuance of the Notes. At March 31, 1996, $80.0 million was outstanding under the Credit Agreement and $35.0 million was available for borrowing thereunder. The Credit Agreement is unsecured. The Company has provided the lenders with first lien deeds of trust on its oil and natural gas assets which will not become effective, and the lenders have agreed not to file, unless (i) 80% of any outstanding borrowings in excess of the borrowing base is not repaid within a 90 day period, (ii) cash collateral securing a hedge transaction exceeds 20% of the borrowing base or (iii) an event of default or a material adverse event, as defined in the Credit Agreement, occurs. So long as no default (as defined in the Credit Agreement) is continuing, the Company has the option of having all or any portion of the amount borrowed under the Credit Agreement be the subject of one of the following interest rates: (i) NationsBank's prime rate, (ii) the CD Rate plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base and (iii) LIBOR plus 1 1/4% to 1 5/8% based upon the ratio of outstanding debt to the available borrowing base. The Company must also pay a commitment fee of between 0.375% to 0.425% on the unused portion of the credit facility. F-13 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) The Credit Agreement contains various restrictive covenants, including limitations on the granting of liens, restrictions on the issuance of additional debt, restrictions on investments, a requirement to maintain positive working capital, and restrictions on dividends and stock repurchases. The Credit Agreement also contains requirements that JEDI, Enron, or certain affiliates of JEDI must continue to own a majority of the outstanding equity of the Company and must have the ability to elect the majority of the Board of Directors and that certain members of management maintain specified levels of equity ownership in the Company and continue their employment with the Company. The Credit Agreement matures on February 16, 2001. 4. LONG-TERM DEBT The Company's 12% Senior Subordinated Debentures due 2000 (the "Debentures") bear interest at 12% per annum, payable semiannually. At March 31, 1996, approximately $1.2 million in aggregate principal amount of the Debentures was outstanding. On March 28, 1996, the Company gave notice of redemption, prior to maturity, to each of the record holders of the outstanding Debentures. The outstanding Debentures were redeemed on May 1, 1996 at a redemption price of 100.0% of the principal amount of the Debentures plus accrued and unpaid interest thereon. On May 1, 1996, the Company deposited with the trustee of the Debentures funds sufficient to so redeem the Debentures, and thereafter interest on the Debentures ceased to accrue. 5. 10 1/2% SENIOR SUBORDINATED NOTES On March 18, 1996, the Company completed the sale of $110 million principal amount of 10 1/2% Senior Subordinated Notes due 2006 (the "Notes"). The proceeds of the Notes were used to fully repay the JEDI debt assumed in the Merger and to partially repay bank debt. The Notes bear interest at an annual rate of 10 1/2% payable semiannually in arrears on April 1 and October 1 of each year. The Notes are general, unsecured obligations of the Company, are subordinated in right of payment to all Senior Debt (as defined in the Indenture governing the Notes) of Coda, and are senior in right of payment to all future subordinated debt of the Company. The claims of the holders of the Notes will be subordinated to Senior Debt, which, as of March 31, 1996, was $81.8 million. The Notes were issued pursuant to an Indenture, which contains certain covenants that, among other things, limit the ability of Coda and its Restricted Subsidiaries to incur additional indebtedness and issue Disqualified Stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing pari passu or subordinated indebtedness of Coda and engage in mergers and consolidations. The Notes are not redeemable at Coda's option prior to April 1, 2001. After April 1, 2001, the Notes will be subject to redemption at the option of Coda, in whole or in part, at the redemption prices set forth in the Indenture, plus accrued and unpaid interest thereon to the applicable redemption date. In addition, until March 12, 1999, up to $27.5 million in aggregate principal amount of Notes are redeemable, at the option of Coda on any one or more occasions from the net proceeds of an offering of common equity of Coda, at a price of 110.5% of the aggregate principal amount of the Notes, together with accrued and unpaid interest thereon to the date of the redemption; provided, however, that at least $82.5 million in aggregate principal amount of Notes must remain outstanding immediately after the occurrence of such redemption; provided, further, that any such redemption shall occur within 75 days of the date of the closing of such offering of common equity. In the event of a Change of Control (as defined in the Indenture), holders of the Notes will have the right to require Coda to repurchase their Notes, in whole or in part, at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the date of F-14 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) repurchase. The Indenture requires that, prior to such a repurchase but in any event within 90 days of such Change of Control, Coda must either repay all Senior Debt or obtain any required consent to such repurchase. Coda's payment obligations under the Notes are fully, unconditionally and jointly and severally guaranteed on a senior subordinated basis by all of Coda's current subsidiaries and future Restricted Subsidiaries (as defined in the Indenture). Such guarantees are subordinated to the guarantees of Senior Debt issued by the Guarantors under the Credit Agreement and to other guarantees of Senior Debt issued in the future. The combined condensed financial information of the Company's current subsidiaries, the Guarantors, is as follows:
MARCH 31, 1996 --------- Current assets........................................................ $ 6,928 Oil and gas properties, net........................................... 55,601 Gas plants and gathering systems, net................................. 33,040 Other properties, net and other assets................................ 1,554 ------- Total assets........................................................ $97,123 ======= Current liabilities................................................... $ 4,965 Intercompany payables................................................. 49,699 Deferred income taxes................................................. 15,612 Stockholder's equity.................................................. 26,847 ------- Total liabilities and stockholder's equity.......................... $97,123 =======
POST PRE MERGER MERGER ------------ --------- 47 DAYS 44 DAYS ENDED ENDED FEBRUARY 16, MARCH 31, 1996 1996 ------------ --------- Revenues: Oil and gas sales.................................................................................... $ 2,529 $ 3,180 Gas gathering and processing......................................................................... 5,322 4,799 Other income......................................................................................... 2 47 ------- --------- 7,853 8,026 Costs and expenses: Oil and gas production............................................................................... 843 884 Gas gathering and processing......................................................................... 4,567 3,888 Depletion, depreciation and amortization............................................................. 1,039 1,350 General and administrative........................................................................... 435 504 Interest............................................................................................. 460 467 Writedown of oil and gas properties.................................................................. -- 19,159 ------- --------- 7,344 26,252 ------- --------- Income (loss) before income taxes...................................................................... 509 (18,226) Income tax expense (benefit)........................................................................... 277 (6,591) - -------------------------------------------------- ------- --------- Net income (loss)...................................................................................... $ 232 $ (11,635) ======= =========
F-15 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 6. PREFERRED STOCK Under Coda's Restated Certificate of Incorporation, the Board of Directors is authorized to issue up to 40,000 shares of preferred stock, par value $0.01 per share. All 40,000 shares of preferred stock are designated as "15% Cumulative Preferred Stock." The holders of each share of Preferred Stock are entitled to receive, when and as declared by the Board of Directors, cumulative preferential dividends, at the rate of $150.00 per share per annum. There are currently 20,000 shares of Preferred Stock issued and outstanding. Shares of Preferred Stock in excess of such 20,000 shares shall be issuable only for the purpose of paying dividends on the Preferred Stock. As long as any shares of Preferred Stock are outstanding, no dividends whatsoever, whether paid in cash, stock or otherwise (except for dividends paid in shares of common stock, either in the form of a stock split or stock dividend), may be paid or declared, nor may any distribution be made, on any common stock to the holders of such stock, unless certain conditions are met. Coda's Restated Certificate of Incorporation requires that Coda redeem all the issued and outstanding shares of Preferred Stock at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption, if Coda has sufficient funds legally available for such redemption and if such redemption would not violate or conflict with any loan agreement, credit agreement, note agreement, indenture or other agreement relating to indebtedness to which Coda is a party, on or before the fifth business day after the earliest to occur of the following: (i) the closing of the sale by Coda of Taurus Energy Corp. and (ii) a Trigger Event, as such term is defined in the Stockholders Agreement. The Preferred Stock may be redeemed by Coda at its option, as a whole or in part, to the extent Coda shall have funds legally available for such redemption, at any time or from time to time at a redemption price of $1,000 per share, plus all accrued and unpaid dividends (including undeclared dividends) to the date of redemption. Such redemption, whether required or optional, is restricted by the Credit Agreement and the Indenture. Upon the complete liquidation, dissolution, or winding up of Coda, whether voluntarily or involuntarily, the holders of Preferred Stock shall be entitled, after payment or provision for payment of the debts and other liabilities of Coda but before any distribution is made to the holders of any common stock, to be paid $1,000 per share plus all accrued and unpaid dividends (including undeclared dividends), and shall not be entitled to any further payment. Except as otherwise provided herein or required by law, the holders of shares of Preferred Stock are not be entitled to vote on any matters to be voted on by the stockholders of Coda; provided, however, that so long as any shares of the Preferred Stock are outstanding, Coda shall not, without the written consent or the affirmative vote of holders of at least a majority of the total number of shares of Preferred Stock then outstanding and voting as a class, (i) amend its Certificate of Incorporation or Bylaws or (ii) authorize the merger (whether or not Coda is a surviving corporation in such merger) of Coda, in each case, if such amendment or merger would alter, change or abolish the powers, preference or rights of the Preferred Stock so as to affect the holders of the Preferred Stock adversely. 