-----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, Us45HFueogF9m9KQpq5rg2R1sgdcmfJgp8+wvk/PpcCNIc455R2FVEa8cUkVIj1Y h625HcEjBHgkF0n9QEC75A== 0000950129-99-000574.txt : 19990217 0000950129-99-000574.hdr.sgml : 19990217 ACCESSION NUMBER: 0000950129-99-000574 CONFORMED SUBMISSION TYPE: 424B3 PUBLIC DOCUMENT COUNT: 1 FILED AS OF DATE: 19990216 FILER: COMPANY DATA: COMPANY CONFORMED NAME: POGO PRODUCING CO CENTRAL INDEX KEY: 0000230463 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 741659398 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 424B3 SEC ACT: SEC FILE NUMBER: 333-72129 FILM NUMBER: 99542337 BUSINESS ADDRESS: STREET 1: 5 GREENWAY PLAZA STE 2700 STREET 2: P O BOX 2504 CITY: HOUSTON STATE: TX ZIP: 77046-0504 BUSINESS PHONE: 7132975017 MAIL ADDRESS: STREET 1: 5 GREENWAY PLAZA SUITE 2700 STREET 2: P O BOX 2504 CITY: HOUSTON STATE: TX ZIP: 77046-0504 FORMER COMPANY: FORMER CONFORMED NAME: PENNZOIL OFFSHORE GAS OPERATORS INC /TX/ DATE OF NAME CHANGE: 19600201 424B3 1 POGO PRODUCING COMPANY FOR REG. NO. 333-72129 1 Filed pursuant to Rule 424(b)(3) Registration No. 333-72129 PROSPECTUS [LOGO] POGO PRODUCING COMPANY $150,000,000 OFFER TO EXCHANGE 10 3/8% SERIES B SENIOR SUBORDINATED NOTES DUE 2009 FOR ALL OUTSTANDING 10 3/8% SERIES A SENIOR SUBORDINATED NOTES DUE 2009 THE NEW NOTES o will be freely tradeable and otherwise substantially identical to the outstanding notes o will accrue interest from January 15, 1999 at the rate of 10 3/8% per annum, payable semi-annually in arrears on each February 15 and August 15, beginning August 15, 1999. o will be unsecured and will rank equally with the outstanding notes and our other unsecured senior subordinated indebtedness. o will not be listed on any securities exchange or on any automated dealer quotation system THE EXCHANGE OFFER o expires at 5:00 p.m., New York City time, on April 5, 1999, unless extended o is not conditioned upon any minimum aggregate principal amount of outstanding notes being tendered IN ADDITION, YOU SHOULD NOTE THAT o all outstanding notes that are validly tendered and not validly withdrawn will be exchanged for an equal principal amount of new notes that are registered under the Securities Act of 1933 o tenders of outstanding notes may be withdrawn any time prior to the expiration of the exchange offer o the exchange of outstanding notes for new notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes YOU SHOULD CONSIDER CAREFULLY THE RISK FACTORS BEGINNING ON PAGE 14 OF THIS PROSPECTUS BEFORE PARTICIPATING IN THE EXCHANGE OFFER. NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THE NEW NOTES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE. THE DATE OF THIS PROSPECTUS IS FEBRUARY 16, 1999. 2 TABLE OF CONTENTS
Forward-Looking Statements.....................................................2 Where You Can Find More Information............................................3 Incorporation of Certain Documents by Reference................................3 Certain Definitions............................................................4 Prospectus Summary.............................................................5 Risk Factors..................................................................14 Private Placement.............................................................24 Use of Proceeds...............................................................24 Capitalization................................................................24 Selected Financial Data.......................................................25 Selected Reserve and Operating Data...........................................27 Management's Discussion and Analysis of Financial Condition and Results of Operations.................................29 Business and Properties.......................................................45 Management and Board of Directors.............................................66 The Exchange Offer............................................................68 Description of the Notes......................................................78 Outstanding Notes Registration Rights Agreement..............................121 Book Entry; Delivery and Form................................................122 Certain Federal Income Tax Consequences......................................124 Plan of Distribution.........................................................125 Transfer Restrictions on Outstanding Notes...................................126 Legal Matters................................................................126 Experts......................................................................126 Index to Consolidated Financial Statements...................................F-1
--------------------------- This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. You should rely only on the information or representations provided in this prospectus. We have not authorized any person to provide information other than that provided in this prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any jurisdiction where the offer is not permitted. You should not assume that the information in this prospectus is accurate as of any date other than the date on the front of this document. --------------------------- FORWARD-LOOKING STATEMENTS Certain of the statements contained or incorporated by reference in this prospectus are forward-looking statements. The use of any of the words "anticipate," "estimate," "expect," "may," "project," "believe" and similar expressions are intended to identify uncertainties. Although we believe the expectations reflected in those forward- looking statements are reasonable, they do involve certain assumptions, risks and uncertainties, and we cannot assure that those expectations will prove to have been correct. Our actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth below and other factors set forth in or incorporated by reference in this prospectus. These factors include: o the cyclical nature of the oil and natural gas industries o uncertainties associated with the United States and worldwide economies 2 3 o current and potential governmental regulatory actions in countries where we own an interest o substantial competitor production increases resulting in oversupply and declining prices o our ability to implement cost reductions o our ability to raise additional capital or sell assets o operating interruptions (including leaks, explosions, fires, mechanical failure, unscheduled downtime, transportation interruptions, and spills and releases and other environmental risks) o fluctuations in foreign currency exchange rates in areas of the world where we own an interest, particularly Southeast Asia o covenant restrictions in our indebtedness o the impact of the Year 2000 problem Many of those factors are beyond our ability to control or predict. Management cautions against putting undue reliance on forward-looking statements or projecting any future results based on such statements or present or prior earnings levels. All subsequent written and oral forward-looking statements attributable to us and persons acting on our behalf are qualified in their entirety by the cautionary statements contained in this section and elsewhere in this prospectus. WHERE YOU CAN FIND MORE INFORMATION This prospectus incorporates important business and financial information about us that we have not included in or delivered with this prospectus. This information is available without charge upon written or oral request. You should make any request to Gerald A. Morton, Pogo Producing Company, 5 Greenway Plaza, Suite 2700, Houston, Texas 77046-0504, telephone number: (713) 297-5000. To ensure timely delivery, you should request the information no later than March 26, 1999. See "Incorporation of Certain Documents by Reference." We file annual, quarterly and special reports, proxy statements and other information with the Securities and Exchange Commission (the "SEC"). Our SEC filings are available to the public over the Internet at the SEC's web site at http://www.sec.gov. You may also read and copy any document we file with the SEC at its public reference facilities at 450 Fifth Street, N.W., Washington, D.C. 20549. You can also obtain copies of the documents at prescribed rates by writing to the Public Reference Section of the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference facilities. You can also obtain information about us at the offices of the New York Stock Exchange, 20 Broad Street, New York, New York 10005. INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE We "incorporate by reference" into this prospectus certain information we file with the SEC, which means that we can disclose important information to you by referring you to those documents. The information incorporated by reference is an important part of this prospectus and information that we subsequently file with the SEC will automatically update this prospectus. We incorporate by reference the documents listed below (collectively, the "Reports") and any filings we make with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the Exchange Act after the date of this prospectus and before the termination of the offering made under this prospectus: o Our Annual Report on Form 10-K for the year ended December 31, 1997 (the "Annual Report") 3 4 o Our Quarterly Reports on Form 10-Q for the quarters ended March 31, 1998, June 30, 1998, and September 30, 1998, as amended You may request a copy of these filings (other than an exhibit to a filing unless that exhibit is specifically incorporated by reference into that filing) at no cost, by writing to or telephoning us at the following address: Pogo Producing Company Corporate Secretary 5 Greenway Plaza, Suite 2700 Houston, Texas 77046-0504 (713) 297-5017 CERTAIN DEFINITIONS As used in this prospectus, "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf" means billion cubic feet, "Bbl" means barrel, "MBbls" means thousand barrels and "MMBbls" means million barrels. "BOE" means barrel of oil equivalent, "Mcfe" means thousand cubic feet of natural gas equivalent, "MMcfe" means million cubic feet of natural gas equivalent and "Bcfe" means billion cubic feet of natural gas equivalent. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids ("NGL"). "EBITDA" means income from continuing operations before provision for income taxes, interest expense, depreciation, depletion and amortization, and dry hole and impairment costs. References to "$" and "dollars" refer to United States dollars. All estimates of reserves contained in this prospectus, unless otherwise noted, are reported on a "net" basis. Information regarding production, acreage and numbers of wells are set forth on a gross basis, unless otherwise noted. 4 5 PROSPECTUS SUMMARY This summary may not contain all the information that is important to you. You should read the entire prospectus, including the financial data and related notes, before making an investment decision. The terms "the Company", "we", "our", "ours" and "us" as used in this prospectus refer to "Pogo Producing Company" and its subsidiaries and predecessors as a combined entity. We acquired Arch Petroleum Inc. and its subsidiaries ("Arch") on August 17, 1998, in a stock-for-stock, tax-free merger which was accounted for using the purchase method of accounting. Company financial and operating data as of dates and for periods after August 17, 1998, include financial and operating data for Arch. You should carefully consider the information set forth under the heading "Risk Factors." This prospectus contains certain forward-looking statements which involve risks and uncertainties. Our actual results may differ significantly from the results discussed in the forward-looking statements. See "Forward-Looking Statements." The term "outstanding notes" refers to the 10 3/8% Series A Senior Subordinated Notes due 2009 that were issued January 15, 1999. The term "new notes" refers to the 10 3/8% Series B Senior Subordinated Notes due 2009 issuable in the exchange offer. The term "notes" refers to the outstanding notes and the new notes collectively. POGO PRODUCING COMPANY We are an independent oil and gas exploration and production company with a well balanced portfolio of domestic and international properties. Our properties produced approximately 60% natural gas and 40% oil over the nine months ended September 30, 1998. As of December 31, 1997, approximately 52% of our proved reserves were located in the United States where we currently own interests in 105 lease blocks (comprising 455,600 gross acres) in the offshore Gulf of Mexico and approximately 378,000 gross acres onshore, primarily in Texas, New Mexico and Louisiana. Our remaining proved reserves, as of December 31, 1997, were located in the Gulf of Thailand where we currently own interests in 734,000 gross acres. We also own interests in approximately 150,000 gross acres in Western Canada, and we were recently awarded a license on 113,000 gross acres in the U.K. sector of the North Sea. Our 1997 year-end worldwide proved reserves totaled 64,045 MBbls of liquid hydrocarbons and 478,373 MMcf of natural gas or 862,643 MMcfe (including reserves we acquired in the Arch acquisition). For the twelve months ended September 30, 1998, our total revenues were $230,641,000 and EBITDA was $126,171,000. Our exploration strategy is to concentrate our efforts on selected areas where we believe that our expertise, competitive acreage position, or ability to quickly take advantage of new opportunities offers the potential for achieving a significant return on our investment. We have established a record of increasing our proven hydrocarbon reserves over the last seven years, principally through the exploration, exploitation and development of our properties and, to a lesser extent, the selective acquisition of additional interests in producing properties in which we already have an interest. An important measure of our success is our record for replacing the oil and gas which we produce each year. From 1993 through 1997, we replaced each year's production with new proved reserves at the following rates:
PERCENTAGE OF PRODUCTION YEAR REPLACED - ---- ------------- 1993............................................ 204% 1994............................................ 153% 1995............................................ 305% 1996............................................ 187% 1997............................................ 188%
5 6 Our cost for replacing these reserves averaged $5.43 per BOE over the five year period. As a result of our continuing successful exploration, exploitation and development activities, we currently believe that we have replaced our 1998 worldwide production (excluding the reserves we acquired in the Arch acquisition). We believe that another measure of our success is the number of successful wells that we have participated in drilling. Since December 31, 1993, we have participated in drilling 508 gross wells, 89% of which were successful. COMPETITIVE STRENGTHS We believe we are well positioned to continue to build upon our historical success by capitalizing on our strengths, including the following: o Diversified Portfolio of Core Properties. We benefit from a portfolio of existing properties which provide geographic diversification while being of sufficient size and potential to enable us to concentrate our resources and regional expertise. For example, as of December 31, 1997, 90% of our proved liquid hydrocarbon reserves and 82% of our proved natural gas reserves were located in six operating areas in four geographic regions. This concentration of core properties permits us to maintain a focused exploration and development program by using the substantial geological and operating expertise that we have gained over years of participating in these areas. We also use the experience that we gain in our core areas to evaluate new opportunities in areas with similar characteristics. For example, we used the experience we gained in the Gulf of Mexico to develop our concession in the Gulf of Thailand. Since our Thailand concession was granted in August 1991, we have discovered over 375 Bcfe of proven reserves (as of December 31, 1997) on this acreage net to our interest. o Significant Further Potential From Existing Properties. We believe that our existing properties continue to hold significant further potential for increased production and the discovery of additional reserves. For example, we expect a significant increase in our production rates when the Benchamas Field comes onstream in the third quarter of 1999. In addition, we currently expect to spend approximately $170,000,000 during 1999 to develop our existing properties, including drilling approximately 110 gross wells. o Balanced Risk Profile; Prudent Exposure to Higher Return Opportunities. We seek to manage our risk exposure by maintaining a prudent level of participation in our projects. We seek to operate properties where we believe that our working interest percentage, expertise or ability to control the timing or cost of a project provides a competitive advantage to us and our partners. On properties where we are not the operator, we try to have a meaningful working interest so that we can influence operating and development decisions regarding them. Generally, we seek a higher level of participation in projects which we view as having potentially high rates of return and relatively low anticipated exploration and development costs, such as our operations in southeastern New Mexico and West Texas. Conversely, we will generally seek a lower level of participation in projects that have high drilling costs, a long lead time until production can come onstream, or where development costs may be disproportionately high, such as wells in intermediate water depths (600 to 4,400 feet) in the Gulf of Mexico or wells that are unusually deep or are considered highly risky. We currently operate all or a portion of 27 of the 105 lease blocks in which we own interests in the Gulf of Mexico. o Technical Expertise. We have an experienced staff of engineers and geoscientists that comprise over 40% of our total full-time personnel. Our personnel's expertise, augmented by data from over 500 gross wells drilled since December 31, 1993, more than 4,800,000 acres of 3-D seismic data and 112,700 miles of 2-D seismic data, create a knowledge base which we use to establish our drilling priorities and associated capital budget. BUSINESS STRATEGY Our business strategy is to maximize profitability and shareholder value by: 6 7 o increasing hydrocarbon production levels, leading to increased revenues, cash flow and earnings o replacing and expanding our proven hydrocarbon reserves base o maintaining appropriate levels of debt and interest, and controlling overhead and operating costs o expanding exploration and production activities into new and promising geographic areas consistent with our expertise To implement our business strategy, we currently are principally focused in the following four geographic areas: DOMESTIC OPERATIONAL AREAS Gulf of Mexico. As of December 31, 1997, approximately 31% of our total proved oil and gas reserves and approximately 59% of our domestic proved oil and gas reserves were located in the Gulf of Mexico, where we have explored for nearly 30 years. Most of these proved reserves are concentrated in four significant producing areas, including eight fields in the Eugene Island area located off the Louisiana coast. This concentration allows us to closely manage costs and to develop detailed geologic and other information relating to these areas. We believe that the Gulf of Mexico will continue to provide us with substantial opportunities to expand our hydrocarbon reserves and increase our deliverability by using our extensive inventory of 3-D seismic data (covering the equivalent of 600 federal Gulf of Mexico lease blocks) to locate low risk exploration and development projects, and by using advanced drilling technology, including horizontal drilling, to accelerate development of these projects. For example, within the last several years we have acquired interests in 15 lease blocks in intermediate water depths (ranging from 600 feet to 4,400 feet). We have participated in drilling six wells on these lease blocks, all of which have been successful. Together with our partners, we are currently developing three projects on these blocks, two of which should commence producing during the first quarter of 1999, and the other should come onstream in the first quarter of 2000. Permian Basin. As of December 31, 1997, approximately 12% of our total proved oil and gas reserves, and approximately 24% of our domestic proved oil and gas reserves were located in the Permian Basin where we have explored for over 20 years. According to the most recently published annual figures, we are the ninth largest producer of crude oil in New Mexico. We believe that we will continue to be one of the most active companies drilling for oil and gas in the southeastern New Mexico portion of the Permian Basin, where we have interests in over 101,000 gross acres. Our primary drilling objective in this region is the Brushy Canyon (Delaware) formation, which produces oil at depths of approximately 6,000 to 9,000 feet. Commencing in late 1989 and continuing through December 31, 1998, we (excluding Arch) and our partners drilled 389 wells in the Permian Basin area, of which 96% were completed as productive. We generally achieve rapid cost recovery on our Permian Basin wells because of relatively low capital costs and high initial rates of production. We currently expect our Permian Basin operations to continue to be a source of significant future oil production. Onshore Gulf Coast Region. We have maintained an active presence in the Onshore Gulf Coast region for over 20 years. Over the last several years, we have committed considerable resources to increasing our presence in promising areas where we believe that our technological expertise, acreage position and comparatively low operating costs provide a competitive advantage. Commencing in 1994, we have participated in nine proprietary and several speculative 3-D seismic surveys in the Onshore Gulf Coast region. Since that time, we have participated in the drilling of 58 new wells based in part on prospects developed from those surveys. Successful drilling, based in large part on these surveys, has enabled us to more than double our proven reserves in this region from approximately 25 Bcfe as of December 31, 1995, to approximately 68 Bcfe as of December 31, 1997. INTERNATIONAL OPERATIONAL AREAS Gulf of Thailand. In August 1991, together with our joint venture partners, we were awarded a license to explore for oil and gas on the Kingdom of Thailand's Block B8/32 Concession in the Gulf of Thailand. Through 7 8 December 31, 1998, we have drilled 108 exploratory and development wells and acquired 3-D seismic surveys covering approximately 673,650 acres. At December 31, 1997, approximately 48% of the Company's total proved oil and gas reserves were located on the concession. The first portion of the concession that we developed was the Tantawan Field. Through December 31, 1998, we have drilled 19 exploration wells and 31 development wells in the Tantawan Field. Production from the Tantawan Field began in early February 1997. During the third quarter of 1998, production averaged 76.2 MMcf of natural gas per day and 5,605 Bbls of crude oil and condensate per day (35.3 MMcf per day and 2,598 Bbls per day net to our working interest). We plan to drill additional development wells in the Tantawan Field during the first quarter of 1999. We are currently developing a second field on the concession that is known as the Benchamas Field. The Benchamas Field does not appear to be as highly faulted and the depositional environment of the reservoir rock appears to be different from what we found in the Tantawan Field. We currently believe this means the reservoirs in the Benchamas Field will be larger and more contiguous than those in the Tantawan Field. Through December 31, 1998, we have drilled 21 exploration wells and 28 development wells in the Benchamas Field. Recently we announced the results of three wells in this field, the Benchamas 22, 19 and A-7 wells. The Benchamas 22 well contained 278 feet of hydrocarbon bearing sands. The Benchamas 19 well contained 257 feet of hydrocarbon bearing sands, and the Benchamas A-7 contained 435 feet of hydrocarbon bearing sands. Drilling and platform construction continue in the Benchamas Field, where we currently expect to begin producing in the third quarter of 1999. The government of the Kingdom of Thailand has also granted us a production license to develop a third field on the concession known as the Maliwan Field. We have also started exploring in another part of the concession known as the Jarmjuree area, where we drilled three wells which located hydrocarbons during the third quarter of 1998. We currently plan to drill additional appraisal wells in the Maliwan Field during 1999, as well as more exploratory wells on other parts of the concession that have not yet been designated as production licenses. Rutherford-Moran Oil Corporation, the parent company of Thai Romo Ltd., one of our partners in our Thailand concession, has recently announced that it has agreed to be acquired by Chevron Corporation. The acquisition is subject to conditions, several of which are outside of Rutherford-Moran's control. One of these conditions is that Chevron reach agreement with us on a new joint operating agreement that would include the transfer of operatorship on the Thailand concession from our subsidiary to a subsidiary of Chevron. Although we have held discussions with Chevron on this subject, we do not know whether we can reach a mutually satisfactory agreement with Chevron. In addition to developing our concession in the Gulf of Thailand, we continue to actively evaluate potentially high return projects in other areas of the world with relatively stable political and financial climates, such as Canada and certain European and ASEAN ("Association of Southeast Asian Nations") countries. As a result of our acquisition of Arch in August 1998, we own interests in approximately 150,000 gross acres located primarily in Alberta and British Columbia. In another promising development, in December 1998, the United Kingdom's Department of Trade and Industry announced that we, together with two partners, had been awarded two blocks in the Central Graben area of the North Sea covering approximately 113,000 gross acres. The license to explore these two blocks is for an initial six-year term. -------------------- Our principal executive offices are located at 5 Greenway Plaza, Suite 2700, Houston, Texas 77046, telephone (713) 297-5000. 8 9 SUMMARY OF THE EXCHANGE OFFER On January 15, 1999, we completed the private offering of the outstanding notes. We entered into a registration rights agreement with the initial purchasers in the private offering in which we agreed to deliver to you this prospectus and to complete the exchange offer within 180 days after the date we issued the outstanding notes. You are entitled to exchange in the exchange offer your outstanding notes for new notes with substantially identical terms. You should read the discussion under the headings "--Summary of the Terms of the New Notes" beginning on page 12 and "Description of the Notes" beginning on page 78 for further information regarding the new notes. We summarize the terms of the exchange offer below. You should read the discussion under the headings "The Exchange Offer" beginning on page 68 for further information regarding the exchange offer and resale of the new notes.
The Exchange Offer......................... We are offering to exchange up to $150 million aggregate principal amount of new notes for up to $150 million aggregate principal amount of the outstanding notes. Outstanding notes may be exchanged only in integral multiples of $1,000. Expiration Date............................ The Exchange Offer will expire at 5:00 p.m., New York City time, on April 5, 1999, or such later date and time to which we extend it. Withdrawal of Tenders...................... You may withdraw your tender of outstanding notes at any time prior to the expiration date, unless previously accepted for exchange. We will return to you, without charge, promptly after the expiration or termination of the exchange offer any outstanding notes that you tendered but that were not accepted for exchange. Conditions to the Exchange Offer........... We will not be required to accept outstanding notes for exchange if the exchange offer would be unlawful or would violate any interpretation of the staff of the SEC. The exchange offer is not conditioned upon any minimum aggregate principal amount of outstanding notes being tendered. Please read the section "The Exchange Offer--Conditions to the Exchange Offer" beginning on page 70 for more information regarding the conditions to the exchange offer. Procedures for Tendering Outstanding Notes....................... If your outstanding notes are held through The Depositary Trust Company and you wish to participate in the exchange offer, you may do so through the automated tender offer program of The Depositary Trust Company. If you tender under this program, you will agree to be bound by the letter of transmittal that we are providing with this prospectus as though you had signed the letter of transmittal. By signing or agreeing to be bound by the letter of transmittal, you will represent to us that, among other things: o any new notes that you receive will be acquired in the ordinary course of your business o you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes o if you are not a broker-dealer, you are not engaged in and do not intend to engage in the distribution of the new notes
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o if you are a broker-dealer that will receive new notes for your own account in exchange for outstanding notes that were acquired as a result of market-making activities, you will deliver a prospectus, as required by law, in connection with any resale of such new notes o you are not our "affiliate," as defined in Rule 405 of the Securities Act of 1933, or, if you are our affiliate, you will comply with any applicable registration and prospectus delivery requirements of the Securities Act of 1933 Special Procedures for Beneficial Owners......................... If you own a beneficial interest in outstanding notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender the outstanding notes in the exchange offer, you should contact the registered holder promptly and instruct the registered holder to tender on your behalf. Guaranteed Delivery Procedures............. If you wish to tender your outstanding notes and cannot comply, prior to the expiration date, with the applicable procedures under the automated tender program of The Depositary Trust Company, you must tender your outstanding notes according to the guaranteed delivery procedures described in "The Exchange Offer--Guaranteed Delivery Procedures" beginning on page 74. Certain U.S. Federal Income Tax Considerations...................... The exchange of outstanding notes for new notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read "Certain Federal Income Tax Consequences" beginning on page 124. Use of Proceeds............................ We will not receive any cash proceeds from the issuance of new notes.
10 11 THE EXCHANGE AGENT We have appointed State Street Bank and Trust Company as exchange agent for the exchange offer. You should direct questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for the notice of guaranteed delivery to the exchange agent addressed as follows: FOR DELIVERY BY MAIL: FOR OVERNIGHT DELIVERY ONLY OR BY HAND: State Street Bank and Trust Company State Street Bank and Trust Company Corporate Trust Department Corporate Trust Department P.O. Box 778 4th Floor, Two International Place Boston, MA 02102-0078 Boston, MA 02110 Attn: Kellie Mullen Attn: Kellie Mullen FOR FACSIMILE TRANSMISSION (FOR ELIGIBLE INSTITUTIONS ONLY): (617) 664-5739 To Confirm Receipt: (617) 664-5314 11 12 SUMMARY OF TERMS OF THE NEW NOTES The new notes will be freely tradeable and otherwise substantially identical to the outstanding notes. The new notes will not have registration rights or provisions for additional interest. The new notes will evidence the same debt as the outstanding notes, and the outstanding notes are and the new notes will be governed by the same indenture.
Notes Offered............................ $150,000,000 aggregate principal amount of 10 3/8% Series B Senior Subordinated Notes due 2009. Maturity Date............................ February 15, 2009. Interest Payment Dates................... February 15 and August 15 of each year, commencing August 15, 1999. Optional Redemption...................... We may redeem any or all of the new notes at any time on or after February 15, 2004. We will pay a redemption price equal to the principal amount of the notes we redeem plus a make-whole premium, which is described under "Description of the Notes -- Redemption; Optional Redemption" on page 79. We will also pay accrued and unpaid interest. Possible Subsidiary Guarantees............................... None of our subsidiaries will guarantee the new notes initially. If our existing or future restricted subsidiaries guarantee any of our other indebtedness, however, they will be required by the indenture governing the new notes to jointly and severally guarantee the new notes on a senior subordinated basis. We do not intend to cause any subsidiary to take any action that would require it to guarantee the new notes. Any subsidiary guarantees of the new notes that may be issued will be limited to the extent of any payment that would not constitute a fraudulent transfer or conveyance under federal or state law. See "Risk Factors -- Future subsidiary guarantees may be affected by fraudulent conveyance laws" on page 22 and "Description of the Notes -- Possible Subsidiary Guarantees of the Notes" beginning on page 82. Change of Control........................ Upon certain change of control events, each holder of notes may require us to purchase all or a portion of its notes at a purchase price equal to 101% of the principal amount of those notes, together with accrued and unpaid interest, if any, to the date of purchase. See "Description of the Notes -- Certain Covenants; Change of Control" beginning on page 88. Ranking.................................. The new notes will be our general unsecured senior subordinated obligations. They will be subordinated in right of payment to all our existing and future Senior Indebtedness. The new notes will rank equally with all our existing and future senior subordinated indebtedness and senior in right of payment to all our existing and future Subordinated Indebtedness. The terms "Senior Indebtedness" and "Subordinated Indebtedness" are defined with respect to the notes in "Description of the Notes -- Certain Definitions" which begins on page 99. Certain Covenants........................ The indenture governing the outstanding notes and the new notes contains covenants that, among other things, limit our ability, and the ability of our restricted subsidiaries to:
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o incur additional indebtedness o make certain investments o pay dividends on, redeem or repurchase our capital stock o issue and sell our restricted subsidiaries' capital stock o engage in transactions with affiliates o create certain liens o dispose of asset sales proceeds o guarantee indebtedness o incur senior subordinated indebtedness that does not rank equal to the notes o merge, consolidate and sell assets These covenants have various exceptions and qualifications, which are described under "Description of the Notes -- Certain Covenants" which begins on page 83. Right under Registration Rights Agreement......................... If we fail to complete the exchange offer as required by the registration rights agreement, we will be obligated to pay additional interest to holders of the outstanding notes. Please read "Outstanding Notes Registration Rights Agreement" beginning on page 121 for more information regarding your rights as a holder of outstanding notes. Absence of a Public Market for the Notes............................ The new notes will be a new issue of securities for which there is currently no market. Although the initial purchasers of the outstanding notes have informed us that they each currently intend to make a market in the new notes issued in the exchange offer, they are not obligated to do so. Any such market making may be discontinued at any time without notice. Accordingly, we cannot assure you as to the development or liquidity of any market for the notes. Risk Factors............................. You should consider carefully the risks described in "Risk Factors," beginning on page 14.