7. COMMON STOCK At December 31, 1995, the Company had 40.0 million shares of $.02 par value common stock authorized with 22.1 million shares issued and outstanding. At March 31, 1996, the Company had 1.0 million shares of $.01 par value common stock authorized with 14,000 shares issued to management subject to put and call rights and 900,000 issued to JEDI for a total of 914,000 shares issued and outstanding. F-16 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) 8. RELATED PARTY TRANSACTIONS SUBSCRIPTION AGREEMENT CAI entered into a Subscription Agreement dated as of October 30, 1995, as amended by Amendment No. 1 to Subscription Agreement dated as of January 10, 1996, with members of the Management Group (as amended, the "Subscription Agreement") which provided for the acquisition by such persons of CAI common stock and the grant to them of nonqualified stock options to purchase shares of post-Merger common stock (the "Replacement Options") of Coda. Under the Subscription Agreement, each member of the Management Group who acquired CAI common stock paid $100 per share for shares thereof, which is the same price per share paid by JEDI for the remaining shares of CAI common stock. Under the Subscription Agreement, the Management Group acquired CAI common stock immediately prior to the effective time of the Merger in exchange for varying combinations of (i) proceeds from limited recourse promissory notes payable to CAI in the aggregate principal amount of $937,300 (the "Promissory Notes"), (ii) Coda common stock, which was valued for this purpose at $7.75 per share, and (iii) cash. The CAI common stock so acquired was not registered under the Securities Act or any state securities laws and does not have the benefit of any registration rights, but is subject to the Stockholders Agreement described below. By virtue of the Merger, each share of CAI common stock was converted into one share of Coda common stock. The Subscription Agreement provided that the Specified Options (representing certain options to purchase Common Stock held by certain members of the Management Group) and Specified Warrants (representing certain warrants to purchase Common Stock held by certain members of the Management Group) would not be exercised prior to the effective time of the Merger and would, as of the effective time, be canceled without exercise and without payment of consideration. Concurrently, the Management Group entered into Nonstatutory Stock Option Agreements governing the Replacement Options that provided for the right for a period of 10 years from and after the effective time of the Merger to purchase shares of post-Merger Coda common stock for $0.01 per share. However, the Replacement Options may only be exercised while the holder remains an employee of the Company and for a limited period of time thereafter. The number of shares of Coda common stock underlying the Replacement Options each member of the Management Group received is based on the amount of cash the holder would have received if his Specified Options or Specified Warrants had been converted into cash in the Merger on the same basis as other outstanding options and warrants to purchase Common Stock were converted, divided by the $100 per share purchase price paid by JEDI and the other Management Group members for their shares of CAI common stock. Thus, if the Replacement Options are exercised, the holders will have effectively paid the same purchase price per share as JEDI and the Management Group paid for their shares of common stock of Coda. In connection with the issuance of the Replacement Options, the Company recognized stock option compensation expense of approximately $3.2 million representing the total amount of cash the holders of the Specified Options and Specified Warrants would have received if such options and warrants had been converted to cash in the Merger. The Promissory Notes will be due on February 16, 2001, bear interest at 5.61%, are secured by the Company common stock purchased with the proceeds thereof and certain rights of the maker under the Stockholders Agreement described below, and provide that in no event will an individual maker's liability thereunder for any deficiency on his respective Promissory Note (after the sale and disposition of all collateral securing same) exceed 35% of the original principal balance of the Promissory Note. F-17 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) STOCKHOLDERS AGREEMENT CAI, JEDI and the Management Group entered into a Stockholders Agreement dated as of October 30, 1995, as amended by Amendment No. l to Stockholders Agreement dated as of January 10, 1996 (as amended, the "Stockholders Agreement"), which provides generally that all parties, including JEDI and the Management Group, (i) have rights of first refusal to acquire additional shares of common stock of Coda that may be issued by Coda and (ii) are restricted from transferring their Coda common stock. Coda has a right to match any third party offer to purchase shares of Coda common stock from any stockholder, and, in the event that Coda does not purchase those shares, the other stockholders may have a right to include a pro rata portion of their Coda common stock in the transaction. The Stockholders Agreement provides that, if the employment of a member of the Management Group terminates for any reason (including death or disability) other than his voluntary termination (except upon retirement at age 65 or older or the expiration of the term of any employment agreement he has with Coda) or his termination by Coda for cause, then Coda shall have a right to purchase such member's shares of Coda common stock at a purchase price to be determined from time to time by Coda pursuant to a formula that values the shares on the basis of a comparison of the discretionary cash flow and EBITDA (as defined therein) of the Company and a group of peer companies. The Stockholders Agreement also provides that, if the employment of a member of the Management Group terminates for any reason other than voluntary termination or termination of such member for cause, then such member shall have the right to require Coda to purchase such member's shares of Coda common stock based on the previously described formula. The purchase price under the formula will vary depending on the financial performance of the Company and the group of peer companies. The Stockholders Agreement provides that each member of the Management Group shall have the right (the "Special Management Rights") to receive from JEDI, upon the occurrence of certain events (generally an initial public offering, a business combination with another person or the liquidation of Coda) (each, a "Trigger Event"), an amount, which is payable in cash or additional shares of Coda common stock depending upon the cause of the Trigger Event, designed to result in the Management Group receiving in connection with the Trigger Event one- third of the proceeds, attributable to the shares of Coda common stock purchased by JEDI, above the amount of proceeds necessary for JEDI to achieve an internal annual rate of return on that investment of 15%. The individual member's interest in such Special Management Rights is proportional to such member's ownership of the fully diluted common stock of Coda. The Stockholders Agreement also provides that if the employment of a member of the Management Group terminates, his Special Management Rights shall terminate and, if the termination is other than a voluntary termination or a termination for cause, he may be entitled to receive an amount based on the discretionary cash flow and EBITDA formula discussed above. The Stockholders Agreement further provides that, after the effective time of the Merger, Coda will establish an employee benefit plan for the benefit of its employees who are not members of the Management Group and will contribute to the plan 1,900 shares of Coda common stock. Furthermore, pursuant to the Stockholders Agreement, 4% of the Special Management Rights will be allocated thereto. The Stockholders Agreement will terminate and no party thereto will have any further obligations or rights thereunder upon the earliest to occur of (i) the termination of the Merger Agreement in accordance with its terms, (ii) October 30, 2005, (iii) the date on which an initial public offering of Coda common stock or any business transaction involving Coda whereby Coda common stock becomes a publicly traded security is consummated, (iv) the date of the dissolution, liquidation or winding-up of Coda and (v) the date of the delivery to Coda of a written termination notice executed by certain parties to the Stockholders Agreement. F-18 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) ENRON Enron Corp. ("Enron") is the parent of ECT and accordingly may be deemed to control indirectly both JEDI and the Company. Enron and certain of its subsidiaries and other affiliates collectively participate in nearly all phases of the oil and natural gas industry and are, therefore, competitors of the Company. In addition, ECT and JEDI have provided, and may in the future provide, and ECT Securities Corp. has assisted, and may in the future assist, in arranging, financing to non-affiliated participants in the oil and natural gas industry who are or may become competitors of the Company. Because of these various conflicting interests, ECT, the Company, JEDI and the Management Group have entered into the Business Opportunity Agreement which is intended to make it clear that Enron and its affiliates have no duty to make business opportunities available to the Company in most circumstances. The Business Opportunity Agreement also provides that ECT and its affiliates may pursue certain business opportunities to the exclusion of the Company. The Business Opportunity Agreement may limit the business opportunities available to the Company. In addition, pursuant to the Business Opportunity Agreement there may be circumstances in which the Company will offer business opportunities to certain affiliates of Enron. If an Enron affiliate is offered such an opportunity and decides to pursue it, the Company may be unable to pursue it. 9. HEDGING TRANSACTIONS The following table sets forth the barrels and weighted average NYMEX prices hedged under various swap agreements entered into as of March 31, 1996.