SELECTED FINANCIAL DATA Please read "Selected Financial Data" beginning on page 25 for our selected financial date for the five-year period ended December 31, 1997, and the nine month periods ended September 30, 1998 and 1997. SELECTED RESERVE AND OPERATING DATA Please read "Selected Reserve and Operating Data" beginning on page 27 for our selected reserve and operating data for the five-year period ended December 31, 1997, and the nine month periods ended September 30, 1998 and 1997. 13 14 RISK FACTORS Your investment in the notes involves certain risks. You should carefully consider the following Risk Factors before making an investment decision. VOLATILITY OF OIL AND GAS MARKETS AFFECTS US Market prices are volatile Our profitability and cash flow depend greatly on the market prices of oil and natural gas. Those market prices have historically been seasonal, cyclical and volatile. They depend on many factors, including weather, economic, political and regulatory conditions that we cannot control. Commencing in 1997, the average prices for our production have generally declined. Oil prices have reached lows that, on a historic inflation adjusted basis, are almost unprecedented. In the past, we have at times curtailed production to mitigate the effects of low market prices. We may do so again. The significant drop in oil or gas prices has had a serious adverse effect on our cash flow and continued low prices could seriously affect our operations and financial condition and could in some cases result in a further reduction in funds available under our bank credit agreement. Hedging transactions may not prevent losses We cannot predict future oil and gas prices with certainty. Accordingly, we sometimes execute contracts on a portion of our production to hedge against market price changes. In the past, we have not entered hedging transactions exceeding 50% of our total oil and gas production on an energy equivalent basis for any given period. Hedging transactions are intended to limit the negative effect of further price declines, but could also limit our participation in significant price increases for the covered period. We cannot be certain that hedging transactions will reduce the effect of any substantial declines in oil and gas prices. As of December 31, 1998, we were not a party to any natural gas futures contracts, crude oil swap agreements or other commodity hedging agreements. WE ARE SUBJECT TO UNCERTAINTIES IN RESERVE ESTIMATES AND FUTURE NET REVENUES There is substantial uncertainty in estimating quantities of proved reserves and projecting future production rates and the timing of development expenditures. No one can measure underground accumulations of oil and gas in an exact way. Accordingly, oil and gas reserve engineering requires subjective estimations of those accumulations. Estimates of other engineers might differ widely from those of our reserve engineers, Ryder Scott. Accuracy of reserve estimates depends on the quality of available data and on engineering and geological interpretation and judgment. Ryder Scott may make material changes to reserve estimates based on the results of actual drilling, testing, and production. As a result, our reserve estimates often differ from the quantities of oil and gas we ultimately recover. Also, we make certain assumptions regarding future oil and gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions could greatly affect our estimates of reserves and future net revenues. The reserve estimates and estimates of future net income included in this prospectus were prepared as of December 31, 1997. See "Business and Properties -- Exploration and Production Data; Reserves." As a result of current low oil and natural gas prices, estimates of our future net revenues, as of December 31, 1998, will be significantly lower than they were at year-end 1997. See "Selected Reserve and Operating Data." WE ARE SUBJECT TO OPERATING AND UNINSURED RISKS We must continually acquire or explore for and develop new oil and natural gas reserves to replace those produced and sold. Our hydrocarbon reserves and revenues will decline if we are not successful in our drilling, acquisition or exploration activities. Although we have historically maintained our reserves base primarily through successful exploration and development operations, we cannot assure that future efforts will be similarly successful. Casualty risks and other operating risks could cause reserves and revenues to decline. 14 15 We are subject to various casualty risks Our onshore and offshore operations are subject to the following inherent casualty risks: o blowouts, cratering, and explosions o uncontrollable flows of oil, natural gas or well fluids o fires o pollution and other environmental risks o hazards of marine and helicopter operations (capsizing, collision and adverse weather and sea conditions) We could suffer substantial financial losses due to any of the following: o injury or loss of life o severe damage to and destruction of property and equipment o pollution and other environmental damage o suspension of operations We may not have enough insurance to cover some operating risks We carry insurance which we believe is in accordance with customary industry practices, but we are not fully insured against all casualty risks incident to our business. We are subject to various other operating risks Numerous risks affect drilling our activities, including the risk of drilling non-productive wells or dry holes. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. Also, our drilling operations could diminish or cease because of any of the following: o title problems o weather conditions o noncompliance with governmental requirements o shortages or delays in the delivery or availability of equipment or fabrication yards Moreover, effective marketing of our natural gas production depends on a number of factors, such as the following: o existing market supply of and demand for natural gas o the proximity of our reserves to pipelines o the available capacity of such pipelines o government regulations The marketing of oil and gas production similarly depends on the availability of pipelines and other transportation, processing and refining facilities, and the existence of adequate markets. As a result, even if hydrocarbons are discovered in commercial quantities, a substantial period of time may elapse before commercial production commences. If pipeline facilities in an area are insufficient, we may have to wait for the construction or expansion of pipeline capacity before we can market production from that area. See "-- We face additional risks related to our operations in the Kingdom of Thailand" and "Business and Properties -- Miscellaneous" and "-- Government Regulation." WE DEPEND ON OTHER OPERATORS Even on properties we do not operate, we try to maintain significant influence over the nature and timing of exploration and development activities to the extent we can. However, we have limited influence over operations on 15 16 a significant percentage of our oil and gas properties, including control over the maintenance of safety and environmental standards. For those properties: o operators could refuse to initiate exploration or development projects (in which case we may propose desired exploration or development activities) o if we proceed with any of those projects the operator has refused to initiate, we may not receive any funding from the operator with respect to that project o the operators may initiate exploration or development projects on a slower schedule than we prefer o the operator may propose to drill more wells or build more facilities on a project than we have funds for, which may mean that we cannot participate in those projects or share in a substantial share of the revenues from those projects Any of these events could significantly affect our anticipated exploration and development activities. See "Business and Properties -- Miscellaneous." WE HAVE SUBSTANTIAL CAPITAL REQUIREMENTS We have substantial anticipated capital requirements. Our ongoing capital requirements consist primarily of the following items: o funding the remainder of our 1998 capital and exploration budget o the capital and exploration budget for 1999 o other allocations for acquisition, development, production, exploration and abandonment of oil and gas reserves o costs associated with our Thailand operations o future dividend payments From 1996 to 1997, we increased our capital and exploration expenditures from $206.2 million to $229.5 million (excluding purchased reserves and interest capitalized). We budgeted $230 million for capital and exploration expenditures in 1998 (excluding purchased reserves and interest capitalized). Substantially all of our 1998 capital and exploration budget has been spent or incurred. Our 1999 capital and exploration budget has been established by our Board of Directors at $170 million (excluding purchased reserves and interest capitalized). We plan to finance anticipated ongoing expenses and capital requirements with funds generated from the following sources: o available cash and cash investments o cash provided by operating activities o funds available under our bank credit agreement after the application of proceeds from the notes offering o our uncommitted bank line of credit and banker's acceptances o capital we believe we can raise through debt and convertible preferred equity offerings o asset sales We believe the funds provided by these sources will be sufficient to meet our 1999 cash requirements. However, the uncertainties and risks associated with future performance and revenues, as described in this section, will ultimately determine our liquidity and ability to meet our anticipated capital requirements. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources; Capital Structure; Credit Agreement and Uncommitted Credit Line." 16 17 WE FACE SIGNIFICANT COMPETITION The oil and gas industry is highly competitive. We compete with major oil companies, other independent oil and gas concerns and individual producers and operators. Many of these competitors have much greater financial and other resources than us. Moreover, the oil and gas industry competes with other industries in supplying the energy and fuel needs of industrial, commercial and other consumers. Increased competition causing oversupply or depressed prices could greatly affect our operations revenues. THE RIGHT TO RECEIVE PAYMENTS ON THE NOTES IS JUNIOR TO OUR SENIOR DEBT; THE NOTES ARE STRUCTURALLY SUBORDINATED TO OBLIGATIONS OF OUR SUBSIDIARIES The notes are senior subordinated obligations. Accordingly, the notes are subordinated to all of our existing and future senior indebtedness, including indebtedness under our bank credit agreement. We expect to incur additional senior indebtedness from time to time in the future under our bank credit agreement or otherwise. The indenture governing the notes limits, but does not prohibit, the incurrence of any other indebtedness by us or our subsidiaries, including senior indebtedness. The terms "senior indebtedness" and "indebtedness" are defined in the "Description of the Notes -- Certain Definitions" section of this prospectus. Assuming we had issued the outstanding notes and applied the proceeds on September 30, 1998, we would have had approximately $23,179,000 principal amount of outstanding senior indebtedness. Upon any distribution of assets, liquidation, dissolution, reorganization or any similar proceeding by or relating to us, the holders of our senior indebtedness would be entitled to receive payment in full before the holders of the notes would be entitled to receive any payment. The terms and conditions of the subordination provisions pertinent to the notes are described in more detail in "Description of the Notes -- Subordination." The notes are effectively subordinated to claims of creditors of our subsidiaries (other than us) that are not guarantors of the notes, including lessors, trade creditors, taxing authorities, creditors holding guarantees and tort claimants. In the event of a liquidation, reorganization or similar proceeding relating to a subsidiary that is not a guarantor of the notes, these persons generally will have priority as to the assets of that subsidiary over our claims and equity interest and, thereby indirectly, holders of our indebtedness, including the notes. Currently, none of our subsidiaries guarantee the notes. However, under certain circumstances, our payment obligations under the notes may in the future be required to be jointly and severally guaranteed by our existing or future subsidiaries. See "Description of the Notes -- Possible Subsidiary Guarantees of the Notes." THE NOTES ARE UNSECURED In addition to being subordinate to all of our senior indebtedness, the notes are not secured by any of our assets. Under certain circumstances, our obligations under our bank credit agreement may become secured by some of our oil and gas properties. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources; Capital Structure." If the bank obligations become secured, and then we become insolvent, are liquidated, or payment under our bank credit agreement is accelerated, the lenders under our bank credit agreement would be entitled to exercise the remedies available to a secured lender under applicable law. Under these circumstances our bank lenders would have a secured claim on some of our assets before the holders of these notes. Because the notes are unsecured, there could be no assets remaining for the holders of the notes or any remaining assets could be insufficient to pay off the notes. OUR SUBSIDIARIES HAVE INDEBTEDNESS AND MAY INCUR ADDITIONAL INDEBTEDNESS At September 30, 1998, our subsidiaries (principally Thaipo Ltd. ("Thaipo") and Arch) had total combined assets of $370,029,000 (exclusive of net receivables to us) and liabilities of $39,313,000 (exclusive of net payables to us). Both the combined assets and liabilities are exclusive of assets and liabilities associated with transactions treated as operating leases in our consolidated financial statements. Among other obligations, Thaipo has guaranteed its pro rata portion of obligations under an eleven and a half year bareboat charter of a Floating Production, Storage and 17 18 Offloading system used for development of the Tantawan production area. The portion of the obligations under the bareboat charter guaranteed by Thaipo is currently estimated at $11,122,000 per year for the first ten years. Thaipo has also entered into a ten year bareboat charter of a Floating Storage and Offloading system for the Benchamas Field at an estimated annual cost of approximately $5,215,000, commencing in mid-1999. The documents governing such obligations state that we have no liability for those obligations. In addition, our subsidiaries may incur other liabilities in the future. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources; Other Material Long-Term Commitments." The indenture governing the notes limits our and our subsidiaries' ability to incur additional indebtedness and liens and to enter into agreements that would restrict the ability of our subsidiaries to make distributions, loans or other payments to us. That indenture will also impose limits on our ability to transfer assets to unrestricted subsidiaries or acquire unrestricted subsidiaries. However, these limitations are subject to various qualifications. Subject to certain limitations, we and our subsidiaries may incur secured indebtedness. For additional details of these provisions and the applicable qualifications, see "Description of the Notes -- Subordination" and " -- Certain Covenants." WE ARE HIGHLY LEVERAGED Assuming we had issued the outstanding notes and applied the proceeds on September 30, 1998, our long-term debt (including the current portion) would have been $388,179,000 and shareholders' equity would have been $283,824,000. We believe that our cash flow from operations, together with funds available under our bank credit agreement after it is paid down with the net proceeds we receive from these notes, and other anticipated sources of liquidity, including additional debt and convertible preferred securities that we may offer in the future and proceeds from asset sales, will be adequate to meet our anticipated requirements for working capital, capital expenditures, interest payments and scheduled principal payments. However, our ability to meet our debt service obligations will be dependent upon our future performance. Our future performance, in turn, will be subject to general economic conditions and to financial, business and other factors affecting our operations, many of which are beyond our control. WE ARE SUBJECT TO VARIOUS COVENANT RESTRICTIONS We and our subsidiaries will be subject to significant operating and financial restrictions contained in the instruments governing the notes and our other indebtedness. Such restrictions will affect, and in many respects significantly limit or prohibit, among other things, our ability to: o incur additional indebtedness o make various investments o pay dividends on, redeem or repurchase our capital stock o issue and sell our restricted subsidiaries' capital stock o engage in transactions with affiliates o create certain liens o dispose of asset sales proceeds o guarantee indebtedness o incur senior subordinated indebtedness that does not rank equal to the notes o merge, consolidate and sell assets In addition, our bank credit agreement requires us to maintain various financial ratios. These restrictions could also limit our ability to obtain financing in the future, make needed capital expenditures, withstand a future downturn in our business or the economy in general or conduct necessary corporate activities. If we or our subsidiaries fail to comply with these restrictions, we may be in default under the terms of such indebtedness, even if we are otherwise able to meet our debt service obligations. In the event of a default, the holders of such indebtedness could elect to declare all such indebtedness, together with accrued interest, to be due and payable and a significant portion of our other indebtedness (including the notes) may become immediately due and payable. We cannot assure you that we 18 19 would be able to make such payments or borrow sufficient funds from alternative sources to make such payments. Even if we were to obtain additional financing, such financing may be on terms unfavorable to us. WE ARE SUBJECT TO VARIOUS GOVERNMENT REGULATIONS AND ENVIRONMENTAL RISKS We are subject to various legal limitations We and our subsidiaries are subject to various foreign and domestic laws and regulations on taxation, exploration and development, and environmental and safety matters in countries where we own or operate properties. Many laws and regulations require drilling permits and govern the spacing of wells, the prevention of waste, rates of production and other matters. These statutes and regulations, and any others that are passed by the jurisdictions where we have production could limit the total number of wells drilled or the total allowable production from successful wells, which could limit revenues. We are subject to various environmental liabilities We could incur liability to governments or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water, including responsibility for remedial costs. We could potentially discharge oil or natural gas into the environment in any of the following ways: o from a well or drilling equipment at a drill site o leakage from storage tanks, pipelines or other gathering and transportation facilities o damage to oil or natural gas wells resulting from accidents during normal operations o blowouts, cratering or explosions Environmental discharges may move through soil to water supplies or adjoining properties, giving rise to additional liabilities. Some laws and regulations could impose liability for failure to notify the proper authorities of a discharge and other failures to comply with those laws. Environmental laws may also affect the costs of our acquisitions of properties. We do not believe that its environmental risks are materially different from those of comparable companies in the oil and gas industry. However, we cannot assure that environmental laws will not, in the future, result in decreased production, substantially increased costs of operations or other adverse effects to our combined operations and financial condition. Pollution and similar environmental risks generally are not fully insurable. See "Business and Properties -- Government Regulations." OUR FOREIGN OPERATIONS SUBJECT US TO ADDITIONAL RISKS Our ownership and operations in Thailand, Canada, and any other foreign areas where we may choose to do business, are subject to the various risks inherent in foreign operations. These risks may include the following: o currency restrictions and exchange rate fluctuations o loss of revenue, property and equipment due to expropriation, nationalization, war, insurrection and other political risks o risks of increases in taxes and governmental royalties o renegotiation of contracts with governmental entities and quasi-governmental agencies o changes in laws and policies governing operations of foreign-based companies o other uncertainties arising out of foreign government sovereignty o inability to fund foreign operations from the United States United States laws and policies on foreign trade, taxation and investment may also adversely affect international operations. In addition, if a dispute arises from foreign operations, foreign courts may have exclusive jurisdiction over the dispute, or we may not be able to subject foreign persons to the jurisdiction of United States courts. We seek to manage these risks by concentrating our international operations in areas where we believe that the existing government is stable and favorably disposed towards United States oil and gas companies. 19 20 WE FACE ADDITIONAL RISKS RELATED TO OUR OPERATIONS IN THE KINGDOM OF THAILAND Additional risks and uncertainties affect the marketing and sales of hydrocarbons from our Block B8/32 Concession located in the Gulf of Thailand (the "Thailand Concession"). We expect that all the natural gas we produce from the Thailand Concession will be sold to The Petroleum Authority of Thailand ("PTT"), which maintains a monopoly over gas transmission and distribution in Thailand. Two major natural gas pipelines owned and operated by PTT cross the Thailand Concession. These pipelines may become full due to production from the Tantawan Field, the Benchamas Field and other fields in the Gulf of Thailand. We cannot assure, even if we are successful in exploration efforts, that we will be able to successfully and profitably transport, process, refine and market the oil and gas we produce. PTT has constructed a lateral pipeline from its main pipeline to the Tantawan production area and has agreed to take the gas produced from that area pursuant to a gas sales agreement (the "Gas Sales Agreement"). If the Company and our joint venture partners in the Tantawan Field fail to deliver the required reserves or production rates of natural gas at a specified quality level under the Gas Sales Agreement, we may be obligated to contribute to PTT's costs for the construction of the lateral pipeline. Also, if the Tantawan joint venturers fail to deliver the minimum daily rates under the Gas Sales Agreement, PTT has the right to take from subsequent deliveries an amount equal to the quantity of undelivered gas at 75% of the contract price. Commencing on October 1, 1998, we and our joint venture partners have been delivering less natural gas than is being nominated by PTT under the Gas Sales Agreement. We have not been able to meet our contractual minimum delivery obligations for a number of reasons, including declining production from existing wells, the need to shut-in existing wells while drilling or working over additional wells from the same platform and our decision to emphasize oil and condensate production from the Tantawan Field. We anticipate that we will suffer a penalty on a portion of our future production. Thai governmental royalties, other governmental charges and income taxes also affect our operations cash flow. We expect all gas sales to be carried out in Baht, the Thai currency. Fluctuations in the exchange rate between Baht and dollars could also adversely affect the anticipated profits of our operations in Thailand. SOUTHEAST ASIA ECONOMIC ISSUES AFFECT US We conduct a substantial portion of our oil and gas production and sales in Southeast Asia. In recent months, Southeast Asia in general, and the Kingdom of Thailand in particular, have experienced severe economic difficulties, including sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. The Thailand government and other governments in the region are currently acting to address these issues. However, the economic difficulties in Thailand and the volatility of the Thai Baht against the U.S. dollar will continue to have a material impact on our Thailand operations and the prices we receive for our oil and gas production there. In early July 1997, the government of the Kingdom of Thailand announced that the value of the Baht would be set against the dollar and other currencies under a "managed float" program arrangement. This led to a substantial decline in value of the Thai Baht compared to the U.S. dollar, resulting in our experiencing foreign currency transaction losses during 1997. During 1998, the value of the Thai Baht has generally strengthened against the U.S. dollar, resulting in our experiencing foreign currency transaction gains. However, we cannot predict what the Thai Baht to dollar exchange rate may be in the future. Moreover, we anticipate that this exchange rate will remain volatile. LIQUIDITY AND CASH FLOW PROBLEMS OF OUR PARTNERS MAY AFFECT US Due to the recent decline in oil and gas prices, many of our partners, particularly the smaller ones, are experiencing liquidity and cash flow problems. These problems may lead to their attempting to delay or slow down the pace of drilling or project development in order to conserve cash, to a point that we believe is detrimental to the project. In most cases, we have the ability to influence the pace of development through our joint operating agreements. Some partners may be unwilling or unable to pay their share of the costs of projects as they become due. At worst, a partner may declare bankruptcy and refuse or be unable to pay its share of the costs of a project. We would then be required to pay this partner's share of the project costs. In most instances, we believe that we are contractually protected from such an event through our ability to take over the non-paying partner's share of the 20 21 project and by applicable oil and gas lien laws and bankruptcy laws. We believe that we would ultimately recover any sums that we are owed by non-paying partners that do not meet their share of the costs of a project in a timely fashion. Rutherford-Moran Oil Corporation ("RMOC"), the parent company of Thai Romo Ltd., one of the partners in our Thailand Concession, has been actively seeking a sale or merger for some time. RMOC recently announced that it has agreed to be acquired by Chevron Corporation ("Chevron"). The acquisition is subject to conditions, several of which are outside of RMOC's control. One of these conditions is that Chevron reach agreement with us on a new joint operating agreement that would include the transfer of operatorship on the Thailand concession from our subsidiary Thaipo to a subsidiary of Chevron. Although we have held discussions with Chevron on this subject, we do not know whether we can reach a mutually satisfactory agreement with Chevron. RMOC has also stated that its financial resources will be exhausted in February 1999, and that its banks have currently refused to lend it any additional funds. Chevron has agreed to lend additional funds to RMOC if most of the conditions to the acquisition have been satisfied, including Chevron's reaching agreement with us on a new joint operating agreement. Thai Romo's failure to pay its share of the expenses of our projects in the Gulf of Thailand could have a material adverse effect on us, due to the increased capital requirements that funding Thai Romo's share of the project development costs could have on us. WE HAVE YEAR 2000 RISKS Many existing computer programs and components were designed and developed to use a two-digit field to indicate the year in an applicable date field, which could result from the improper processing of dates for years after 1999. This issue is commonly known as the "Year 2000 Issue." The Year 2000 Issue is a broad business issue, which could effect financial and business applications as well as automated systems and instrumentation of ours and third parties with whom we do business. There can be no guarantee that third parties of business importance to us will successfully reprogram or replace, and test, all of their own computer hardware, software and process control systems to ensure such systems are Year 2000 ready. Failure by us, third parties of business importance to us and/or other constituents such as governments to become Year 2000 ready on a timely basis could have a material adverse effect on our financial position and results of operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources; Other Matters; Year 2000 Readiness Disclosure." WE MAY NOT HAVE SUFFICIENT FUNDS TO REPURCHASE THE NOTES UPON A CHANGE OF CONTROL Should certain change of control events occur, each holder of the notes will have the right to require us, subject to certain conditions, to repurchase all or any part of that holder's notes at a price equal to 101% of the principal of those notes, plus accrued and unpaid interest, if any, to the date of repurchase. See "Description of the Notes -- Certain Covenants; Change of Control." Existing senior indebtedness under our bank credit agreement and certain other of our indebtedness include, and future indebtedness may include, change of control provisions. Under those provisions, should a specified change of control event occur, we would be required to repurchase, or the lender could demand the repayment of, that indebtedness. We would be required to make that repurchase or repayment of senior indebtedness before repurchasing the notes (or then outstanding indebtedness ranking equally with the notes that contains similar change of control provisions). The term "Change of Control" with respect to the notes is defined in the "Description of the Notes -- Certain Definitions" section of this prospectus. We cannot assure you that we will have sufficient funds available or could obtain the financing necessary to repurchase the notes and any other outstanding indebtedness that rank equally with or senior to the notes tendered by holders of those obligations following a change of control. If a change of control occurred and we did not have the funds or financing available to pay for the notes and any other indebtedness ranking equally with, or senior to, the notes that are tendered for repurchase, an event of default would be triggered under the indenture governing the notes and under such other outstanding indebtedness. Each of these defaults could have a material adverse consequence for us and the holders of the notes. 21 22 In addition, we have two other series of notes outstanding that contain change of control provisions that are similar to the change of control provisions contained in the notes. Consequently, an event triggering a change of control repurchase obligation under the notes may also trigger a change of control repurchase obligation under those other series of notes. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Also, the definition of change of control includes a phrase relating to the sale or other disposition of the our properties and assets "substantially as an entirety." Although there is a developing body of case law interpreting phrases such as "substantially as an entirety," there is no precise established definition of such phrases under applicable law. Accordingly, the ability of a holder of the notes to require us to repurchase its notes as a result of our sale or other disposition of less than all our properties and assets on a consolidated basis to another person or related group of persons may be uncertain. See "Description of the Notes -- Certain Covenants; Change of Control." FUTURE SUBSIDIARY GUARANTEES MAY BE AFFECTED BY FRAUDULENT CONVEYANCE LAWS None of our subsidiaries currently guarantee the notes. If our existing or future restricted subsidiaries guarantee any of our other indebtedness, they will be required by the terms of the indenture governing the notes to jointly and severally guarantee the notes on a senior subordinated basis. We do not intend to cause any of our subsidiaries to take any action that would require it to issue a guarantee of the notes. Various applicable fraudulent conveyance laws have been enacted for the protection of creditors. A court may use those laws to subordinate or avoid any guarantee of the notes issued by any of our subsidiaries. It is also possible that under certain circumstances a court could hold that the direct obligations of a subsidiary guaranteeing the notes could be superior to the obligations under that guarantee. A court could avoid or subordinate the guarantee of the notes by any of our subsidiaries in favor of that subsidiary's other debts or liabilities to the extent that the court determined either of the following were true at the time the subsidiary issued the guarantee: o that subsidiary incurred the guarantee with the intent to hinder, delay or defraud any of its present or future creditors or that such subsidiary contemplated insolvency with a design to favor one or more creditors to the total or partial exclusion of others; or o that subsidiary did not receive fair consideration or reasonably equivalent value for issuing the guarantee and, at the time it issued the guarantee, that subsidiary: -- was insolvent or rendered insolvent by reason of the issuance of the guarantee, -- was engaged or about to engage in a business or transaction for which the remaining assets of that subsidiary constituted unreasonably small capital, or -- intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they matured. Among other things, a legal challenge of a subsidiary's guarantee of the notes on fraudulent conveyance grounds may focus on the benefits, if any, realized by that subsidiary as a result of our issuance of the notes. To the extent a subsidiary's guarantee of the notes is avoided as a result of fraudulent conveyance or held unenforceable for any other reason, the note holders would cease to have any claim in respect of that guarantee and would be creditors solely of ours. THE ABSENCE OF A TRADING MARKET AND OTHER FACTORS MAY AFFECT THE LIQUIDITY OF THE NOTES The new notes will be new securities for which currently there is no trading market. We do not currently intend to apply for listing of the new notes on any securities exchange or stock market. Although the initial purchasers of the new notes have informed us that they currently intend to make a market in the new notes, they are not obligated to do so. Any such market making may be discontinued at any time without notice. The liquidity of any market for the new notes will depend on the number of holders of those notes, the interest of securities dealers in making a market in those securities and other factors. Accordingly, we cannot assure you as to the development or liquidity of 22 23 any market for the new notes. Historically, the market for noninvestment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the new notes. We cannot assure you that the market, if any, for the new notes will be free from similar disruptions. Any such disruptions may adversely effect the new note holders. 23 24 PRIVATE PLACEMENT On January 15, 1999, the Company issued $150,000,000 principal amount of the outstanding notes to the initial purchasers of those notes (the "Initial Purchasers") at a price of 95.95% of the principal amount of those notes in a private transaction not registered under the Securities Act of 1933, as amended (the "Securities Act"), in reliance upon Section 4(2) of the Securities Act. The Initial Purchasers then offered and resold the outstanding notes only to qualified institutional buyers at an initial price to such purchasers of 97.70% of the principal amount of those notes. We used the approximately $143,675,000 of proceeds (after deducting the Initial Purchasers' discounts and the expenses of that offering) to repay a portion of our outstanding Senior Indebtedness. USE OF PROCEEDS The Company will not receive any cash proceeds from the issuance of the new notes. In consideration for issuing the new notes, the Company will receive in exchange a like principal amount of outstanding notes. The outstanding notes surrendered in exchange for the new notes will be retired and canceled and cannot be reissued. Accordingly, issuance of the new notes will not result in any change in the Company's capitalization. CAPITALIZATION The following table sets forth the unaudited consolidated debt and capitalization of the Company and its subsidiaries at September 30, 1998. The table has also been adjusted to reflect the issuance of the outstanding notes and the application of the net proceeds therefrom as described under "Use of Proceeds" assuming the outstanding notes sale had occurred on September 30, 1998. This table should be read in conjunction with the consolidated financial statements and related notes thereto included in the Company's Reports and incorporated by reference in this prospectus. See "Incorporation of Certain Documents by Reference."
SEPTEMBER 30, 1998 ------------------------ ACTUAL AS ADJUSTED ------ ----------- (IN THOUSANDS) Long-term debt, including current portion: Credit Agreement indebtedness(a) $154,000 $ 10,325 Uncommitted credit line with bank 2,000 2,000 Banker's acceptance loans 10,854 10,854 10 3/8% Senior Subordinated Notes, due 2009 -- 150,000 8 3/4% Senior Subordinated Notes, due 2007 100,000 100,000 5 1/2% Convertible subordinated notes, due 2006 115,000 115,000 -------- -------- Total long-term debt 381,854 388,179 -------- -------- Shareholders' equity: Preferred stock, $1 par value; 2,000,000 shares authorized; no shares issued and outstanding -- -- Common Stock, $1 par value; 100,000,000 shares authorized; 40,119,250 shares issued 40,119 40,119 Additional capital 290,133 290,133 Retained earnings (deficit) (46,104) (46,104) Treasury stock, at cost; 15,575 shares; and other (324) (324) -------- -------- Total shareholders' equity 283,824 283,824 -------- -------- Total capitalization $665,678 $672,003 ======== ========
- ---------------- (a) As of December 31, 1998, the outstanding indebtedness under the Credit Agreement was $205,000,000. 24 25 SELECTED FINANCIAL DATA The selected financial data presented below as of, and for each of the years in the five-year period ended December 31, 1997, are derived from the consolidated financial statements of the Company and its subsidiaries, which have been audited by independent public accountants. The financial data as of, and for the nine month periods ended September 30, 1997 and 1998, are derived from the Company's unaudited financial statements which, in the opinion of management, include all adjustments (which consist only of normal recurring adjustments) necessary for a fair presentation of the financial position and results of operations of the Company for each such interim period. This data should be read in conjunction with the consolidated financial statements and related notes thereto and "Management's Discussion and Analysis of Financial Condition and Results of Operations" included elsewhere herein.
NINE MONTHS ENDED Year Ended December 31, SEPTEMBER 30, ----------------------------------------------------- ------------------ 1993 1994 1995 1996 1997 1997 1998(e) ---- ---- ---- ---- ---- ---- ------- (IN THOUSANDS, EXCEPT RATIOS AND UNIT AMOUNTS) (Unaudited) INCOME STATEMENT DATA: Revenue: Crude oil and condensate $ 64,042 $ 65,141 $ 76,557 $ 96,908 $ 112,603 $ 84,776 $ 59,276 Natural gas 66,173 99,093 72,032 94,589 158,500 116,117 91,411 Natural gas liquids 7,288 9,189 8,097 11,867 13,748 11,746 8,149 --------- --------- --------- --------- --------- --------- --------- Oil and gas revenues 137,503 173,423 156,686 203,364 284,851 212,639 158,836 Pipeline and other, net (950) 133 773 778 349 1,274 842 Interest on tax refund 2,322 -- -- -- -- -- -- Gains (losses) on sales 679 52 100 (165) 1,100 1,318 (106) --------- --------- --------- --------- --------- --------- --------- Total 139,554 173,608 157,559 203,977 286,300 215,231 159,572 --------- --------- --------- --------- --------- --------- --------- Operating costs and expenses: Lease operating 26,633 29,768 35,071 37,628 63,501 45,116 51,196 General and administrative 14,550 15,984 16,400 18,028 21,412 15,746 19,843 Exploration 2,455 5,257 7,468 16,777 10,530 7,823 7,260 Dry hole and impairment 4,690 7,088 6,703 8,579 9,631 6,926 7,906 Depreciation, depletion and amortization 40,693 63,308 68,489 61,857 103,157 75,989 83,739 --------- --------- --------- --------- --------- --------- --------- Total 89,021 121,405 134,131 142,869 208,231 151,600 169,944 --------- --------- --------- --------- --------- --------- --------- Operating income (loss) 50,533 52,203 23,428 61,108 78,069 63,631 (10,372) Interest charges (10,956) (10,104) (11,167) (13,203) (21,886) (15,771) (17,513) Interest income 14 53 26 232 453 271 534 Interest capitalized 451 739 1,834 4,244 6,175 3,463 6,540 Foreign currency translation gain (loss) -- -- -- -- (7,604) (6,522) 953 --------- --------- --------- --------- --------- --------- --------- Income (loss) before taxes and extraordinary items 40,042 42,891 14,121 52,381 55,207 45,072 (19,858) Income tax (expense) benefit (14,981) (15,517) (4,891) (18,800) (18,091) (15,694) 9,052 --------- --------- --------- --------- --------- --------- --------- Income (loss) before extraordinary items 25,061 27,374 9,230 33,581 37,116 29,378 (10,806) Extraordinary loss -- (307) -- (821) -- -- -- --------- --------- --------- --------- --------- --------- --------- Net income (loss) $ 25,061 $ 27,067 $ 9,230 $ 32,760 $ 37,116 $ 29,378 $ (10,806) ========= ========= ========= ========= ========= ========= =========
25 26
OTHER FINANCIAL DATA: EBITDA(a) $95,930 $122,652 $98,646 $131,776 $183,706 $140,295 $82,760 Capital and exploration expenditures (excluding interest capitalized 74,600 120,800 110,400 206,200 259,500 165,000 121,800 SELECTED RATIOS: EBITDA/Net interest expense 9.1x 13.1x 10.6x 14.7x 11.7x 11.4x 7.5x Ratio of earnings to fixed charges(b) 4.5x 5.1x 2.1x 4.6x 3.2x 3.6x (c) Long-term obligations/EBITDA(d) 1.4x 1.2x 1.7x 1.9x 1.9x 2.4x 4.6x Long-term obligations/Total proved reserves (BOE) $ 1.95 $ 2.01 $ 1.63 $ 2.24 $ 2.78 n/a n/a
September 30, 1998(e) ----------------------------- Actual As Adjusted(f) ------ -------------- BALANCE SHEET DATA: Total assets $823,350 $829,675 Long-term obligations, including current portion 381,854 388,179 Total shareholders' equity 283,824 283,824
- --------------------- (a) EBITDA represents income from continuing operations before income taxes, interest expense, depreciation, depletion and amortization, and dry hole and impairment costs. EBITDA is presented as a measure of the Company's debt service ability, and not as an alternative to (i) operating income (as determined in accordance with generally accepted accounting principals) as an indicator of the Company's operating performance, or (ii) cash flows from operating activities (as determined in accordance with generally accepted accounting principals) as a measure of liquidity. (b) Pre-tax earnings plus total interest charges, including amortization of debt issue expenses, divided by total interest charges, including amortization of debt issue expenses. (c) For the nine-month period ended September 30, 1998, earnings were insufficient to cover fixed charges by $26.5 million. (d) Long-term obligations includes the current portion of long-term debt. (e) Includes the results of Arch from August 17, 1998, the effective date of its acquisition by the Company. The acquisition was accounted for using the purchase method. (f) Adjusted to give effect to the sale of the outstanding notes and the application of the net proceeds from that sale as if it had occurred on September 30, 1998. 26 27 SELECTED RESERVE AND OPERATING DATA The selected reserve and operating data presented below under the captions "Production (Sales) Data" as of, and for each of the years in the five-year period ended, December 31, 1997, and for the nine month periods ended September 30, 1997, and 1998, is unaudited and should be read in conjunction with the consolidated financial statements and related notes thereto and "Business and Properties -- Exploration and Production Data; Production and Sales" and "Management's Discussion and Analysis of Financial Condition and Results of Operations." The reserve information presented under the caption "Reserve Data" as of, and for each of the years in the five-year period ended, December 31, 1997 has been derived from the summary reserve report prepared by Ryder Scott and should be read in conjunction with the notes to the Company's consolidated financial statements and "Business and Properties -- Exploration and Production Data; Reserves." The data included in the Reports is incorporated in this prospectus by reference. See "Incorporation of Certain Documents by Reference."