WEIGHTED BARRELS AVERAGE PERIODS COVERED HEDGED PRICE --------------- ------- -------- Nine months ending December 31, 1996..................... 530,000 $18.81 Year ending December 31, 1997............................ 375,000 $19.02
As of March 31, 1996 the Company has open positions for sold call options covering 25,000 Bbls of oil per month at an option price of $18.30 per Bbl for the period April 1996 to August 1996, and at an option price of $20.00 per Bbl for the period from September 1996 to August 1997. During the period ended February 16, 1996 and March 31, 1996 the Company's oil revenues were decreased by $14,000 and $250,000, respectively, as a result of hedging transactions. F-19 REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS The Board of Directors and Stockholders Coda Energy, Inc. We have audited the accompanying consolidated balance sheets of Coda Energy, Inc., and subsidiaries (the "Company") as of December 31, 1994 and 1995, and the related consolidated statements of operations, cash flows, and stockholders' equity for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Coda Energy, Inc., and subsidiaries at December 31, 1994 and 1995, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. ERNST & YOUNG LLP Dallas, Texas February 17, 1996, except for the first through the fifth paragraphs of Note 10 as to which the date is March 18, 1996 F-20 CODA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS DECEMBER 31, 1994 AND 1995 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
DECEMBER 31, ----------------- 1994 1995 -------- -------- ASSETS Current assets: Cash and cash equivalents.................................. $ 6,474 $ 4,604 Accounts receivable--revenue............................... 7,551 10,598 Accounts receivable--joint interest and other.............. 1,766 2,463 Other current assets....................................... 1,276 2,206 -------- -------- 17,067 19,871 Amounts due from stockholders................................ 1,375 81 Oil and gas properties (full cost accounting method)......... 190,967 226,650 Less accumulated depletion, depreciation, and amortiza- tion...................................................... 39,154 56,042 -------- -------- Oil and gas properties, net.............................. 151,813 170,608 Gas plants and gathering systems, at cost.................... 29,835 38,068 Less accumulated depreciation.............................. 1,492 4,082 -------- -------- Gas plants and gathering systems, net.................... 28,343 33,986 Other properties, net........................................ 2,150 2,142 Other assets................................................. 2,354 2,376 -------- -------- $203,102 $229,064 ======== ======== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Current maturities of long-term debt....................... $ 424 $ 453 Accounts payable--trade.................................... 5,954 7,252 Accounts payable--revenue and other........................ 3,599 3,394 Accrued interest........................................... 1,375 342 Income taxes payable....................................... 733 128 -------- -------- 12,085 11,569 Long-term debt, less current maturities...................... 105,063 123,907 Deferred income taxes........................................ 11,213 14,400 Commitments and contingencies Stockholders' equity: Preferred stock, 7,500 shares authorized; none issued...... -- -- Common stock, $.02 par value; 40,000 shares authorized; 22,228 and 22,089 shares issued at December 31, 1994 and 1995, respectively........................................ 445 442 Additional paid-in capital................................. 69,976 68,671 Retained earnings subsequent to June 30, 1989.............. 4,320 10,075 -------- -------- Total stockholders' equity............................... 74,741 79,188 -------- -------- $203,102 $229,064 ======== ========
See notes to consolidated financial statements. F-21 CODA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS YEARS ENDED DECEMBER 31, 1993, 1994, AND 1995 (IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31, ----------------------- 1993 1994 1995 ------- ------- ------- Revenues: Oil and gas sales.................................... $38,877 $50,683 $60,997 Gas gathering and processing......................... 732 20,081 35,634 Other income......................................... 441 822 1,207 ------- ------- ------- 40,050 71,586 97,838 Costs and expenses: Oil and gas production............................... 17,590 21,646 27,119 Gas gathering and processing......................... 570 17,357 30,473 Depletion, depreciation, and amortization............ 10,808 16,419 19,715 General and administrative........................... 2,596 3,144 2,898 Business combination................................. -- 1,829 -- Interest............................................. 4,834 5,281 8,676 ------- ------- ------- 36,398 65,676 88,881 ------- ------- ------- Income before income taxes............................. 3,652 5,910 8,957 Income tax expense..................................... 1,318 2,581 3,202 ------- ------- ------- Net income............................................. $ 2,334 $ 3,329 $ 5,755 ======= ======= =======
See notes to consolidated financial statements. F-22 CODA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS YEARS ENDED DECEMBER 31, 1993, 1994, AND 1995 (IN THOUSANDS)
YEAR ENDED DECEMBER 31, ---------------------------- 1993 1994 1995 -------- -------- -------- Cash flows from operating activities: Net income...................................... $ 2,334 $ 3,329 $ 5,755 Adjustments to reconcile net income to net cash provided by operating activities: Depletion, depreciation, and amortization..... 10,808 16,419 19,715 Deferred income tax expense................... 1,038 1,567 3,187 Amortization of deferred financing costs...... -- 554 101 Amortization of prepaid gas purchases......... -- -- 440 Other......................................... 183 123 55 Effect of changes in: Accounts receivable.......................... (1,545) 589 (3,849) Other current assets......................... (221) 60 (558) Accounts payable and other current liabilities................................. 3,846 346 (545) -------- -------- -------- Net cash provided by operating activities.. 16,443 22,987 24,301 Cash flows from investing activities: Additions to oil and gas properties............. (34,375) (49,732) (41,079) Additions to gas plant and gathering systems and other property................................. (646) (4,130) (8,500) Business combinations........................... (5,074) (3,250) -- Investment in common equity securities.......... -- -- (573) Payments received on amounts due from stockholders................................... -- -- 1,294 Proceeds from sale of assets.................... 441 2,515 5,722 Prepaid long-term gas purchases................. -- (1,759) -- Other, net...................................... (137) (423) 106 -------- -------- -------- Net cash used in investing activities...... (39,791) (56,779) (43,030) Cash flows from financing activities: Proceeds from common stock offering, net........ 36,128 -- -- Repayment of long-term debt..................... (53,286) (41,542) (11,551) Proceeds from bank borrowings................... 43,217 76,350 30,400 Proceeds from exercise of stock options and warrants....................................... 972 2,370 772 Repurchases of common stock..................... (68) (812) (2,125) Other, net...................................... (804) (140) (637) -------- -------- -------- Net cash provided by financing activities.. 26,159 36,226 16,859 -------- -------- -------- Net increase (decrease) in cash and cash equivalents..................................... 2,811 2,434 (1,870) Cash and cash equivalents at beginning of year... 1,229 4,040 6,474 -------- -------- -------- Cash and cash equivalents at end of year......... $ 4,040 $ 6,474 $ 4,604 ======== ======== ======== Supplemental cash flow information: Interest paid................................... $ 4,364 $ 3,788 $ 9,584 ======== ======== ======== Income taxes paid............................... $ 156 $ 300 $ 618 ======== ======== ========
See notes to consolidated financial statements. F-23 CODA ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY YEARS ENDED DECEMBER 31, 1993, 1994, AND 1995 (IN THOUSANDS)
COMMON STOCK TREASURY STOCK -------------- ---------------- ADDITIONAL RETAINED PAID-IN EARNINGS SHARES AMOUNT CAPITAL (DEFICIT) SHARES AMOUNT ------ ------ ---------- --------- ------- ------- Balances December 31, 1992.................... 12,850 $257 $20,891 $(1,218) 524 $ 981 Common stock issued for cash, net............... 6,789 136 35,992 -- -- -- Shares issued as director compensation............ 8 -- 41 -- -- -- Shares issued upon exercise of stock options and warrants.... 339 7 965 -- -- -- Cancellation of treasury stock................... (524) (11) (970) -- (524) (981) Repurchase and cancellation of common stock................... (7) -- (68) -- -- -- Dividends on Diamond Energy Operating Company common stock............ -- -- -- (125) -- -- Net income............... -- -- -- 2,334 -- -- ------ ---- ------- ------- ------ ------- Balances December 31, 1993.................... 19,455 389 56,851 991 -- -- Shares issued as director compensation............ 7 -- 44 -- -- -- Shares issued upon exercise of stock options and warrants.... 788 16 2,355 -- -- -- Common stock issued to purchase Taurus Energy Corp.................... 1,500 30 7,265 -- -- -- Repurchase and cancellation of common stock................... (157) (3) (809) -- -- -- Common stock issued to acquire reversionary interests in oil and gas properties.............. 635 13 4,270 -- -- -- Net income............... -- -- -- 3,329 -- -- ------ ---- ------- ------- ------ ------- Balances December 31, 1994.................... 22,228 445 69,976 4,320 -- -- Shares issued as director compensation............ 7 -- 45 -- -- -- Shares issued upon exercise of stock options and warrants.... 225 5 767 -- -- -- Repurchase and cancellation of common stock................... (371) (8) (2,117) Net income............... -- -- -- 5,755 -- -- ------ ---- ------- ------- ------ ------- Balances December 31, 1995.................... 22,089 $442 $68,671 $10,075 -- $ -- ====== ==== ======= ======= ====== =======
See notes to consolidated financial statements. F-24 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS DECEMBER 31, 1995 1. SUMMARY OF SIGNIFICANT ACCOUNTING AND REPORTING POLICIES PRINCIPLES OF CONSOLIDATION AND BASIS OF FINANCIAL STATEMENT PRESENTATION-- The consolidated financial statements include the accounts of Coda Energy, Inc. ("Coda"), its majority owned subsidiaries, and its pro rata share of the assets, liabilities, and operations of oil and gas limited partnerships and joint ventures (the "Company"). See Note 2. All significant intercompany balances and transactions have been eliminated in consolidation. Certain reclassifications have been made to amounts reported in prior years to conform with the current presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. CASH AND CASH EQUIVALENTS--Cash and cash equivalents include commercial paper or deposits with major financial institutions with maturities of three months or less when purchased. ACCOUNTS RECEIVABLE--Substantially all of the Company's accounts receivable arise from sales of oil, natural gas, or natural gas liquids or from participants in oil and gas wells for which the Company serves as the operator. Generally, operators of oil and gas properties have the right to offset future revenues against unpaid charges related to operated wells. Oil and gas sales are generally unsecured. Most of the Company's receivables are from a broad and diverse group of oil and gas companies and, accordingly, do not represent a significant credit risk. Credit losses are provided for in the financial statements and have been within management's expectations. The allowance for doubtful accounts receivable aggregated $185,000 and $158,000 at December 31, 1994 and 1995, respectively. OIL AND GAS PROPERTIES--Oil and gas properties are recorded at cost using the full cost method of accounting, as prescribed by the Securities and