NINE MONTHS ENDED Year Ended December 31, SEPTEMBER 30, -------------------------------------------------------- ----------------- 1993 1994 1995 1996 1997 1997 1998 ---- ---- ---- ---- ---- ---- ---- (IN THOUSANDS, EXCEPT UNIT AMOUNTS) PRODUCTION (SALES) DATA: Net daily average and weighted average price: Natural gas: Mcf per day 91,700 144,800 121,000 107,700 181,700 184,500 164,400 Price per Mcf $ 1.98 $ 1.88 $ 1.63 $ 2.40 $ 2.39 $ 2.31 $ 2.04 Crude oil and condensate: Bbls per day 9,851 11,100 11,786 11,968 15,927 15,856 16,090 Price per Bbl $ 17.81 $ 16.08 $ 17.80 $ 22.12 $ 19.37 $ 19.52 $ 13.49 Natural gas liquids: Bbls per day 1,678 2,222 1,998 2,173 2,923 3,424 2,768 Price per Bbl $ 11.90 $ 11.33 $ 11.10 $ 14.92 $ 12.89 $ 12.57 $ 10.78 RESERVE DATA(A)(D): Estimated proved reserves: Crude oil, condensate and natural gas liquids (MBbls) 28,268 33,862 45,182 49,602 58,164 -- -- Natural gas (MMcf) 232,866 242,890 328,061 360,944 401,488 -- -- Natural gas equivalents (MMcfe) 402,474 446,062 599,153 658,556 750,472 -- -- Estimated future net revenues before income taxes, discounted at 10%(b)(c) $403,840 $382,980 $532,475 $954,545 $462,781 -- -- Estimated future net revenues after income taxes, discounted at 10%(b) $300,260 $290,069 $377,145 $686,040 $349,465 -- --
(a) Proved reserves were estimated in accordance with SEC guidelines using oil and gas prices and production and development costs as of December 31 of each such year. These amounts exclude Arch's proved reserves. See "Business and Properties -- Arch and its Subsidiaries; Oil and Gas Reserves." (b) These values were estimated in accordance with SEC guidelines. See "Business and Properties -- Exploration and Production Data; Reserves." 27 28 (c) Based on assumed Company-wide flat prices of $12.00 per Bbl for oil and condensate and $2.00 per Mcf for gas, the Company's reservoir engineers estimate that the present value of future net revenues before income taxes, discounted at 10%, of the Company's proved reserves would have been approximately $254,599,000 at December 31, 1997. This calculation represents an internal Company estimate, is presented for information purposes and has not been calculated entirely in accordance with SEC guidelines. (d) On a pro forma basis, giving effect to the Company's merger with Arch as if it had occurred on December 31, 1997, and using SEC pricing in effect on that date, the Company's estimated proved reserves of: (i) crude oil, condensate and natural gas liquids would have been 64,045 MBbls; (ii) natural gas would have been 478,373 MMcf; (iii) natural gas equivalents would have been 862,643 MMcfe; and estimated future net revenues before income taxes discounted at 10% would have been $528,745,000. Based on assumed Company-wide flat prices of $12.00 per Bbl for oil and condensate and $2.00 per Mcf for gas, the Company's reservoir engineers estimate that the present value of future net revenues before income taxes, discounted at 10%, of our proved reserves would have been approximately $305,806,000 at December 31, 1997 if Arch's reserves were included as of that date. 28 29 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The Company's acquisition of Arch was initially accounted for as a pooling of interests which requires the financial results for all periods prior to the acquisition to be combined and restated as if the Company and Arch had always been combined. The Company then restated its consolidated financial statements for periods prior to the merger, including the first nine months of 1997 and the first nine months of 1998, to reflect the combined results of both the Company and Arch. A report on Form 10-Q for the quarter ended September 30, 1998 was filed on that basis. The Company recently concluded that, as a result of the current environment of low crude oil and natural gas prices, the Company must maintain maximum flexibility to address its cash flow needs, including the option of selling certain of the Company's assets. Under the current application of accounting principles, such transactions would preclude the pooling of interests method of accounting and require that the Company account for the acquisition using the purchase method of accounting. Consequently, on December 24, 1998, the Company filed an amended report on Form 10-Q for the quarter ended September 30, 1998, primarily for the purpose of restating the financial statements contained in such report and to make conforming changes to "Management's Discussion and Analysis of Financial Condition and Results of Operations" to reflect the change from the pooling method of accounting to the purchase method of accounting for the Arch acquisition. See "Incorporation of Certain Documents by Reference." NINE MONTHS ENDED SEPTEMBER 30, 1998, COMPARED WITH THE NINE MONTHS ENDED SEPTEMBER 30, 1997 RESULTS OF OPERATIONS Net Income (Loss) For the first nine months of 1998, the Company reported a net loss of $10,806,000 or $0.29 per share (on both a basic and a diluted basis) compared to net income for the first nine months of 1997 of $29,378,000 or $0.88 per share ($31,689,000 or $0.83 on a diluted basis). Among other items affecting net income for the first nine months of 1998, were non-recurring expenses totaling approximately $2,285,000 ($1,485,000 or $0.04 per share on an after-tax basis), related to the Company's acquisition of Arch. Earnings per share are based on the weighted average number of common shares outstanding for the first nine months of 1998 of 37,171,000, compared to 33,374,000 for the first nine months of 1997. The increase in the weighted average number of common shares outstanding for the 1998 period, compared to the 1997 period, resulted primarily from the issuance of 3,882,023 shares of its common stock upon the conversion of the Company's 5 1/2% Convertible Subordinated Notes due 2004 (the "2004 Notes") prior to their being redeemed on March 16, 1998, the issuance as of August 17, 1998, of approximately 2,540,000 shares of common stock to former holders of Arch capital stock and convertible debt securities in connection with the Company's acquisition of Arch and, to a lesser extent, the issuance of common stock upon the exercise of stock options pursuant to the Company's stock option plans. The earnings per share computation on a diluted basis in the 1998 period is identical to the basic earnings per share computation because there were no securities of the Company that were dilutive during the period. The earnings per share computation on a diluted basis in the 1997 period primarily reflects additional shares of common stock issuable upon the assumed conversion of the 2004 Notes and the elimination of related interest requirements, as adjusted for applicable federal income taxes and, to a lesser extent, the assumed exercise of options to purchase common shares. The weighted average number of common shares outstanding on a diluted basis for the first nine months of 1997 were 38,064,000. Total Revenues The Company's total revenues for the first nine months of 1998 were $159,572,000, a decrease of approximately 26% compared to total revenues of $215,231,000 for the first nine months of 1997. The decrease in the Company's total revenues for the first nine months of 1998, compared to the first nine months of 1997, resulted primarily from decreases in revenue from the Company's oil and gas operations and, to a lesser extent, a decline in revenue from the 29 30 sale of non-strategic properties, pipeline sales revenues and other miscellaneous items. Total revenues for the first nine months of 1998 reflect the inclusion of pipeline revenues from Saginaw Pipeline, L.C. and its marketing subsidiary, Industrial Natural Gas, L.C., which the Company acquired through its acquisition of Arch on August 17, 1998. Total revenues for the first nine months of 1997 include a net gain of $1,459,000 on the sale of a compressor by the Company during the first half of 1997. Oil And Gas Revenues The following table reflects an analysis of differences in the Company's oil and gas revenues (expressed in thousands of dollars) between the first nine months of 1998 and the same period in the preceding year.
9 MONTHS 1998 COMPARED TO 9 MONTHS 1997 ------------- Increase (decrease) in oil and gas revenues resulting from differences in: NATURAL GAS -- Price...................................................................... $(13,598) Production................................................................. (11,108) -------- (24,706) CRUDE OIL AND CONDENSATE -- Price...................................................................... (26,366) Production................................................................. 866 -------- (25,500) NGL--......................................................................... (3,597) -------- Increase (decrease) in oil and gas revenues................................ $(53,803) ========
Prices and production volumes attributable to the Company's operations in Canada are included in the Company's domestic oil and gas prices and production volumes. This information is not presented separately because the Company does not believe that such information is material to an understanding of the Company's results of operations for the period presented due to the relatively small portion of the Company's oil and gas revenues which were attributable to such operations during the applicable periods. NATURAL GAS PRICES. Prices that the Company received for its natural gas production during the first nine months of 1998 averaged $2.04 per Mcf, a decrease of approximately 12% from an average price of $2.31 per Mcf that the Company received for its natural gas production during the first nine months of 1997. Domestic Prices. Prices that the Company received for its domestic natural gas production during the first nine months of 1998 averaged $2.13 per Mcf, a decrease of approximately 10% from an average price of $2.37 per Mcf that the Company received for its domestic natural gas production during the first nine months of 1997. Thailand Prices. The Company's Tantawan Field located in the Kingdom of Thailand commenced production of natural gas and liquid hydrocarbons in February 1997. During the first nine months of 1998, the prices that the Company received under its long term gas sales contract for natural gas production from the Tantawan Field averaged approximately 74 Thai Baht per Mcf. Based on the Thai Baht to U.S. dollar exchange rates in effect at the time that such production was recorded on the Company's financial statements, the average price in U.S. dollars that the Company recorded during the first nine months of 1998 for such production was approximately $1.73 per Mcf, a decrease of approximately 14% from an average price of $2.00 per Mcf that the Company recorded in the first nine months of 1997. The price that the Company receives under its Gas Sales Agreement normally adjusts on a semi-annual basis. However, the Gas Sales Agreement provides for adjustment on a more frequent basis in the event that certain indices and factors on which the price is based fluctuate outside a given range. Due to the volatility of the Thai Baht and the current economic difficulties in the Kingdom of Thailand and throughout Southeast Asia, the price that the Company received under the Gas Sales Agreement was adjusted several times during the first nine months of 1998. See "Business and Properties -- International Operations; Contractual Terms Governing the Thailand Concession and Related Production." The Company cannot predict what the Baht to dollar exchange rate may be in the future. Moreover, it is anticipated that this exchange rate will remain volatile. See "; Foreign Currency 30 31 Transaction Gain (Loss)", "-- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues" and "Business and Properties -- International Operations; Contractual Terms Governing the Thailand Concession and Related Production." NATURAL GAS PRODUCTION. The Company's total natural gas production during the first nine months of 1998 averaged 164.4 MMcf per day, a decrease of approximately 11% from an average of 184.5 MMcf per day that the Company produced during the first nine months of 1997. Domestic Production. The decrease in the Company's natural gas production during the first nine months of 1998, compared to the first nine months of 1997, was related in large measure to decreased production from the Company's East Cameron Block 334 "E" platform, and to a lesser extent, three periods in the third quarter of 1998 during which most of the Company's offshore production was shut-in as a precautionary measure due to hurricanes in the Gulf of Mexico and natural production declines, that was partially offset by increased production from the Company's onshore properties located in South Texas and South Louisiana. As of December 31, 1998, the Company was not a party to any future natural gas sales contracts. Thailand Production. The Company's share of natural gas production from the Tantawan Field during the first nine months of 1998 averaged 38.9 MMcf per day, an increase of approximately 21% from an average of 32.1 MMcf per day that the Company produced during the first nine months of 1997. The increase in the Company's average daily natural gas production from the Tantawan Field during the first nine months of 1998, compared to the first nine months of 1997, reflects the fact that production from the Tantawan Field did not commence until early in February 1997 and did not achieve sustained commercial production rates until March 15, 1997. Commencing on October 1, 1998, the Company and its joint venture partners have been delivering less natural gas than is being nominated by PTT under the Gas Sales Agreement. This could result in the Company receiving only 75% of the current contract price on a portion of its future natural gas sales to PTT. The Company is taking actions that it currently believes will minimize the penalty that it will incur on future gas sales to PTT by, among other things, increasing production from the Tantawan Field. CRUDE OIL AND CONDENSATE PRICES. Prices that the Company received for its crude oil and condensate production during the first nine months of 1998 averaged $13.49 per Bbl, a decrease of approximately 31% from an average price of $19.58 per Bbl that the Company received during the first nine months of 1997. Domestic Prices. Prices that the Company received for its domestic crude oil and condensate production during the first nine months of 1998 averaged $13.44 per Bbl, a decrease of approximately 32% from an average price of $19.69 per Bbl that the Company received during the first nine months of 1997. Thailand Prices. Since the inception of production from the Tantawan Field, crude oil and condensate have been stored in a Floating Production, Storage and Offloading System (the "FPSO") until an economic quantity is accumulated for offloading and sale. The first such sale of crude oil and condensate from the Tantawan Field occurred in July 1997. The price that the Company recorded for its crude oil and condensate production stored on the FPSO for the first nine months of 1998 was $13.72 per Bbl, a decrease of approximately 27% from the price of $18.84 per Bbl that was recorded for the first nine months of 1997. Prices that the Company receives for its crude oil and condensate production from Thailand are based on world benchmark prices, which are denominated in dollars. In addition, the Company is generally paid for its crude oil and condensate production from Thailand in U.S. dollars. CRUDE OIL AND CONDENSATE PRODUCTION. The Company's total crude oil and condensate production during the first nine months of 1998 averaged 16,090 Bbls per day, an increase of approximately 1% from an average of 15,856 Bbls per day during the first nine months of 1997. Domestic Production. The Company's domestic crude oil and condensate production during the first nine months of 1998 averaged 13,317 Bbls per day, a decrease of approximately 4% from an average of 13,927 Bbls per day during the first nine months of 1997. The decrease in the Company's domestic crude oil and condensate production during the first nine months of 1998, compared to the first nine months of 1997, resulted primarily from a decrease 31 32 in condensate production from the Company's East Cameron Block 334 "E" platform, which was in part due to damage sustained in a marine accident at the crude oil and condensate pipeline from the platform, that was only partially offset by increased production from the Company's ongoing development drilling and workover programs in the offshore and onshore Gulf of Mexico regions. As of December 31, 1998, the Company was not a party to any crude oil swaps or futures contracts. Thailand Production. The Company's share of crude oil and condensate production from the Tantawan Field during the first nine months of 1998 averaged 2,773 Bbls per day, an increase of approximately 44% from an average of 1,930 Bbls per day during the first nine months of 1997. The increase in the Company's average daily crude oil and condensate production from the Tantawan Field during the first nine months of 1998, compared to the first nine months of 1997, primarily reflects the fact that production from the Tantawan Field did not commence until early in February 1997 and did not achieve sustained commercial production rates until March 15, 1997. NGL PRODUCTION. The Company's oil and gas revenues, and its total liquid hydrocarbon production volumes, reflect the production and sale by the Company. The Company's NGL revenues for the first nine months of 1998 decreased $3,597,000, from the first nine months of 1997. The decrease in the Company's NGL for the first nine months of 1998, compared to the first nine months of 1997, was related to both a decrease in NGL production volumes from the Company's domestic offshore properties and a decrease in the price that the Company received for its NGL production volumes. TOTAL LIQUID HYDROCARBON PRODUCTION. The Company's average liquid hydrocarbon production during the first nine months of 1998 was 18,858 Bbls per day, a decrease of approximately 2% from an average liquid hydrocarbon production of 19,280 Bbls per day during the first nine months of 1997. Lease Operating Expenses Company-wide lease operating expenses for the first nine months of 1998 were $51,196,000, an increase of approximately 13% from lease operating expenses of $45,116,000 for the first nine months of 1997. A discussion of lease operating expenses attributable to the Company's operations in Canada is included in the Company's domestic lease operating expenses. The information is not presented separately because the Company does not believe that such information is material to an understanding of the Company's results of operations for the periods presented due to the relatively small portion of the Company's lease operating expenses which were attributable to such operations during the applicable periods. DOMESTIC LEASE OPERATING EXPENSES. The Company's domestic lease operating expenses for the first nine months of 1998 were $35,249,000, an increase of approximately 11% from domestic lease operating expenses of $31,802,000 for the first nine months of 1997. The increase in domestic lease operating expenses for the first nine months of 1998, compared to the first nine months of 1997, were affected by a non-recurring maintenance project on the Company's East Cameron 334 "E" platform during the first quarter of 1998 and by expenses related to purchasing natural gas for transportation and subsequent resale on the pipeline system acquired in the merger with Arch, operating expenses related to the pipeline system for which no corresponding expenses were recorded during the first nine months of 1997. In addition, lease operating expenses for the first nine months of 1997 were reduced by a $954,000 refund in connection with the Company's audit of a joint venture partner, for which no corresponding refund of a similar magnitude was obtained in the first nine months of 1998. THAILAND LEASE OPERATING EXPENSES. The Company's lease operating expenses in the Kingdom of Thailand for the first nine months of 1998 were $15,947,000, an increase of approximately 20% from lease operating expenses of $13,314,000 for the first nine months of 1997. The increase in lease operating expenses in the Kingdom of Thailand for the first nine months of 1998, compared to the first nine months of 1997, was primarily related to the fact that prior to the commencement of production in the Tantawan Field on February 1, 1997, no lease operating expenses were incurred by the Company in Thailand. Consequently, the Company does not believe that a comparison of lease operating expenses in the Kingdom of Thailand between the first nine months of 1998 and the first nine months of 1997 is meaningful. A substantial portion of the Company's lease operating expenses in the Kingdom of Thailand 32 33 relate to lease payments made by Tantawan Services, L.C., in connection with its bareboat charter of the FPSO, which amounted to $8,318,000 and $7,404,000 (net to the Company's interest) for the first nine months of 1998 and 1997, respectively. See "-- Liquidity and Capital Resources; Capital Requirements; Other Material Long-Term Commitments." General and Administrative Expenses General and administrative expenses for the first nine months of 1998 were $19,843,000, an increase of approximately 26% from general and administrative expenses of $15,746,000 for the first nine months of 1997. The increase in general and administrative expenses for the first nine months of 1998, compared with the first nine months of 1997, was primarily related to a number of non-recurring expenses arising in connection with the Company's acquisition of Arch totaling approximately $2,285,000, that included severance payments to former officers and employees of Arch. In addition, the increase in general and administrative expense was attributable, in part, to an increase in the size of the Company's work force and normal salary and concomitant benefit expense adjustments. Exploration Expenses Exploration expenses consist primarily of rental payments required under oil and gas leases to hold non-producing properties ("delay rentals") and geological and geophysical costs which are expensed as incurred. Exploration expenses for the first nine months of 1998 were $7,260,000, a decrease of approximately 7% from exploration expenses of $7,823,000 for the first nine months of 1997. The decreases in exploration expenses for the first nine months of 1998, compared to the first nine months of 1997, resulted primarily from decreased geophysical activity in the Gulf of Mexico and West Texas, and a decrease in delay rental payments, that were partially offset, during the comparable nine month periods, by increased geophysical activity by the Company in East Texas, South Louisiana and in the Gulf of Thailand. Dry Hole and Impairment Expenses Dry hole and impairment expenses relate to costs of unsuccessful wells drilled, along with impairments due to decreases in expected reserves from producing wells. The Company's dry hole and impairment expenses for the first nine months of 1998 were $7,906,000, an increase of approximately 14% from dry hole and impairment expenses of $6,926,000 for the first nine months of 1997. Depreciation, Depletion and Amortization Expenses The Company accounts for its oil and gas activities using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Proved properties are reviewed whenever events or changes in circumstances indicate that the value of such property on the Company's books may not be recoverable. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. The provision for depreciation, depletion and amortization ("DD&A") is based on the capitalized costs, as determined in the preceding paragraph, plus future costs to abandon offshore wells and platforms, and is determined on a cost center by cost center basis using the units of production method. The Company generally creates cost centers on a field by field basis for oil and gas activities in the Gulf of Mexico and Gulf of Thailand. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its oil and gas activities onshore in the United States. The Company's DD&A expense for the first nine months of 1998 was $83,739,000, an increase of approximately 10% from DD&A expense of $75,989,000 for the first nine months of 1997. The increases in DD&A expense for the first nine months of 1998, compared to the first nine months of 1997, resulted primarily from an 33 34 increase in the Company's composite DD&A rate that was only partially offset by a decrease in production of oil and natural gas. The composite DD&A rate for all of the Company's producing fields for the first nine months of 1998 was $1.09 per equivalent Mcf ($6.54 per equivalent Bbl), an increase of approximately 20% from a composite DD&A rate of $0.91 per equivalent Mcf ($5.46 per equivalent Bbl) for the first nine months of 1997. The increase in the composite DD&A rate for all of the Company's producing fields for the first nine months of 1998, compared to the first nine months of 1997, resulted primarily from an increased percentage of the Company's production coming from certain of the Company's fields that have DD&A rates that are higher than the Company's recent historical composite rate and a corresponding decrease in the percentage of the Company's production coming from fields that have DD&A rates that are lower than the Company's recent historical composite DD&A rate. The Company produced 75,781,000 equivalent Mcf (12,630,000 equivalent Bbls) during the first nine months of 1998, a decrease of approximately 8% from the 82,036,000 equivalent Mcf (13,673,000 equivalent Bbls) produced by the Company during the first nine months of 1997. Interest INTEREST CHARGES. Interest charges incurred by the Company for the first nine months of 1998 were $17,513,000, an increase of approximately 11% from interest charges of $15,771,000 for the first nine months of 1997. The increase in interest charges for the first nine months of 1998, compared to the first nine months of 1997, resulted primarily from an increase in the average amount of debt outstanding and, to a lesser extent, the average interest rate charged on the Company's outstanding debt. As of December 31, 1998, the Company was not a party to any interest rate swap agreements. CAPITALIZED INTEREST. Capitalized interest expense for the first nine months of 1998 was $6,540,000, an increase of approximately 89% from capitalized interest expense of $3,463,000 for the first nine months of 1997. The increase in capitalized interest for the first nine months of 1998, compared to the first nine months of 1997, resulted primarily from an increase in the amount of capital expenditures subject to interest capitalization during the first nine months of 1998 ($122,414,000), compared to the first nine months of 1997 ($73,086,000), and from an increase in the computed rate that the Company uses to apply on such capital expenditures to arrive at the total amount of capitalized interest. A substantial percentage of the Company's capitalized interest expense during the latter half of 1997 and the first nine months of 1998 resulted from capitalization of interest related to such capital expenditures for the development of the Benchamas Field in the Gulf of Thailand and, to a lesser extent, several development projects in the Gulf of Mexico. Foreign Currency Transaction Gain (Loss) The Company experienced a foreign currency transaction gain of $953,000 during the first nine months of 1998, compared to a foreign currency transaction loss of $6,522,000 during the first nine months of 1997. The foreign currency transaction gain and loss each resulted primarily from the fluctuation against the U.S. dollar of cash and other monetary assets and liabilities denominated in Thai Baht that were on the Company's subsidiary's financial statements during the respective periods and, to a much lesser extent, the fluctuation of the Canadian dollar against the U.S. dollar. In early July 1997, the government of the Kingdom of Thailand announced that the value of the Baht would be set against the dollar and other currencies under a "managed float" program arrangement. This led to a substantial decline in value of the Thai Baht compared to the U.S. dollar, resulting in the foreign currency transaction losses during the 1997 periods presented. During the 1998 periods presented, the value of the Thai Baht has generally strengthened against the U.S. dollar, resulting in corresponding foreign currency transaction gains. However, the Company cannot predict what the Thai Baht to dollar exchange rate may be in the future. Moreover, it is anticipated that this exchange rate will remain volatile. As of December 31, 1998, the Company was not a party to any financial instrument that was intended to constitute a foreign currency hedging arrangement. 34 35 Income Tax Benefit (Expense) The Company experienced an income tax benefit for the first nine months of 1998 of $9,052,000, compared to income tax expense of $15,694,000 for the first nine months of 1997. The income tax benefit for the first nine months of 1998, compared to the income tax expense for the first nine months of 1997, resulted primarily from a pre-tax loss resulting from substantially lower revenues in the United States and the tax benefit of accrued foreign losses from the Company's operations in the Kingdom of Thailand. YEAR ENDED DECEMBER 31, 1997, COMPARED WITH YEARS ENDED DECEMBER 31, 1996 AND 1995, RESPECTIVELY RESULTS OF OPERATIONS Net income The Company reported net income for 1997 of $37,116,000 or $1.11 per share ($40,198,000 or $1.06 per share on a diluted basis) compared to net income for 1996 of $32,760,000 or $0.99 per share ($35,843,000 or $0.95 per share on a diluted basis)and net income for 1995 of $9,230,000 or $0.28 per share (on both a basic and a diluted basis). The Company recorded an extraordinary loss of $821,000 during the second quarter of 1996 related to the early retirement of the Company's 8% Convertible Subordinated Debentures, due 2005 with the proceeds from the Company's issuance on June 18, 1996, of its 5 1/2% Convertible Subordinated Notes, due 2006 (the "2006 Notes"). Earnings per common share are based on the weighted average number of common and common equivalent shares outstanding for 1997 of 33,421,000 (38,064,000 on a diluted basis), compared to 33,203,000 (37,920,000 on a diluted basis) for 1996 and 32,893,000 (33,490,000 on a diluted basis) for 1995. The yearly increases in the weighted average number of common shares outstanding resulted primarily from the issuance of shares of Common Stock upon the exercise of stock options pursuant to the Company's stock option plans. Earnings per common share computations on a diluted basis primarily reflect additional common shares issuable upon the assumed conversion of the 2004 Notes in 1996 and 1997 (the only convertible securities of the Company that were dilutive during the applicable periods) and the elimination of related interest requirements, as adjusted for applicable federal income taxes. In addition, the number of common shares outstanding in the diluted computation is adjusted, in accordance with the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 128 ("SFAS 128"), to include dilutive shares that are assumed to have been issued by the Company in connection with options exercised during the year, less treasury shares that are assumed to have been purchased by the Company from the option proceeds. SFAS 128 was adopted by the Company in 1997, resulting in a restatement of the earnings per share calculations for 1996 and 1995, and all preceding years. Total Revenues The Company's total revenues for 1997 were $286,300,000, an increase of approximately 40% from total revenues of $203,977,000 for 1996, and an increase of approximately 82% from total revenues of $157,559,000 for 1995. The increase in the Company's total revenues for 1997, compared to 1996, resulted primarily from the substantial increase in the Company's natural gas and liquid hydrocarbon (including crude oil, condensate and NGL) production, which was only partially offset by a decline in the average price that the Company received for its liquid hydrocarbon production and, to a much lesser extent, the average price that the Company received for its natural gas production. The increase in the Company's total revenues for 1997, compared to 1995, resulted primarily from the substantial increases in the Company's natural gas production, the average price that the Company received for its natural gas production, the Company's liquid hydrocarbon production and, to a lesser extent, the average price that the Company received for its liquid hydrocarbon production. Oil and Gas Revenues The Company's oil and gas revenues for 1997 were $285,200,000, an increase of approximately 40% from oil and gas revenues of $204,142,000 for 1996, and an increase of approximately 81% from oil and gas revenues of 35 36 $157,459,000 for 1995. The following table reflects an analysis of variances in the Company's oil and gas revenues (expressed in thousands) between 1997 and the previous two years:
1997 COMPARED TO ---------------------- 1996 1995 -------- -------- Increase (decrease) in oil and gas revenues resulting from variances in: NATURAL GAS -- Price................................................ $ (394) $ 33,466 Production........................................... 64,305 53,002 -------- -------- 63,911 86,468 CRUDE OIL AND CONDENSATE -- Price................................................ (12,064) 6,767 Production........................................... 27,759 29,279 -------- -------- 15,695 36,046 NGL AND OTHER, NET --................................... 1,452 5,227 -------- -------- Increase in oil and gas revenues..................... $ 81,058 $127,741 ======== ========
NATURAL GAS PRICES. Prices per Mcf that the Company received for its natural gas production during 1997 averaged $2.39 per Mcf. The average price that the Company received for its natural gas production in 1997 was approximately equal to the average price that the Company had received during 1996 of $2.40 per Mcf, but was a substantial increase (of approximately 47%) from the average price of $1.63 that it received during 1995. Domestic Prices. Prices that the Company received for its domestic natural gas production during 1997 averaged $2.50 per Mcf, an increase of approximately 4% from an average price of $2.40 per Mcf that the Company received for its domestic natural gas production during 1996, and an increase of approximately 53% from an average price of $1.63 that the Company received for its natural gas production during 1995. Thailand Prices. The Company's Tantawan Field located in the Kingdom of Thailand commenced production of natural gas and liquid hydrocarbons in February 1997. During 1997, the price that the Company received under the Gas Sales Agreement averaged approximately 60 Thai Baht per Mcf. The price that the Company receives under the Gas Sales Agreement would normally adjust on a semi-annual basis. However, the Gas Sales Agreement provides for adjustment on a more frequent basis in the event that certain indices and factors on which the price is based fluctuate outside a given range. See "Business and Properties -- International Operations; Contractual Terms Governing the Thailand Concession and Related Production." Due to the volatility of the Thai Baht and the current economic difficulties in the Kingdom of Thailand and throughout Southeast Asia, the price that the Company receives under the Gas Sales Agreement has been adjusted on almost a monthly basis since July 1997. As a result of these adjustments, during December 1997 the price that the Company received under the Gas Sales Agreement for its production from the Thailand Concession averaged approximately 68 Thai Baht per Mcf. However, the increases that the Company received during 1997 in the Thai Baht price for its natural gas production from the Thailand Concession were not sufficient to completely ameliorate, in U.S. dollar terms, the decline of the Thai Baht against the U.S. dollar. The Company cannot predict when, if ever, the adjustments provided for in the Gas Sales Agreement will completely recompense the Company for the decline of the Thai Baht against the U.S. dollar. See ";Foreign Currency Transaction Loss," "-- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues" and "Business and Properties -- International Operations; Contractual Terms Governing the Thailand Concession." NATURAL GAS PRODUCTION. The Company's natural gas production for 1997 averaged 181.7 MMcf per day, an increase of approximately 69% from average production of 107.7 MMcf per day during 1996, and an increase of approximately 50% from average production of 121 MMcf per day during 1995. 36 37 Domestic Production. The Company's domestic natural gas production for 1997 averaged 147.2 MMcf per day, an increase of approximately 37% from average production of 107.7 MMcf per day during 1996, and an increase of approximately 22% from average production of 121 MMcf per day during 1995. The increase in the Company's average domestic natural gas production for 1997, compared to 1996 and 1995, was related in large measure to production from the Company's East Cameron Block 334 "E" platform, which commenced production in April 1997, and, to a lesser extent, the results of successful drilling in the Company's Lopeno Field in South Texas and its Eugene Island Block 261 field, that was only partially offset by the anticipated natural decline in deliverability from certain of the Company's properties. Thailand Production. The Company commenced production from its Tantawan Field early in February 1997. Following a field startup phase which ended on March 15, 1997, production from the Tantawan Field stabilized. During 1997, the Company's share of natural gas production from the Tantawan Field averaged approximately 37.7 MMcf per day. CRUDE OIL AND CONDENSATE PRICES. Prices received by the Company for its crude oil and condensate production averaged $19.37 per Bbl during 1997, a decrease of approximately 12% compared to an average of $22.12 per Bbl during 1996, and an increase of approximately 9% compared to an average price of $17.80 per Bbl that the Company received during 1995. Domestic Prices. Prices that the Company received for its domestic crude oil and condensate production during 1997 averaged $19.49 per Bbl, a decrease of approximately 12% from an average price of $22.12 per Bbl that the Company received for its domestic crude oil and condensate production during 1996, and an increase of approximately 9% from an average price of $17.80 per Bbl that the Company received for its crude oil and condensate production during 1995. Thailand Prices. Since the inception of production from the Tantawan Field, crude oil and condensate has been stored on the FPSO until an economic quantity was accumulated for offloading and sale. The first such sale of crude oil and condensate from the Tantawan Field occurred in July 1997. The average price that the Company recorded for its crude oil and condensate production stored on the FPSO during 1997 was $18.60 per Bbl. Prices that the Company receives for such production are based on world benchmark prices, which are denominated in U.S. dollars, and are generally paid in U.S. dollars. CRUDE OIL AND CONDENSATE PRODUCTION. The Company's crude oil and condensate production for 1997 averaged 15,927 Bbls per day, an increase of approximately 33% from 11,968 Bbls per day for 1996, and an increase of approximately 35% from 11,786 Bbls per day for 1995. Domestic Production. The Company's domestic crude oil and condensate production for 1997 averaged 13,711 Bbls per day, an increase of approximately 15% from 11,968 Bbls per day for 1996, and an increase of approximately 