Exchange Commission (the "SEC"). Under the full cost method, all costs associated with the acquisition, exploration, or development of oil and gas properties are capitalized as part of the full cost pool. Sales, dispositions, and other oil and gas property retirements are accounted for as adjustments to the full cost pool, with no recognition of gain or loss unless such disposition would significantly alter the amortization rate. Under rules of the SEC for the full-cost method of accounting, the net carrying value of oil and gas properties is limited to the sum of the present value (10% discount rate) of estimated future net cash flows from proved reserves, based on period-end prices and costs, plus the lower of cost or estimated fair value of unproved properties. Depletion, depreciation, and amortization of evaluated oil and gas properties are provided using the unit-of-production method based on total proved reserves, as determined by independent petroleum reservoir engineers. GAS PLANTS AND GATHERING SYSTEMS--Gas plants and gathering systems are recorded at cost and depreciated on a straight-line basis over their estimated useful lives of 15 years. OVERHEAD REIMBURSEMENT FEES--Fees from overhead charges billed to working interest owners, including the Company, of $2,999,000, $3,372,000, and $5,571,000 for the years ended December 31, 1993, 1994, and 1995, respectively, have been classified as a reduction of general and administrative expenses in the accompanying consolidated statements of operations. F-25 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 OIL AND GAS FINANCIAL INSTRUMENTS--The Company enters into swap agreements to reduce the effects of the volatility of the price of crude oil and natural gas on the Company's operations. These agreements involve the receipt of fixed price amounts in exchange for variable payments based on NYMEX prices and specific volumes. The differential to be paid or received is accrued in the month of the related production and recognized as a component of oil and gas revenues. The Company also sells call options on crude oil. The strike price of these agreements exceeds current market prices at the time they are entered into. Option premiums received, which have not been material, are deferred. If the applicable market price exceeds the strike price and option premium, the differential is accrued and recognized as a reduction of oil revenues in the month of the related production. Any remaining deferred option premiums are recognized at the end of the option period. The fair values of the swap agreements and sold call options are not included in the financial statements. INCOME TAXES--The Company has adopted the Financial Accounting Standards Board's Statement No. 109, "Accounting for Income Taxes" ("FAS 109"), which requires the use of the liability method in accounting for income taxes. QUASI-REORGANIZATION--In 1989, the Company, with the approval of the Board of Directors, implemented a quasi-reorganization and adjusted its assets and liabilities to fair value at June 30, 1989; eliminated accumulated depletion, depreciation, and amortization existing on all properties at June 30, 1989, against the respective asset accounts; and transferred the accumulated deficit at June 30, 1989, of $39,663,000 and the cost of canceled treasury stock of $1,809,000 to additional paid-in capital. NEW ACCOUNTING PRONOUNCEMENTS--In the first quarter of 1996, the Company will adopt the Financial Accounting Standards Board ("FASB") Statement No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of" ("FAS 121"). Adoption of this statement will not have a material effect on the Company's financial statements. In October 1995, the FASB issued its statement No. 123, "Accounting for Stock Based Compensation" ("FAS 123") which establishes an alternative method of accounting for stock based compensation to the method set forth in Accounting Principles Board Opinion No. 25 ("APB 25"). FAS 123 encourages, but does not require, adoption of a fair value based method of accounting for stock options and similar equity instruments granted to employees. The Company will continue to account for such grants under the provisions of APB 25 and will adopt the disclosure provisions of FAS 123 in the first quarter of 1996. Accordingly, adoption of FAS 123 will not effect the Company's financial statements. 2. MERGER WITH DIAMOND On September 30, 1994, pursuant to an Agreement and Plan of Merger (the "Merger Agreement"), the Company acquired all of the issued and outstanding stock of Diamond Energy Operating Company and Diamond A Inc. ("DEOC" and "Diamond A," respectively, and collectively, "Diamond"), and two newly formed, wholly owned subsidiaries of the Company merged into DEOC and Diamond A. The Company issued an aggregate of 3,647,715 shares of the Company's common stock to the Diamond stockholders. Contemporaneously with the merger, Diamond acquired the F-26 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 overriding royalty and reversionary interests owned by Diamond's primary lender in certain of Diamond's oil and gas properties for $9.0 million cash. Coda provided the funds necessary to complete such acquisition and repay $18.5 million of existing Diamond indebtedness. If the price of oil received from the Diamond properties averages more than $17.65 per barrel for the 48-month period ending September 30, 1998, Diamond's former lender will be paid an additional $1.0 million. In addition, other reversionary interests in oil and gas properties in which Diamond owns an interest were purchased from certain employees and former employees of, and consultants to, DEOC and from a financial advisor to Diamond for 634,519 shares of the Company's common stock and approximately $39,000 in cash. The merger with Diamond has been accounted for as a pooling of interests. Accordingly, the merger of the equity interests has been given retroactive effect in these financial statements for periods prior to the merger to represent the combined financial statements of the previously separate entities. The acquisitions of the reversionary interests were accounted for as purchases effective September 30, 1994. Separate and combined results of Coda and Diamond for periods prior to the merger are as follows (in thousands):
CODA DIAMOND COMBINED ------- ------- -------- Year ended December 31, 1993: Revenues............................................ $27,226 $12,824 $40,050 Net income.......................................... 840 1,494 2,334 Nine months ended September 30, 1994 (unaudited): Revenues............................................ 37,048 13,314 50,362 Net income.......................................... 194 1,831 2,025
In connection with the merger, the Company incurred approximately $1.8 million of legal, accounting, printing, and other costs related to the combination of the previously separate entities. Under pooling of interests accounting, these costs were expensed in September 1994. Amounts due from stockholders shown in the accompanying balance sheets are primarily related to the sale by DEOC of its oil and gas properties to its stockholders in July 1990 in exchange for a note receivable. The note bears interest at 10% and is due on demand. Interest is added to the principal balance as accrued. The note is secured by certain of the shares of Coda common stock which the former Diamond stockholders received in the merger. 3. ACQUISITIONS The Company is continually acquiring oil and gas properties. The significant transactions that have occurred since January 1, 1993, are discussed below. In July 1993, the Company acquired interests in 71 producing oil and gas properties effective June 1, 1993, located primarily in the Morrow and Chester formations in southwest Kansas (the "Kansas Properties"), from affiliates of Mobil Oil Corp. The total purchase price for the Kansas Properties was $15,800,000, all of which was funded pursuant to the Company's credit agreement. In September 1993, the Company purchased all of the issued and outstanding shares of MJM Oil & Gas, Inc. ("MJM"). The total purchase price was $5,650,000, all of which was funded from the net F-27 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 proceeds of a public offering of common stock (Note 5). The acquisition was accounted for as a purchase. As a result of the acquisition of MJM, the Company acquired 147 producing oil and gas properties, located primarily in north and west Texas and western Oklahoma, at a cost of approximately $19.9 million, including the assumption of approximately $11.7 million of MJM indebtedness. On April 29, 1994, Coda acquired 100% of the issued and outstanding common stock of Taurus Energy Corporation ("Taurus"), a privately held Texas corporation, in exchange for 1,500,000 shares of the Company's common stock, valued at approximately $7.3 million, and $3.25 million cash. The Company assumed existing Taurus indebtedness of approximately $9.75 million. The cash portion of the purchase price was funded, and the assumed debt was refinanced, under the Company's existing credit agreement. Taurus operates three natural gas processing facilities and owns interests in approximately 700 miles of natural gas gathering systems located primarily in west central Texas. Contemporaneously with the consummation of the acquisition of Taurus, the president and former principal stockholder of Taurus loaned the Company $1.0 million in exchange for a subordinated promissory note from the Company having a term of three years, payable in three equal annual installments of principal plus accrued interest calculated at the rate of 7% per annum. In July 1994, Taurus acquired ownership of the Shackelford gas gathering system and processing plant. Taurus had previously been operating the system and plant under operating leases. Taurus paid $3.8 million for the system and plant, which was funded under the Company's existing credit agreement. In related transactions, Taurus entered into an agreement to sell 10,000 MMBTU per day to the former owner of Shackelford for a period of 48 months. Simultaneously, Taurus entered into a gas purchase agreement with an unrelated third party for similar quantities over the same term. Pricing under both the gas sales agreement and the gas purchase agreement is structured to allow Taurus to earn a margin on all volumes sold during the term of the agreements. In January 1995, Taurus acquired the remaining ownership interest in one of Taurus' gas plants and related facilities for $6.5 million which was financed under the Company's credit facility. In December 1994, in two separate transactions, the Company acquired interests in 31 producing oil and gas properties in west Texas from two major oil companies. The acquisition prices were $13.3 million and $10.0 million, respectively, all of which was financed under the Company's credit facility. The acquisitions were accounted for as a purchase. The properties acquired for $13.3 million are referred to herein as the Major Oil Company Properties. In October 1995, Coda acquired from Snyder Oil Company interests in 63 producing oil and gas properties located in west Texas (the "Snyder Properties"). The aggregate purchase price was $17.1 million in cash, of which $16.0 million was financed by borrowings under the Company's existing credit facility. The acquisition was accounted for by the purchase method of accounting. The following pro forma data present the consolidated results of operations of the Company for the years ended December 31, 1994 and 1995, as if the acquisitions of Taurus, the Major Oil Company Properties, and the Snyder Properties had occurred on January 1, 1994. The pro forma results of operations are presented for comparative purposes only and are not necessarily indicative of the results that would have been obtained had such acquisitions been consummated as presented. The following data reflect pro forma adjustments for depletion, depreciation, and amortization related to the acquired oil and gas properties, gas plants, and gathering systems; anticipated changes in general and F-28 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 administrative expenses; adjustments to interest expense on borrowed funds; and resulting adjustments to income tax expense.