16% from 11,786 Bbls per day for 1995. The increase in the Company's crude oil and condensate production for 1997, compared to 1996 and 1995, resulted primarily from increased condensate production from wells located in the Gulf of Mexico and, to a lesser extent, increased crude oil production from certain of the Company's onshore properties, which was only partially offset by the natural decline in deliverability from certain of the Company's more mature properties. Thailand Production. The Company commenced production from its Tantawan Field early in February 1997. Following a field startup phase which ended on March 15, 1997, production from the Tantawan Field stabilized. During 1997, the Company's share of crude oil and condensate production from the Tantawan Field averaged approximately 2,216 Bbls per day. NGL PRODUCTION AND "OTHER" NET REVENUE ITEMS. The Company's oil and gas revenues, and its total liquid hydrocarbon production, reflect the production and sale by the Company of NGL, which are liquid products that are extracted from natural gas production. In addition, the Company's oil and gas revenues for 1997, 1996 and 1995 also reflect adjustments for various miscellaneous items. The Company's NGL and other, net revenues for 1997 37 38 increased $1,452,000 from those reported in 1996, and $5,227,000 from those reported in 1995. The increase in NGL and other, net revenues in 1997, compared with 1996, primarily related to an increase in the Company's NGL production that was partially offset by a decrease in the average price that the Company received for such NGL production. The increase in NGL and other, net revenues in 1997, compared with 1995, primarily related to an increase in the Company's NGL production and, to a lesser extent, an increase in the price that the Company received for its NGL production. TOTAL LIQUID HYDROCARBON PRODUCTION. The Company's average liquid hydrocarbon (including crude oil, condensate and NGL) production during 1997 was 18,851 Bbls per day, an increase of approximately 33% from an average total liquids production of 14,141 Bbls per day for 1996, and an increase of approximately 37% from an average total liquids production of 13,784 Bbls per day for 1995. Lease Operating Expenses Lease operating expenses for 1997 were $63,501,000, an increase of approximately 69% from lease operating expenses of $37,628,000 for 1996, and an increase of approximately 81% from lease operating expenses of $35,071,000 for 1995. DOMESTIC LEASE OPERATING EXPENSES. The Company's domestic lease operating expenses for 1997 were $43,934,000, an increase of approximately 17% from domestic lease operating expenses of $37,628,000 for 1996, and an increase of approximately 25% from domestic lease operating expenses of $35,071,000 for 1995. The increase in domestic lease operating expenses for 1997, compared to 1996 and 1995, resulted primarily from increased costs to the Company (and the entire offshore oil industry) because of a shortage of qualified offshore service contractors, which permitted such contractors to increase the costs of their services significantly during 1997, increased expenses related to the leasing of certain equipment in the Gulf of Mexico, a year to year increase in the level of the Company's operating activities, including increased operating costs related to additional properties brought on production and an increased ownership interest in certain properties as a result of the acquisition of such interests. THAILAND LEASE OPERATING EXPENSES. The Company's lease operating expenses in Thailand for 1997 were $19,567,000. Prior to the commencement of production in the Tantawan Field on February 1, 1997, there were no lease operating expenses incurred by the Company in Thailand. A substantial portion of the Company's lease operating expenses in the Kingdom of Thailand relate to lease payments made by a subsidiary of the Company in connection with its bareboat charter of the FPSO, which amounted to $10,200,000 during 1997. See " -- Liquidity and Capital Resources; Capital Requirements; Other Material Long-Term Commitments." General and Administrative Expenses General and administrative expenses for 1997 were $21,412,000, an increase of approximately 19% from general and administrative expenses of $18,028,000 for 1996, and an increase of approximately 31% from general and administrative expenses of $16,400,000 for 1995. The increase in general and administrative expenses for 1997, compared to 1996 and 1995, was primarily related to salary and benefit expenses incurred in connection with the increase in the Company's work force in its Bangkok, Thailand office as a result of the Company's increased activities there. Exploration Expenses Exploration expenses for 1997 were $10,530,000, a decrease of approximately 37% from exploration expenses of $16,777,000 for 1996, and an increase of approximately 41% from exploration expenses of $7,468,000 for 1995. The decrease in exploration expenses for 1997, compared to 1996, resulted primarily from the incurrence of costs associated with conducting several 3-D seismic surveys by the Company on its leases in South Louisiana, East Texas and the Permian Basin during 1996 for which no similar costs of their magnitude were incurred during the comparative periods, although such costs were partially offset in 1997 by the costs associated with conducting the 38 39 Jarmjuree 3-D seismic survey in the Gulf of Thailand and by increased seismic data acquisition in the Gulf of Mexico. The increase in exploration expenses for 1997, compared to 1995, resulted primarily from increased geophysical activity by the Company, including the costs of conducting and processing the Jarmjuree 3-D seismic surveys. In addition, exploration expenses attributable to increased delay rental expense resulting from the Company's acquisition of additional prospective oil and gas acreage during 1997, as compared to 1996 and 1995, served to offset the decrease in exploration expenses for 1997, compared to 1996, and to increase the exploration expenses incurred during 1997, compared to 1995. The Company does not currently expect its exploration expenses in 1998 to increase significantly over those incurred during 1997. Dry Hole and Impairment Expenses Dry hole and impairment expenses relate to costs of unsuccessful wells drilled along with impairments due to decreases in expected reserves from producing wells. The Company's dry hole and impairment expenses for 1997 were $9,631,000, an increase of approximately 12% from dry hole and impairment costs of $8,579,000 for 1996, and an increase of approximately 44% from dry hole and impairment costs of $6,703,000 for 1995. Depreciation, Depletion and Amortization Expenses The Company's DD&A expense for 1997 was $103,157,000, an increase of approximately 67% from DD&A expenses of $61,857,000 for 1996, and an increase of approximately 51% from DD&A expenses of $68,489,000 for 1995. The increase in the Company's DD&A expenses for 1997, compared to 1996 and 1995, resulted primarily from an increase in the Company's natural gas and liquid hydrocarbon production and, to a lesser extent, an increase in the Company's composite DD&A rate. The composite DD&A rate for all of the Company's producing fields for 1997 was $0.95 per equivalent Mcf ($5.68 per equivalent Bbl), an increase of approximately 9% from a composite DD&A rate of $0.87 per equivalent Mcf ($5.20 per equivalent Bbl) for 1996, and an increase of approximately 3% from a composite DD&A rate of $0.91 per equivalent Mcf ($5.47 per equivalent Bbl) for 1995. The increase in the composite DD&A rate for all of the Company's producing fields for 1997, compared to 1996 and 1995, resulted primarily from an increased percentage of the Company's production coming from certain of the Company's fields that have DD&A rates that are higher than the Company's recent historical composite rate and a corresponding decrease in the percentage of the Company's production coming from fields that have DD&A rates that are lower than the Company's recent historical composite DD&A rate. Management currently anticipates that this trend will continue for the foreseeable future, resulting in generally increasing DD&A rates. The Company produced 107,605,000 equivalent Mcf (17,934,000 equivalent Bbls) in 1997, an increase of approximately 53% from the 70,472,000 equivalent Mcf (11,745,000 equivalent Bbls) produced in 1996, and an increase of approximately 45% from the 74,337,000 equivalent Mcf (12,389,000 equivalent Bbls) produced in 1995. Interest INTEREST CHARGES. The Company incurred interest charges for 1997 of $21,886,000, an increase of approximately 66% from interest charges of $13,203,000 for 1996, and an increase of approximately 96% from interest charges of $11,167,000 for 1995. The increase in the Company's interest charges for 1997, compared to 1996 and 1995, resulted primarily from an increase in the average amount of the Company's outstanding debt and, to a lesser extent, increased average interest rates on the debt outstanding (resulting primarily from the issuance of the 8 3/4% Senior Subordinated Notes due 2007 (the "2007 Notes") on May 22, 1997, which bear interest at an 8 3/4% annual interest rate) and increased expenses related to amortization of debt issuance expenses resulting from the issuance of the 2006 Notes in 1996. CAPITALIZED INTEREST EXPENSE. Capitalized interest for 1997 was $6,175,000 an increase of approximately 46% from capitalized interest of $4,244,000 for 1996, and an increase of approximately 237% from capitalized interest of $1,834,000 for 1995. The increase in capitalized interest for 1997, compared to 1996 and 1995, resulted primarily from the requirement to capitalize interest expense attributable to capital expenditures on non-producing properties, 39 40 principally capital expenditures related to the Company's development of the Tantawan Field and the East Cameron Block 334 "E" platform during the first quarter of 1997 and its development of the Benchamas Field commencing in 1997, which substantially exceeded the Company's capital expenditures on non-producing properties (principally the Tantawan Field) during 1996 and 1995. To a lesser extent, the increase in capitalized interest expense is also attributable to an increase in the rate used to compute the interest that was capitalized. The Company expects its capitalized interest costs to increase in the future, primarily as a result of the requirement to capitalize interest expense attributable to capital expenditures incurred in connection with its development of the Benchamas Field in the Gulf Thailand. See "Business and Properties -- International Operations; Significant International Operating Areas During 1997." Foreign Currency Transaction Loss The Company incurred a foreign currency transaction loss of $7,604,000 during 1997. No comparable losses were incurred in 1996 or 1995. The foreign currency transaction loss resulted from the devaluation against the U.S. dollar of cash and other monetary assets and liabilities denominated in Thai Baht that were on the Company's subsidiary's financial statements during 1997. In early July 1997, the government of the Kingdom of Thailand announced that the value of the Thai Baht would be set against the U.S. dollar and other currencies under a "managed float" program arrangement. Since that time the value of the Thai Baht has generally declined, although in recent weeks it has shown some sign of stabilizing. During the last two weeks of the month of February 1998, the Thai Baht traded in a range of approximately 43 to 48 Thai Baht to the U.S. dollar. The Company cannot predict what the Thai Baht to U.S. dollar exchange rate may be in the future. Moreover, it is anticipated that this exchange rate will remain volatile. Income Tax Expense Income tax expense for 1997 was $18,091,000, a decrease of approximately 4% from income tax expense of $18,800,000 for 1996, and an increase of approximately 270% from income tax expense of $4,891,000 for 1995. The decrease in income tax expense for 1997, compared to 1996, resulted primarily from the foreign currency transaction loss discussed in the preceding paragraph, which was partially offset by increased taxable income. The increase in income tax expense for 1997, compared to 1995, resulted primarily from increased taxable income. LIQUIDITY AND CAPITAL RESOURCES Cash Flows The Company's Condensed Consolidated Statement of Cash Flows for the nine months ended September 30, 1998, reflects net cash provided by operating activities of $70,466,000. In addition to net cash provided by operating activities, the Company received net proceeds of $998,000 from the exercise of stock options, $350,000 from the sale of certain non-strategic properties, and had net borrowings of $83,354,000 under its Credit Agreement and other senior debt facilities. During the first nine months of 1998, the Company invested $135,964,000 of such cash flow in capital projects, retired a production payment obligation for $15,246,000, spent $2,961,000 to purchase proved reserves, paid $3,327,000 ($0.03 per share for each of the first three quarters of 1998) in cash dividends to holders of the Company's common stock and paid a net amount of $621,000 in miscellaneous other expenditures. As of September 30, 1998, the Company's cash and cash investments were $17,422,000 and its long-term debt stood at $381,854,000. Future Capital Requirements The Company's capital and exploration budget for 1998, which does not include any amounts that may be expended for the purchase of proved reserves or any interest which may be capitalized resulting from projects in progress, was established by the Company's Board of Directors at $230,000,000. Substantially all of the Company's 1998 capital and exploration budget was spent or incurred during 1998. The Company currently anticipates that its 40 41 available cash and cash investments, cash provided by operating activities, funds available under its Credit Agreement and an uncommitted line of credit and amounts that the Company currently believes that it can obtain from external sources including the issuance of new debt (including the Notes) and convertible preferred securities, or asset sales, will be sufficient to fund the Company's ongoing operating, interest and general and administrative expenses, the remainder of its 1998 capital and exploration budget, any currently anticipated costs associated with the Company's projects during 1999, and future dividend payments at current levels. Subject to favorable market conditions and other factors, the Company also currently intends to issue convertible preferred equity securities during 1999 to assist in funding its future capital and exploration plans. The declaration of future dividends on the Company's common stock will depend upon, among other things, the Company's future earnings and financial condition, liquidity and capital requirements, its ability to pay dividends under certain covenants contained in its debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company's Board of Directors. Other Material Long-Term Commitments As of February 9, 1996, Tantawan Services, LLC ("TS"), a company that is currently a wholly owned subsidiary of the Company, entered into a Bareboat Charter Agreement (the "Charter") with Tantawan Production B.V. for the charter of the FPSO for use in the Tantawan Field. See "Business and Properties -- International Operations." The term of the Charter is for a period ending July 31, 2008, subject to extension. In addition, TS has a purchase option on the FPSO throughout the term of the Charter. TS has also contracted with another company, SBM Marine Services Thailand Ltd., to operate the FPSO on a reimbursable basis throughout the initial term of the Charter. Performance of both the Charter and the agreement to operate the FPSO are non-recourse to TS and the Company. However, performance is secured by a negative pledge on any hydrocarbons stored on the FPSO and is guaranteed by each of the working interest holders in the Tantawan Field, including Thaipo. Thaipo's guarantee is limited to its percentage interest in the Tantawan Field (currently 46.34%). The Charter currently provides for an estimated charter hire commitment of $24,000,000 per year ($11,122,000 net to Thaipo). As of August 24, 1998, Thaipo and its joint venture partners (collectively, the "Charterers") entered into a Bareboat Charter Agreement (the "BCA") with Watertight Shipping B.V. for the charter of a Floating Storage and Offloading system named the "Benchamas Explorer" (the "FSO"). See "Business and Properties - -- International Operations." The term of the BCA is for a period of ten years commencing on the date that the FSO is ready to begin operations in the Benchamas Field. In addition, the Charterers have a purchase option on the FSO throughout the term of the BCA. The Charterers have also contracted with another company, Tanker Pacific (Thailand) Co. Ltd, to operate the FSO on a fixed fee basis throughout the initial term of the BCA. Performance of both the BCA and the agreement to operate the FSO are non-recourse to the Company. However the obligations of each joint venturer are full recourse to each joint venturer, but the obligations are several, meaning that each joint venturer's obligations are limited to its percentage interest in the Thailand Concession. Collectively, the BCA and the operating agreement currently provides for an estimated expense of chartering and operating the FSO of $11,253,000 per year ($5,215,000 net to Thaipo). Capital Structure CREDIT AGREEMENT AND UNCOMMITTED CREDIT LINE. Effective August 1, 1997, the Company entered into an amended and restated Credit Agreement, which has subsequently been amended several times, most recently on December 21, 1998. The Credit Agreement provides for a $250,000,000 revolving/term credit facility which will be fully revolving until July 1, 2000, after which the balance will be due in eight quarterly term loan installments, commencing October 31, 2000. A portion of the amount that may be borrowed under the Credit Agreement (the "Primary Tranche") may not exceed a borrowing base which is composed of domestic, Canadian and Thai properties. Generally, the borrowing base is determined semi-annually by the lenders in accordance with the Credit Agreement, based on the lenders' usual and customary criteria for oil and gas transactions. As of December 21, 1998, the Company's total borrowing base was set at $200,000,000, which amount cannot be reduced until after April 30, 1999. In addition, certain lenders that are parties to the Credit Agreement have agreed to extend an additional $50,000,000 in credit (the "Secondary Tranche") under the Credit Agreement without reference to the 41 42 borrowing base limitations of the Credit Agreement. The term of the Secondary Tranche is until the earlier of April 30, 1999 or the completion of the Offering. The Credit Agreement is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and a fixed charge coverage ratio, and limitations on indebtedness, creation of liens, the prepayment of subordinated debt, the payment of dividends, mergers and consolidations, investments and asset dispositions. Upon the occurrence or declaration of certain events, the lenders would be entitled to a security interest in the Company's domestic borrowing base properties. In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. Borrowings under the Primary Tranche bear interest at a rate based upon the percentage of the borrowing base that is being utilized, ranging from a base (prime) rate or LIBOR plus 1.25% to a base rate plus 0.25% or LIBOR plus 2.0%, at the Company's option. Borrowings under the Primary Tranche currently bear interest at a base rate plus 0.25% or LIBOR plus 2.0%, at the Company's option. Borrowings under the Secondary Tranche currently bear interest at a base rate plus 0.75% or LIBOR plus 2.5%, at the Company's option. A commitment fee on the unborrowed amount under the Primary Tranche is also charged and is based upon the percentage of the borrowing base that is being utilized, ranging from 0.25% to 0.375%. The commitment fee is currently 0.375% per annum on the unborrowed amount under the Primary Tranche. As of December 31, 1998, there was $155,000,000 outstanding under the Primary Tranche and $50,000,000 outstanding under the Secondary Tranche. As of December 31, 1998, the Company had also entered into a separate letter agreement with a bank under which the bank may provide a $20,000,000 uncommitted money market line of credit. The line of credit is on an as available or offered basis and the bank has no obligation to make any advances under its line of credit. Although loans made under that letter agreement are for a maximum term of 30 days, they are reflected as long-term debt on the Company's balance sheet because the Company currently has the ability and intent to reborrow such amounts under its Credit Agreement. The letter agreement permits either party to terminate such letter agreement at any time. Under its Credit Agreement, the Company is currently limited to incurring a maximum of $20,000,000 of additional senior debt, which would include debt incurred under that line of credit and under the banker's acceptances discussed below. Further, the 2007 Notes and the Notes offered hereby also restrict the incurrence of additional senior indebtedness. See "; 2007 Notes" and "Description of the Notes -- Certain Covenants; Limitation on Indebtedness." BANKER'S ACCEPTANCES. On June 3, 1998, the Company entered into a Master Banker's Acceptance Agreement under which one of the Company's lenders has offered to accept up to $20,000,000 in bank drafts from the Company. The banker's drafts are available on an uncommitted basis and the bank has no obligation to accept the Company's request for drafts. Drafts drawn under this agreement are for a maximum term of 182 days; however, they are reflected as long-term debt on the Company's balance sheet because the Company currently has the ability and intent to reborrow such amounts under the Credit Agreement. Under its Credit Agreement, the Company is currently limited to incurring a maximum of $20,000,000 of additional senior debt, which would include banker's acceptances as well as debt incurred under the line of credit discussed previously. Further, the 2007 Notes and the Notes offered hereby also restrict the incurrence of additional senior indebtedness. See "; 2007 Notes" and "Description of the Notes -- Certain Covenants; Limitation on Indebtedness." The Master Banker's Acceptance Agreement permits either party to terminate the letter agreement at any time upon five business days notice. As of September 30, 1998, bank drafts in the principal amount of $10,854,000 bearing interest at a rate of 6.1% were outstanding under this agreement. 