PRO FORMA (UNAUDITED, IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) YEAR ENDED DECEMBER 31, -------------------------- 1994 1995 ------------ ------------- Revenues........................................ $89,970 $102,997 ============ ============= Net income...................................... $ 3,664 $ 6,121 ============ =============
4. LONG-TERM DEBT Long-term debt is summarized as follows (in thousands):
DECEMBER 31, ----------------- 1994 1995 -------- -------- NationsBank credit agreements............................ $102,700 $122,000 Note payable to NationsBank.............................. 723 606 Senior subordinated debentures........................... 964 988 Other.................................................... 1,100 766 -------- -------- 105,487 124,360 Less current maturities.................................. 424 453 -------- -------- Long-term debt........................................... $105,063 $123,907 ======== ========
NATIONSBANK CREDIT AGREEMENTS--Until the merger with JEDI on February 16, 1996 (Note 9), the Company had a credit agreement (the "Credit Agreement") with NationsBank of Texas, N.A. ("NationsBank") and three additional participant banks. The Credit Agreement as last amended through August 1995 had a notional amount of $250.0 million, subject to borrowing base limitations, based on the value of the Company's oil and gas properties and its gas gathering and processing assets, as determined by the lenders from time to time. Under the Credit Agreement, the Company was required to pay a facility fee equal to one-quarter of one percent on any accepted increase in the borrowing base in excess of the previously determined borrowing base and a commitment fee of three-eighths of one percent on the unused portion of the borrowing base. The maturity date of the Credit Agreement was May 31, 1999. The Credit Agreement provided that the interest rate on borrowings will range from NationsBank's prime rate to LIBOR plus between 1% and 1 3/8% based on the ratio of outstanding debt to the available borrowing base. The weighted average interest rate on borrowings outstanding under the Credit Agreement was 7.72% and 7.29% at December 31, 1994 and 1995, respectively. There were no scheduled principal payments due on the Credit Agreement until maturity. At December 31, 1995, the borrowing base was $125.0 million and approximately $3.0 million was available for borrowing. A borrowing base deficiency is created in the event that the outstanding loan balances exceed the borrowing base, as determined by the lenders in their sole discretion. Upon such event, the borrowing base deficiency must be repaid by mandatory reductions of the loan balances over a period of not more than six months. The Company did not anticipate a borrowing base F-29 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 deficiency, and, accordingly, the current portion of long-term debt at December 31, 1995, does not include any amount related to the Credit Agreement. Borrowings under the Credit Agreement were unsecured. The Credit Agreement contained various restrictive covenants, including limitations on the granting of liens, restrictions on the issuance of additional debt, requirements to maintain net worth of at least $46.5 million and to maintain positive working capital, as defined, and prohibited the payment of dividends on Coda's capital stock. NOTE PAYABLE TO NATIONSBANK--In December 1992, the Company purchased a building in Dallas, Texas, containing approximately 65,000 square feet of office space to serve as its corporate headquarters. The Company currently occupies approximately two-thirds of the office space and has made the balance available for lease. The purchase price was $950,000, of which $850,000 was financed by NationsBank pursuant to a promissory note requiring monthly principal and interest payments, with the remaining unpaid balance due December 31, 1995. The promissory note bears interest at prime plus 1%. The remainder of the purchase price was financed by the seller and is evidenced by a second lien promissory note requiring quarterly interest payments. In February 1995, NationsBank agreed to amend the note payable to reduce the interest rate to NationsBank's prime rate and to extend the maturity date to January 2, 1998. SENIOR SUBORDINATED DEBENTURES--The Company's 12% Senior Subordinated Debentures (the "Debentures") are presented net of unamortized issuance discount of $189,000 and $165,000 at December 31, 1994 and 1995, respectively. The effective interest rate on the Debentures is 16.61%. The remaining outstanding Debentures are due in 2000. Scheduled maturities of long-term debt as of December 31, 1995, are as follows (in thousands): 1996.............................................................. $ 453 1997.............................................................. 453 1998.............................................................. 366 1999.............................................................. 122,100 2000.............................................................. 988 -------- $124,360 ========
The carrying value of the Company's long-term debt approximates fair value. 5. COMMON STOCK COMMON STOCK--On September 30, 1994, the Company's stockholders approved an amendment to the Company's Certificate of Incorporation increasing the number of authorized shares of common stock from 30 million shares to 40 million shares. In September 1993, the Company sold 6,788,750 shares of common stock pursuant to a public offering. The net proceeds of approximately $36.1 million to the Company were used to purchase the capital stock of MJM (Note 3), to repay certain MJM indebtedness (approximately $900,000), and to repay amounts under the Company's Credit Agreement. In December 1993, the Board of Directors authorized the repurchase of up to 3,000,000 shares of the Company's common stock, from time to time and whenever, in the opinion of the Company's F-30 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 management, market conditions make such repurchase a prudent use of Company funds. In January 1994, the Company received written approval for such repurchases from NationsBank provided that the amount paid does not exceed $5,000,000 in the aggregate. No shares had been repurchased as of December 31, 1993. During the year ended December 31, 1994 and 1995, the Company repurchased and canceled 136,500 and 371,000 shares of common stock, respectively, in open market transactions at a cost of approximately $648,000 and $2.1 million, respectively. STOCK OPTIONS AND WARRANTS--The Company has three stock option plans providing for the granting of stock options to officers and key employees. Compensation expense is not recognized at the time options are granted because the option price per share represents the market value of the share at the date of grant. The 1986 Non-Qualified Stock Option Plan provides that options may be granted, from time to time, to key employees and directors to purchase a maximum of 180,000 shares of common stock. The 1989 Incentive Stock Option Plan provides that options may be granted, from time to time, to key employees to purchase a maximum of 750,000 shares of common stock. The 1993 Incentive Stock Option Plan permits the granting of options to purchase up to 1,500,000 shares of common stock. Option transactions are summarized below:
NUMBER OF SHARES OPTION PRICE RANGE --------- ------------------ Outstanding at December 31, 1992................ 726,750 $2.25 --$3.50 Granted....................................... 343,584 5.13 -- 6.00 Exercised..................................... (163,750) 2.25 -- 3.00 Forfeited..................................... (7,500) 3.50 --------- Outstanding at December 31, 1993................ 899,084 2.25 -- 6.00 Granted....................................... 525,785 5.00 -- 6.50 Exercised..................................... (108,629) 2.25 -- 5.75 Forfeited..................................... (56,708) 3.50 -- 5.75 --------- Outstanding at December 31, 1994................ 1,259,532 2.25 -- 6.50 Granted....................................... -- Exercised..................................... (100,213) 2.25 -- 5.75 Forfeited..................................... (42,687) 3.50 -- 5.75 --------- Outstanding at December 31, 1995 (755,756 exer- cisable)....................................... 1,116,632 2.25 -- 6.50 ========= Reserved for future options..................... 837,876 =========
The following table summarizes warrants outstanding at December 31, 1995:
EXERCISE NUMBER OF NUMBER OF PRICE SHARES UNDER WARRANTS EXPIRATION DATE SHARES EXERCISABLE PER SHARE - --------------------- --------------- ------------------ --------- 500,000 October 1999 500,000 $3.00 450,000 December 2000 450,000 3.13 50,000 April 2002 25,000 3.00 100,000 April 2004 25,000 4.88 100,000 September 2004 25,000 6.75 100,000 March 2005 -- 6.00 --------- --------- 1,300,000 1,025,000 ========= =========
F-31 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 The warrants that expire in October 1999 are held by an officer of the Company. The remaining warrants are held by the Company's directors. As a result of the merger described in Note 9, all outstanding options and warrants are fully vested and the holders thereof are entitled to receive the difference between $7.75 per share and the exercise price for each share represented by the options and warrants. Certain members of the management of the Company have exchanged their right to receive this payment for an equity participation in the Company. 6. INCOME TAXES At December 31, 1995, Coda has net operating loss carryforwards ("NOLs") for income tax purposes that expire beginning in 1998. Utilization of the NOLs is severely restricted because of a change in ownership, as defined by the Tax Reform Act of 1986, of Coda, which occurred in March 1990. Coda estimates that approximately $15.4 million of the NOLs is available to offset future taxable income without limitation, while the remainder will become available in the future at the rate of approximately $921,000 per year through 2004. Coda also has available statutory depletion carryforwards of approximately $1,000,000. For financial reporting purposes, a valuation allowance has been recognized to offset the deferred tax assets related to carryforwards prior to Coda's quasi- reorganization. The Company anticipates that the merger described in Note 9 will not have a material effect on its ability to utilize the remaining NOLs. F-32 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company's deferred tax liabilities and assets are as follows (in thousands):
DECEMBER 31, ---------------- 1994 1995 ------- ------- Deferred tax liabilities: Book basis of oil and gas properties in excess of tax ba- sis....................................................... $ 8,980 $11,441 Book basis of gas plants and gathering systems in excess of tax basis................................................. 5,355 6,447 Revenues not recognized for tax purposes................... 360 -- Other...................................................... 40 1,074 ------- ------- Total deferred tax liabilities........................... 14,735 18,962 Deferred tax assets: Net operating loss carryforwards........................... 6,887 8,468 Credit carryforwards....................................... 569 -- Other...................................................... 108 136 Valuation allowance for deferred tax assets................ (4,042) (4,042) ------- ------- Net deferred tax assets.................................. 3,522 4,562 ------- ------- Net deferred tax liabilities................................. $11,213 $14,400 ======= =======
Significant components of income tax expense are as follows (in thousands):
YEAR ENDED DECEMBER 31, ------------------------ 1993 1994 1995 ------- ------- ------- Current............................................ $ 280 $ 733 $ 15 Deferred........................................... 1,104 1,848 3,187 Adjustments to the valuation allowance............. (66) -- -- ------- ------- ------- $1,318 $2,581 $3,202 ======= ======= =======
The following is a reconciliation, stated as a percentage of pretax income taxable at the corporate level, of the U.S. statutory federal income tax rate to the Company's effective tax rate:
1993 1994 1995 ---- ---- ---- U.S. federal statutory rate................................... 34% 34% 34% State taxes................................................... 4 5 2 Non-deductible business combination expenses.................. -- 5 -- Adjustments to the valuation allowance........................ (2) -- -- --- --- --- 36% 44% 36% === === ===
7. OPERATIONS NATURE OF OPERATIONS The Company is an independent energy company principally engaged in the acquisition and exploitation of producing oil and natural gas properties. The Company seeks to acquire properties F-33 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 whose predominant economic value is attributable to proved producing reserves and to enhance that value through control of operations, reduction of costs, and property development. The Company's producing properties are concentrated in the mid-continent region of the United States. Through a subsidiary, Taurus, the Company also operates natural gas processing and liquid extraction facilities and natural gas gathering systems. OIL AND GAS PRODUCING ACTIVITIES The results of operations from the Company's oil and gas producing activities are as follows (in thousands):
YEAR ENDED DECEMBER 31, ---------------------------- 1993 1994 1995 -------- -------- -------- Oil and gas sales.............................. $ 38,877 $ 50,683 $ 60,997 Production costs............................... (17,590) (21,646) (27,119) Depletion, depreciation, and amortization...... (10,573) (14,853) (16,889) Income tax expense............................. (3,643) (4,823) (5,776) -------- -------- -------- $ 7,071 $ 9,361 $ 11,213 ======== ======== ========
Costs incurred in oil and gas producing activities are as follows (in thousands, except per equivalent barrel amounts):
YEAR ENDED DECEMBER 31, -------------------------- 1993 1994 1995 -------- -------- -------- Property acquisition costs...................... $ 42,223 $ 40,109 $ 25,363 Development costs............................... 10,403 12,450 14,464 Exploration costs............................... 46 206 511 Production costs................................ 17,590 21,646 27,119 Depletion, depreciation, and amortization rate per equivalent barrel.......................... 4.15 4.27 4.33
All of the Company's oil and gas revenues are from proved developed properties located in the United States. The Company has capitalized internal costs of $658,000, $712,000, and $748,000 for the years ended December 31, 1993, 1994, and 1995, respectively. Such capitalized costs include salaries and related benefits of individuals directly involved in the Company's acquisition, exploration, and development activities based on the percentage of their time devoted to such activities. During the year ended December 31, 1993, sales of oil and gas to two purchasers accounted for 21% and 22% of consolidated gross revenues. During the year ended December 31, 1994, sales of oil and gas to two purchasers accounted for 13% and 22% of consolidated gross revenues. During the year ended December 31, 1995, sales of oil and gas to two purchasers accounted for 10% and 18% of consolidated gross revenues. Management believes that the loss of these purchasers would not have a material impact on the Company's consolidated financial condition or results of operations. F-34 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 During the fourth quarter of 1993, the Company received a payment of oil and gas revenues relating to a recalculation of interests owned in certain of the Company's properties for the period from 1985 through 1993. Oil and gas sales increased by $343,000 as a result. OIL AND GAS HEDGING ACTIVITIES AND COMMITMENTS In an effort to reduce the effects of the volatility of the price of crude oil and natural gas on the Company's operations, management has adopted a policy of hedging oil and gas prices whenever such prices are in excess of the prices anticipated in the Company's operating budget and profit plan through the use of commodity futures, options, and swap agreements. The Company does not hold or issue financial instruments for trading purposes. Hedging transactions require the approval of the Board of Directors. While the use of these hedging arrangements limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. All hedging is accomplished pursuant to exchange-traded contracts or master swap agreements based upon standard forms. The Company addresses market risk by selecting instruments whose value fluctuations correlate strongly with the underlying commodity being hedged. Credit risk related to hedging activities, which is minimal, is managed by requiring minimum credit standards for counterparties, periodic settlements, and marked to market valuations. The Company has not historically been required to provide any significant amount of collateral relating to its hedging activities. At December 31, 1995, the Company had entered into various swap agreements to fix selling prices for crude oil at a weighted average NYMEX price of $18.79 and $19.02 per barrel for 740,000 and 375,000 barrels during 1996 and 1997, respectively. While these contracts have no carrying value, their fair value (the estimated amount that would have been received upon termination of the swaps at December 31, 1995) was approximately $900,000. The Company has also sold call options covering 25,000 Bbls of oil per month at an option price of $18.30 per Bbl for the period October 1995 to August 1996, and at an option price of $20.00 per barrel for the period September 1996 to August 1997. While these call options have no carrying value, their fair value (the estimated amount that would have been paid by the Company upon termination of the call options at December 31, 1995) was approximately $230,000. During the years ended December 31, 1993, 1994, and 1995, oil and gas sales were reduced by $289,000 and $5,000, and increased by $298,000, respectively, as a result of hedging transactions. Pursuant to the loan agreements with Diamond's former lender, Diamond entered into an agreement with a refining and marketing company to sell a fixed number of barrels attributable to its share of production of liquid hydrocarbons from certain secured properties at a price of $15.25 per Bbl. Under the purchase and sale agreement, the remaining commitment was approximately 47,000 Bbls at December 31, 1995. The Company expects to fulfill this commitment during the first quarter of 1996. 8. COMMITMENTS AND CONTINGENCIES The Company does not believe that future costs related to site restoration, dismantlement, and abandonment costs, net of estimated salvage values, will have a significant effect on its results of F-35 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 operations or financial position because the salvage value of equipment and related facilities should approximate or exceed any future expenditures for restoration, dismantlement, or abandonment. The Company has not incurred any net expenditures for costs of this nature during the last three years. The Company is a defendant or co-defendant in minor lawsuits that have arisen in the ordinary course of business. In the lawsuits, management believes, based in part on advice from legal counsel, that the Company has meritorious defense against the claims asserted. Management believes that the ultimate resolution of the lawsuits and claims will not have a material adverse effect on the Company's results of operations or financial position. 9. AGREEMENT AND PLAN OF MERGER On February 16, 1996, pursuant to an Agreement and Plan of Merger dated as of October 30, 1995 (as amended, the "Merger Agreement") by and among Coda, Joint Energy Development Investments Limited Partnership ("JEDI"), an affiliate of Enron Capital & Trade Resources Corp., and Coda Acquisition, Inc. ("Purchaser"), a subsidiary of JEDI, JEDI acquired Coda through a merger (the "Merger") at a price of $7.75 per share in cash. Concurrently with the execution of the Merger Agreement, JEDI and Purchaser entered into certain agreements with certain members of the Company's management concerning their employment with and/or equity participation in the Company after the Merger. The sources and uses of funds related to the Merger were as follows (in millions): Sources of funds: Credit agreement................................................... $ 95.0 JEDI Debt.......................................................... 100.0 Redeemable preferred stock issued to JEDI.......................... 20.0 Common stock issued to JEDI........................................ 90.0 ------ $305.0 ====== Uses of funds: Payments to Coda stockholders, warrantholders and optionholders.... $176.2 Repayment of former credit facility and other indebtedness......... 122.7 Merger costs and other expenses.................................... 6.1 ------ $305.0 ======
The Merger has been accounted for using the purchase method of accounting. As such, JEDI's cost of acquiring Coda has been allocated to the assets and liabilities acquired based on estimated fair values. As a result, the Company's financial position and operating results subsequent to February 16, 1996 will reflect a new basis of accounting and are not comparable to prior periods. 10. 10 1/2% SENIOR SUBORDINATED NOTES On March 18, 1996, the Company completed the sale of $110 million principal amount of 10 1/2% Senior Subordinated Notes due 2006 (the "Notes"). The proceeds of the Notes were used to fully repay the JEDI Debt assumed in the Merger and to partially repay bank debt. The Notes bear interest at an annual rate of 10 1/2% payable semiannually in arrears on April 1 and October 1 of each year. The Notes are general, unsecured obligations of the Company, are subordinated in right of payment to all Senior Debt (as defined in the Indenture governing the Notes) of Coda, and are senior in right of payment to all future subordinated debt of the Company. The claims of the holders of the Notes will be subordinated to Senior Debt, which, as of March 31, 1996, was $81.8 million. F-36 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 The Notes were issued pursuant to an Indenture, which contains certain covenants that, among other things, limit the ability of Coda and its Restricted Subsidiaries (as defined in the Indenture) to incur additional indebtedness and issue Disqualified Stock, pay dividends, make distributions, make investments, make certain other restricted payments, enter into certain transactions with affiliates, dispose of certain assets, incur liens securing pari passu or subordinated indebtedness of Coda and engage in mergers and consolidations. The Notes are not redeemable at Coda's option prior to April 1, 2001. After April 1, 2001, the Notes will be subject to redemption at the option of Coda, in whole or in part, at the redemption prices set forth in the Indenture, plus accrued and unpaid interest thereon to the applicable redemption date. In addition, until March 12, 1999, up to $27.5 million in aggregate principal amount of Notes are redeemable, at the option of Coda on any one or more occasions from the net proceeds of an offering of common equity of Coda, at a price of 110.5% of the aggregate principal amount of the Notes, together with accrued and unpaid interest thereon to the date of the redemption; provided, however, that at least $82.5 million in aggregate principal amount of Notes must remain outstanding immediately after the occurrence of such redemption; provided, further, that any such redemption shall occur within 75 days of the date of the closing of such offering of common equity. In the event of a Change of Control (as defined in the Indenture), holders of the Notes will have the right to require Coda to repurchase their Notes, in whole or in part, at a price in cash equal to 101% of the aggregate principal amount thereof, plus accrued and unpaid interest thereon to the date of repurchase. The Indenture requires that, prior to such a repurchase but in any event within 90 days of such Change of Control, Coda must either repay all Senior Debt or obtain any required consent to such repurchase. Coda's payment obligations under the Notes are fully, unconditionally and jointly and severally guaranteed on a senior subordinated basis by all of Coda's current subsidiaries and future Restricted Subsidiaries. Such guarantees are subordinated to the guarantees of Senior Debt issued by the Guarantors under the Credit Agreement and to other guarantees of Senior Debt issued in the future. The combined condensed financial information of the Company's current subsidiaries, the Guarantors, is as follows:
DECEMBER 31, --------------- 1994 1995 ------- ------- Current assets................................................. $ 7,785 $ 5,394 Oil and gas properties, net.................................... 40,076 36,469 Gas plants and gathering systems, net.......................... 28,007 33,650 Other properties, net and other assets......................... 3,490 1,713 ------- ------- Total assets................................................. $79,358 $77,226 ======= ======= Current liabilities............................................ $ 6,082 $ 5,629 Long-term debt................................................. 1,200 -- Intercompany payables.......................................... 52,595 50,172 Deferred income taxes.......................................... 7,021 7,828 Stockholder's equity........................................... 12,460 13,597 ------- ------- Total liabilities and stockholder's equity................... $79,358 $77,226 ======= =======
F-37 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995
FOR THE YEARS ENDED DECEMBER 31, -------------------------------- 1993 1994 1995 ---------- ---------- ---------- Revenues: Oil and gas sales............................ $ 12,530 $ 17,660 $ 18,826 Gas gathering and processing................. 732 20,031 35,634 Other income................................. 322 251 244 ---------- ---------- ---------- 13,584 37,942 54,704 Costs and expenses: Oil and gas production....................... 4,530 4,706 7,023 Gas gathering and processing................. 571 17,324 30,473 Depletion, depreciation and amortization..... 3,393 6,719 7,776 General and administrative................... 898 1,158 3,936 Business combination......................... -- 1,184 -- Interest..................................... 2,000 2,628 3,538 ---------- ---------- ---------- 11,392 33,719 52,746 ---------- ---------- ---------- Income before income taxes..................... 2,192 4,223 1,958 Income tax expense............................. 949 1,813 822 ---------- ---------- ---------- Net income..................................... $ 1,243 $ 2,410 $ 1,136 ========== ========== ==========
11. SUPPLEMENTAL OIL AND GAS RESERVE AND STANDARDIZED MEASURE INFORMATION (UNAUDITED) The Company retains independent engineering firms to provide annual year-end estimates of the Company's future net recoverable oil, gas, and natural gas liquids reserves. Estimated proved net recoverable reserves as shown below include only those quantities that can be expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under existing regulatory practices and with conventional equipment and operating methods. Proved developed reserves represent only those reserves expected to be recovered through existing wells. Proved undeveloped reserves include those reserves expected to be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure is required for recompletion. Reserve estimates are imprecise and may be expected to change as additional information becomes available. Furthermore, estimates of oil and gas reserves, of necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Accordingly, there can be no assurance that the reserves set forth herein will ultimately be produced nor can there be assurance that the proved undeveloped reserves will be developed within the periods anticipated. The Company emphasizes with respect to the estimates prepared by independent petroleum engineers that the discounted future net cash inflows should not be construed as representative of the fair market value of the proved oil and gas properties belonging to the Company, since discounted future net cash inflows are based upon projected cash inflows which do not provide for changes in oil and gas prices nor for escalation of expenses and capital costs. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. F-38 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 ESTIMATED QUANTITIES OF PROVED RESERVES (IN THOUSANDS)
OIL (BBL) GAS (MCF) --------- --------- December 31, 1992........................................... 18,941 27,830 Purchase of reserves in place............................... 5,872 13,274 Extensions.................................................. 7,165 2,259 Revisions of previous estimates............................. (113) (2,289) Production.................................................. (1,766) (4,703) Sales of reserves in place.................................. (15) (175) ------ ------- December 31, 1993........................................... 30,084 36,196 Purchase of reserves in place............................... 11,038 5,482 Extensions.................................................. 271 912 Revisions of previous estimates............................. 749 4,107 Production.................................................. (2,650) (4,982) Sales of reserves in place.................................. (285) (1,907) ------ ------- December 31, 1994........................................... 39,207 39,808 Purchase of reserves in place............................... 7,324 7,298 Extensions.................................................. 783 3,173 Revisions of previous estimates............................. (1,011) 1,459 Production.................................................. (3,165) (4,416) Sales of reserves in place.................................. (548) (10,192) ------ ------- December 31, 1995........................................... 42,590 37,130 ====== =======
ESTIMATED QUANTITIES OF PROVED DEVELOPED RESERVES (IN THOUSANDS)
OIL (BBL) GAS (MCF) --------- --------- December 31, 1992........................................... 14,413 22,852 December 31, 1993........................................... 16,230 30,573 December 31, 1994........................................... 20,151 32,890 December 31, 1995........................................... 25,877 31,496
F-39 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 The following is a summary of a standardized measure of discounted net cash flows related to the Company's proved oil, gas, and natural gas liquids reserves. The information presented is based on a valuation of proved reserves using discounted cash flows based on year-end prices, costs, and economic conditions and a 10% discount rate. The additions to proved reserves from new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the information presented below should not be viewed as an estimate of the fair value of the Company's oil and gas properties, nor should it be considered indicative of any trends. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (IN THOUSANDS)
DECEMBER 31, ----------------- 1994 1995 -------- -------- Future cash inflows........................................... $696,910 $860,180 Future production and development costs....................... 335,656 366,421 Future income taxes........................................... 81,962 113,775 -------- -------- Future net cash flows......................................... 279,292 379,984 Discount of future net cash flows at 10% per annum............ 110,676 159,242 -------- -------- Discounted future net cash flows after income taxes........... $168,616 $220,742 ======== ========
During recent years, there have been significant fluctuations in the prices paid for crude oil in the world markets. This situation has had a destabilizing effect on crude oil's posted prices in the United States, including the posted prices paid by purchasers of the Company's crude oil. The weighted average prices of oil and gas at December 31, 1994 and 1995, used in the above table, were $16.24 and $18.31 per Bbl, respectively, and $1.45 and $2.19 per Mcf, respectively. The following are the principal sources of change in the standardized measure of discounted future net cash flows (in thousands):
YEAR ENDED DECEMBER 31, ---------------------------- 1993 1994 1995 -------- -------- -------- Sales and transfers of oil and gas produced, net of production costs ........................... $(21,287) $(29,037) $(33,878) Net changes in prices and production costs...... (62,305) 18,674 37,290 Extensions and discoveries, net of future development and production costs............... 29,260 3,673 15,932 Development costs during the period............. 10,403 12,656 14,464 Revisions of previous quantity estimates........ (1,098) 3,579 (19,084) Sales of reserves in place...................... (365) (1,755) (6,323) Purchases of reserves in place.................. 52,732 54,672 35,680 Accretion of discount........................... 11,372 33,592 39,858 Change in income taxes.......................... 1,451 (43,461) (31,813) -------- -------- -------- Net change...................................... $ 20,163 $ 52,593 $ 52,126 ======== ======== ========
F-40 CODA ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(CONTINUED) DECEMBER 31, 1995 12. QUARTERLY FINANCIAL DATA (UNAUDITED) Summarized quarterly financial data for 1994 and 1995 is as follows (in thousands, except for per share amounts):
THREE MONTHS ENDED ----------------------------------------- MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31 -------- ------- ------------ ----------- 1994: Total revenues..................... $11,611 $17,143 $21,608 $21,224 Income before income taxes......... 958 2,003 912 2,037 Net income......................... 553 1,217 255 1,304 Net income per common and common equivalent share.................. 0.03 0.06 0.01 0.06 1995: Total revenues..................... 23,039 25,014 23,292 26,493 Income before income taxes......... 2,101 2,776 1,242 2,838 Net income......................... 1,305 1,814 798 1,838 Net income per common and common equivalent share.................. 0.06 0.08 0.03 0.08
Total revenues, income before income taxes and net income for the three months ended March 31 and June 30, 1994 do not include the operations of Taurus prior to its acquisition in April 1994. Income before income taxes for the three months ended September 30, 1994, includes a charge of $1.8 million for business combination expenses related to the merger with Diamond. F-41 ANNEX A [LEE KEELING AND ASSOCIATES INC. LETTERHEAD] February 2,1996 Coda Energy, Inc. 5735 Pineland Drive, Suite 300 Dallas, Texas 75231 Attention: Mr. T. W. Eubank, President RE: Appraisal Oil and Gas Properties-Coda Energy, Inc. Constant Price Case Gentlemen: In accordance with your request, we have prepared an appraisal of the interests owned by Coda Energy, Inc. in oil and gas leases located in the states of Kansas, Louisiana, Michigan, Mississippi, Montana, North Dakota, Oklahoma and Texas. The effective date of the appraisal is January 1, 1996, and the results are summarized as follows:
ESTIMATED REMAINING NET RESERVES FUTURE NET REVENUE --------------------------- ----------------------------- RESERVE Oil Gas Present Worth CLASSIFICATION (Barrels) (MCF) Total Discounted@10% - -------------------------------------------------------------------------------- Proved - ---------------- Producing 22,163,582 28,294,514 $246,046,146 $164,328,638 Non-Producing 3,411,015 1,837,990 42,198,358 23,031,293 Behind-Pipe 302,825 1,363,229 5,815,305 2,256,265 Undeveloped 16,712,768 5,634,348 199,699,930 93,759,024 ---------- ---------- ------------ ------------ Total Proved 42,590,190 37,130,081 $493,759,739 $283,375,220 Probable 3,808,161 166,958 $ 22,877,915 $ 4,845,438 Possible 3,414,725 3,038,336 $ 25,984,354 $ 8,048,330 ---------- ---------- ------------ ------------ Total All Reserves 49,813,076 40,335,375 $542,622,008 $296,268,988
Note: Totals may differ from schedules due to computer round off. A-1 This report is based on assumptions provided by Coda Energy, Inc. Oil and gas prices and expenses used in this appraisal were held constant throughout the anticipated life of the properties. Future net revenue is the amount, exclusive of state and federal income taxes, which will accrue to the appraised interests from continued operation of the properties to depletion. It should not be construed as a fair market or trading value. No provision has been made for the cost of plugging and abandoning the properties nor for the value of salvable equipment. No attempt has been made to quantify or otherwise account for any accumulative gas production imbalances that may exist. Neither has an attempt been made to determine whether the wells and facilities are in compliance with various governmental regulations, nor have costs been included in the event they are not. This report consists of two volumes. Volume I includes summary forecasts of annual gross and net production, severance and ad valorem taxes, operating income and net revenue, and present worth determinations at various discount rates by reserve type. The company totals are summarized in Schedule No. 1. Schedule No. 2 is a one-line summary of the individual properties arranged alphabetically. Schedule No. 3 is a sequential listing of the individual properties based on discounted future net revenue. Volume II contains determination of future net revenue for the individual properties. CLASSIFICATION OF RESERVES - -------------------------- Reserves attributed to the appraised leases have been classified "proved producing," "proved non-producing," proved behind-pipe," "proved undeveloped," "probable," and "possible." Proved producing reserves are those expected to be recovered from currently - ------------------------- producing zones under continuation of present operating methods. Proved non-producing reserves are those attributable to wells which have been - ----------------------------- drilled, but for various reasons, cannot be classified as producing. This category may also contain reserves attributable to developed waterflood units for which no response has been experienced. Proved behind-pipe reserves are those currently behind the pipe in existing - --------------------------- wells which are considered proved by virtue of successful testing or production in offsetting wells. Proved undeveloped reserves are those attributable to wells to be drilled at - --------------------------- locations which can be considered proved by virtue of favorable structural position and which can be anticipated with a high degree of certainty. A-2 Proved undeveloped reserves also include those attributable to undeveloped - --------------------------- repressuring or pressure maintenance projects in zones whose reserves are considered proved by virtue of successful pilot projects or successful projects which involve those zones in the vicinity. Projects to which this category of reserves has been assigned are either in the process of formation or can be expected with a high degree of certainty to be formed in the near future. Probable reserves are those anticipated from zones in existing wells or from - ----------------- wells to be drilled at locations that cannot be considered proved for lack of actual physical testing, production in the area and/or limited geologic control. These can be either primary or secondary reserves. Possible reserves are those based on criteria similar to those discussed under - ----------------- probable reserves but which must be considered more speculative. These also can be either primary or secondary reserves. ESTIMATION OF RESERVES - ---------------------- The majority of the appraised wells have been producing for a considerable length of time. Reserves attributable to wells with well-defined production trends and/or well-defined cumulative recovery-pressure relationships were based upon extrapolation of these trends or relationships to economic limits and/or abandonment pressures. Reserves anticipated from new wells were based upon volumetric calculations or analogy with similar properties which are producing from the same horizons in the respective areas. Structural position, net pay thickness, well productivity, gas/oil ratios, water production, pressures, and other pertinent factors were considered in the estimations of these reserves. Reserves assigned to behind-pipe zones have been estimated based on volumetric calculation and/or analogy with other wells in the area producing from the same horizon. Primary reserves attributable to undeveloped locations have been based on analogy with offsetting wells. Undeveloped secondary reserves, attributable to additional development of existing waterflood projects, have been based on analogy with the respective projects or other secondary projects in the area with similar characteristics. The proved reserves included in this report conform to the applicable definition promulgated by the Securities and Exchange Commission. A-3 FUTURE NET REVENUE - ------------------ Oil Income - ---------- Income from the sale of oil was established using the December 31, 1995, posted West Texas Intermediate price of $18.00 per barrel. A comparison was made between the West Texas Intermediate price during 1995 and the prices actually received for each lease during the same time period. A difference between West Texas Intermediate and actual pricing was determined and this adjustment was applied to the December 31, 1995, West Texas Intermediate posting on a lease basis. For leases with known contracts or fixed prices, that price was used instead of the relationship to West Texas Intermediate posting. All prices were held constant throughout the life of each lease. Provisions were made for state severance and ad valorem taxes where applicable. Gas Income - ---------- Income from the sale of gas from each lease was based on the December 31, 1995 Henry Hub price of $2.26 per MCF. A comparison was made between the Henry Hub price during 1995 and the price actually received for each lease during the same time period. A difference between Henry Hub and actual pricing was determined and this adjustment was applied to the December 31, 1995 Henry Hub price on a lease basis. For leases with known contracts or fixed prices, that price was used instead of the relationship to the Henry Hub price. All prices were held constant throughout the life of each lease. Adjustments were made for state severance and ad valorem taxes where applicable. Operating Expenses - ------------------ Operating expenses were based upon actual operating costs charged by the respective operators as supplied by the staff of Coda Energy, Inc., or were based upon the actual experience of the operators in the respective areas. For leases operated by Coda Energy, Inc., monthly lease operating expenses do not include overhead charges. All expenses have been held constant throughout the life of each lease. GENERAL - ------- Information upon which this appraisal has been based was furnished by the staff of Coda Energy, Inc. or was obtained by us from outside sources. This information is assumed to be correct. No attempt has been made to verify title or ownership of the appraised properties. A-4 Leases were not inspected by a representative of this firm, nor were the wells tested under our supervision; however, the performance of the majority of the wells was discussed with employees of Coda Energy, Inc. This report has been prepared utilizing methods and procedures regularly used by petroleum engineers to estimate oil and gas reserves for properties of this type and character. The recovery of oil and gas reserves and projection of producing rates are dependent upon many variable factors. These include, among others, prudent operation, compression of gas when needed, market demand, installation of lifting equipment and remedial work when required. The reserves included in this report have been based upon the assumption that the wells will continue to be operated in a prudent manner under the same conditions existing at the present time. Actual production results and future well data may yield additional facts, not presently available to us, which will require an adjustment to our estimates. The reserves included in this report are estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and, if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts. As in all aspects of oil and gas evaluation, therefore are uncertainties inherent in the interpretation of engineering data and, therefore, our conclusions necessarily represent only informed professional judgments. You should be aware that state regulatory authorities could, in the future, change the allocation of reserves allowed to be produced from a particular well in any reservoir, thereby altering the material premise upon which our reserve estimate may be based. The projection of cash flow has been made assuming constant prices. There is no assurance that prices will not vary. For this reason and those listed in the previous paragraph, the future net cash from the sale of production from the appraised properties may vary from the estimates contained in this report. The information developed during the course of this investigation, basic data, maps and worksheets showing recovery determinations are available for inspection in our office. We appreciate this opportunity to be of service to you. Very truly yours, /s/ LEE KEELING AND ASSOCIATES, INC. LEE KEELING AND ASSOCIATES, INC. A-5 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- NO PERSON IS AUTHORIZED IN CONNECTION WITH ANY OFFERING MADE HEREBY TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPEC- TUS, AND, IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RE- LIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY ANY SECURI- TIES 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 CIRCUM- STANCES 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 OR THEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE. ----------- TABLE OF CONTENTS
PAGE ---- Summary.................................................................. 4 Risk Factors............................................................. 18 The Exchange Offer....................................................... 25 The Merger............................................................... 33 Use of Proceeds.......................................................... 34 Capitalization........................................................... 35 Selected Historical and Pro Forma Financial Data......................... 36 Management's Discussion and Analysis of Financial Condition and Results of Operations........................................................... 38 Business................................................................. 50 Management............................................................... 64 Security Ownership of Certain Beneficial Owners and Management........... 66 Executive Compensation and Other Information............................. 67 Certain Transactions..................................................... 70 Description of Exchange Notes............................................ 74 Description of Other Indebtedness........................................ 104 Description of Capital Stock of Coda..................................... 105 Certain Federal Income Tax Considerations................................ 106 Plan of Distribution..................................................... 106 Legal Matters............................................................ 107 Experts.................................................................. 107 Available Information.................................................... 108 Glossary................................................................. 109 Index to Financial Statements............................................ F-1 Summary Reserve Report................................................... A-1
UNTIL SEPTEMBER 9, 1996, ALL DEALERS EFFECTING TRANSACTIONS IN THE EXCHANGE NOTES, WHETHER OR NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DE- LIVER A PROSPECTUS. THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DE- LIVER A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UN- SOLD ALLOTMENTS OR SUBSCRIPTIONS. - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- $110,000,000 [LOGO OF CODA ENERGY, INC. APPEARS HERE] OFFER TO EXCHANGE ITS 10 1/2% SERIES B SENIOR SUBORDINATED NOTES DUE 2006 WHICH HAVE BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, FOR ANY AND ALL OF ITS OUTSTANDING 10 1/2% SERIES A SENIOR SUBORDINATED NOTES DUE 2006 ----------- PROSPECTUS ----------- JUNE 11, 1996 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- -----END PRIVACY-ENHANCED MESSAGE-----