2007 NOTES. On May 22, 1997, the Company issued $100,000,000 principal amount of 2007 Notes. The proceeds from the issuance of the 2007 Notes were used to repay amounts outstanding under the Credit Agreement, and to purchase short-term cash investments. The 2007 Notes bear interest at a rate of 8 3/4%, payable semi-annually in arrears on May 15 and November 15 of each year, commencing November 15, 1997. The 2007 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under the Credit Agreement, its unsecured credit line and its banker's acceptances, are equal in right of payment to the Notes offered hereby, but are senior in right of payment to the Company's subordinated indebtedness, which currently includes the 2006 Notes. The Company, at its option, may redeem the 2007 Notes in whole or in part, at any time on or after May 15, 2002, at a redemption price of 104.375% of their principal value and decreasing percentages thereafter. No sinking fund payments are required on the 2007 Notes. The 2007 Notes are redeemable at the option of any holder, upon the 42 43 occurrence of a change of control (as defined in the indenture governing the 2007 Notes), at 101% of their principal amount. The indenture governing the 2007 Notes also imposes certain covenants on the Company that are substantially identical to the covenants contained in the indenture governing the Notes, including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of assets sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and mergers, consolidations and the sale of assets. 2004 NOTES. The Company's 2004 Notes were called for redemption on March 13, 1998, at a price equal to 103.30% of their principal amount. Prior thereto, holders of all but $95,000 principal amount of the 2004 Notes chose to convert their 2004 Notes into Common Stock at a conversion price of $22.188 per common share, rather than receive cash for their 2004 Notes resulting in the issuance of 3,879,726 shares of Common Stock. 2006 NOTES. The outstanding principal amount of 2006 Notes was $115,000,000 as of September 30, 1998. The 2006 Notes are convertible into Common Stock at $42.185 per share, subject to adjustment upon the occurrence of certain events. The 2006 Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after June 15, 1999, at a redemption price of 103.85% of their principal amount and decreasing percentages thereafter. No sinking fund payments are required on the 2006 Notes. The 2006 Notes are redeemable at the option of any holder, upon the occurrence of a repurchase event (a change of control and other circumstances as defined in the indenture governing the 2006 Notes), at 100% of the principal amount. Other Matters INFLATION. Publicly held companies are asked to comment on the effects of inflation on their business. Currently annual inflation in terms of the decrease in the general purchasing power of the U.S. dollar is running much below the general annual inflation rates experienced in the past. While the Company, like other companies, continues to be affected by fluctuations in the purchasing power of the U.S. dollar due to inflation, such effect is not currently considered significant. SOUTHEAST ASIA ECONOMIC ISSUES. A substantial portion of the Company's oil and gas operations are conducted in Southeast Asia, and a substantial portion of its natural gas and liquid hydrocarbon production are sold there. In recent months, Southeast Asia in general, and the Kingdom of Thailand in particular, have experienced severe economic difficulties which have been characterized by sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. The government of the Kingdom of Thailand and other governments in the region are currently acting to address these issues. However, the economic difficulties currently being experienced in Thailand, together with the volatility of the Thai Baht against the U.S. dollar, will continue to have a material impact on the Company's operations in the Kingdom of Thailand, together with the prices that the company receives for its oil and natural gas production there. See "-- Results of Operations; Oil and Gas Revenues" and "-- Results of Operations; Foreign Currency Transaction Gain (Loss)" for both the nine month and yearly comparative periods. All of the Company's current natural gas production from the Thailand Concession is committed under a long term Gas Sales Agreement to PTT at a price denominated in Thai Baht which is determined in accordance with a formula that is intended to ameliorate, at least in part, any decline in the purchasing power of the Thai Baht against the U.S. dollar. See "Business and Properties -- International Operations; Contractual Terms Governing the Thailand Concession" and "Business and Properties -- Miscellaneous; Sales." Although the Company currently believes that PTT will honor its commitments under the Gas Sales Agreement, a failure by PTT to honor such commitments could have a material adverse effect on the Company. The Company's crude oil and condensate production from the Thailand Concession is sold on a tanker load by tanker load basis. Prices that the Company receives for such production are based on world benchmark prices, which are denominated in U.S. dollars, and are typically paid in U.S. dollars. See "Business and Properties -- International Operations; Contractual Terms Governing the Thailand Concession and Related Production" and "Business and 43 44 Properties -- Miscellaneous; Sales." The Company believes that the current economic difficulties in Southeast Asia have resulted in a decreased demand for petroleum products in the region, which has contributed to the recent general decline in crude oil and condensate prices throughout the world. This price decline has had an adverse effect on all oil and gas companies that sell their production on the world spot markets, including the Company, without regard to where their respective production is located. YEAR 2000 READINESS DISCLOSURE. Many computer software systems, as well as certain hardware and equipment using date-sensitive data, were structured to use a two-digit date field meaning that they may not be able to properly recognize dates in the year 2000. The Company is addressing this issue through a process that entails evaluation of the Company's critical software and, to the extent possible, its hardware and equipment to identify and assess Year 2000 issues and to remediate, replace or establish alternative procedures addressing non-Year 2000 compliant systems, hardware and equipment. The Company has substantially completed an inventory of its systems and equipment including computer systems and business applications. Based upon this review, the Company currently believes that all of its critical software and computer hardware systems are either Year 2000 compliant or will be within the next six months. The Company continues to inventory its equipment and facilities to determine if they contain embedded date-sensitive technology. If problems are discovered, remediation, replacement or alternative procedures for non-compliant equipment and facilities will be undertaken on a business priority basis. This process will continue and, depending upon the equipment and facilities, is scheduled for completion during the first three quarters of 1999. As of September 30, 1998, the Company had incurred approximately $50,000 in expenses related to its Year 2000 compliance efforts. These costs are currently being expensed as they are incurred. However, in certain instances the Company may determine that replacing existing equipment may be more efficient, particularly where additional functionality is available. These replacements may be capitalized and therefore would reduce the estimated 1998 and 1999 expenses associated with the Year 2000 issue. The Company currently expects total out-of-pocket costs to become Year 2000 compliant to be less than $1,000,000. The Company currently expects that such costs will not have a material adverse effect on the Company's financial condition, operations or liquidity. The foregoing timetable and assessment of costs to become Year 2000 compliant reflect management's current best estimates. These estimates are based on many assumptions, including assumptions about the cost, availability and ability of resources to locate, remediate and modify affected systems, equipment and facilities. Based upon its activities to date, the Company does not currently believe that these factors will cause results to differ significantly from those estimated. However, the Company cannot reasonably estimate the potential impact on its financial condition and operations if key third parties including, among others, suppliers, contractors, joint venture partners, financial institutions, customers and governments do not become Year 2000 compliant on a timely basis. The Company is contacting many of these third parties to determine whether they will be able to resolve in a timely fashion their Year 2000 issues as they may affect the Company. In the event that the Company is unable to complete the remediation or replacement of its critical systems, facilities and equipment, establish alternative procedures in a timely manner, or if those with whom the Company conducts business are unsuccessful in implementing timely solutions, Year 2000 issues could have a material adverse effect on the Company's liquidity and results of operations. At this time, the potential effect in the event the Company and/or third parties are unable to timely resolve their Year 2000 problems is not determinable; however, the Company currently believes that it will be able to resolve its own Year 2000 issues in a timely manner. The disclosure set forth in this section is provided pursuant to Securities Act Release No. 33-7558. As such it is protected as a forward-looking statement under the Private Securities Litigation Reform Act of 1995. See "Forward- Looking Statements." This disclosure is also subject to protection under the Year 2000 Information and Readiness Disclosure Act of 1998, Public Law 105-271, as a "Year 2000 Statement" and "Year 2000 Readiness Disclosure" as defined therein. 44 45 BUSINESS AND PROPERTIES The Company was incorporated in 1970 and is engaged in oil and gas exploration, development and production activities on its properties located offshore in the Gulf of Mexico, onshore in selected areas in New Mexico, Texas and Louisiana, and internationally, primarily in the Gulf of Thailand. As of December 31, 1998, the Company had interests in 105 lease blocks offshore Louisiana and Texas, approximately 378,000 gross acres onshore in the United States, approximately 734,000 gross acres offshore in the Kingdom of Thailand, 150,000 gross acres in Canada and 113,000 gross acres in the British North Sea. On August 17, 1998, a wholly owned subsidiary of the Company merged with and into Arch in a tax free, stock for stock transaction through which Arch became a wholly owned subsidiary of the Company. The Company issued approximately 2,540,000 of its common shares in connection with the merger, or approximately 6% of its common stock outstanding at the time of the merger. For a description of the Arch and its subsidiaries' businesses, properties and operations, please see "-- Arch and its Subsidiaries." Quantitative information in this "Business and Properties" section which precedes "-- Arch and its Subsidiaries" does not include any such information relating to Arch and its subsidiaries. Quantitative and geological information in the "-- Arch and its Subsidiaries" subsection includes only information relating to Arch and its subsidiaries. Unless otherwise specifically identified, the information set forth in this offering memorandum, including production rates and the number of wells, platforms and blocks, is presented on a gross basis, rather than net to the Company or Arch, as applicable. Unless otherwise stated, quantitative data set forth in this "Business and Properties" section was current as of March 13, 1998. The Company has not attempted to update this information but it believes that any changes in this quantitative information are not material to an understanding of the Company and its subsidiaries. In recent years, the Company has concentrated its efforts in selected areas where it believes that its expertise, competitive acreage position, or ability to quickly take advantage of new opportunities offer the possibility of superior rates of return. As of December 31, 1997, six significant operating areas, of which three are located in the Gulf of Mexico and one each in South Texas, New Mexico and Thailand, accounted for approximately 82% of the Company's estimated proved natural gas reserves, approximately 90% of the Company's estimated proved oil, condensate and natural gas liquids reserves, approximately 80% of the Company's natural gas production and 89% of the Company's oil, condensate and natural gas liquids production for 1997. Reserves, as estimated by Ryder Scott, and production data, as estimated by the Company, for the six significant operating areas are shown in the following table. No other producing area accounted for more than 3% of the Company's estimated proved reserves as of December 31, 1997. SIGNIFICANT OPERATING AREAS
1997 AVERAGE NET NET PROVED RESERVES(A) DAILY PRODUCTION ---------------------------------------- --------------------------------------- TOTAL NET NATURAL GAS LIQUIDS(B) NATURAL GAS LIQUIDS(B) PROVED ----------------- ----------------- ----------------- ---------------- RESERVES(a) MMCF % MBBLS % MCF % BBLS % % ------- ---- ------ ---- ------ ---- ----- ---- ---- DOMESTIC OFFSHORE Eugene Island........ 27,182 6.8 7,607 13.1 23,334 13.5 4,673 24.5 10.7 Main Pass............ 14,570 3.6 3,830 6.6 7,104 4.1 2,777 14.6 5.0 East Cameron......... 30,199 7.5 1,006 1.7 53,893 31.2 3,242 17.0 4.8 DOMESTIC ONSHORE New Mexico........... 20,578 5.1 11,287 19.4 9,151 5.3 4,008 21.0 11.8 South Texas.......... 52,724 13.1 1 0.0 11,484 6.6 0 0.0 7.0 INTERNATIONAL Kingdom of Thailand.. 184,768 46.0 28,783 49.5 37,733 19.0 2,421 14.0 47.6
- ------------- 45 46 (a) Net proved reserves and total net proved reserves are each as of December 31, 1997. (b) "Liquids," includes oil, condensate and NGL. DOMESTIC OFFSHORE OPERATIONS Historically, the Company's interests have been concentrated in the Gulf of Mexico, where approximately 59% of the Company's domestic proved reserves and 31% of its total proved reserves were located as of December 31, 1997. During 1997, approximately 65% of the Company's natural gas production and approximately 59% of its oil and condensate production was from its domestic offshore properties, contributing approximately 62% of the Company's consolidated oil and gas revenues. Three offshore producing areas, Eugene Island, Main Pass and East Cameron, accounted for approximately 18% of the Company's net proved natural gas reserves and approximately 21% of the Company's proved crude oil, condensate and natural gas liquids reserves as of December 31, 1997. See "-- Significant Domestic Offshore Operating Areas During 1997." Lease Acquisitions The Company has participated, either on its own or with other companies, in bidding on and acquiring interests in federal and state leases offshore in the Gulf of Mexico since December 1970. As a result of such sales and subsequent activities, as of December 31, 1997, the Company owned interests in 93 federal leases and 8 state leases offshore Louisiana and Texas. Federal leases generally have primary terms of five, eight or ten years, depending on water depth, and state leases generally have terms of three or five years, depending on location, in each case subject to extension by development and production operations. As part of its strategy, the Company intends to continue an active lease evaluation program in the Gulf of Mexico in order to identify exploration and exploitation opportunities. During 1997, the Company was successful in acquiring interests in 19 lease blocks through federal Outer Continental Shelf oil and gas lease sales and 1 lease block by assignment from a third party. As in the case of prior sales, the extent to which the Company participates in future bidding on federal or state offshore lease sales will depend on the availability of funds and its estimates of hydrocarbon deposits, operating expenses and future revenues which reasonably may be expected from available lease blocks. Such estimates typically take into account, among other things, estimates of future hydrocarbon prices, federal regulations, and taxation policies applicable to the petroleum industry. It is also the Company's objective to acquire certain producing leasehold properties in areas where additional low-risk drilling or improved production methods by the Company can provide attractive rates of return. Exploration and Development The scope of exploration and development programs relating to the Company's offshore interests is affected by prices for oil and gas, and by federal, state and local legislation, regulations and ordinances applicable to the petroleum industry. The Company's domestic offshore capital and exploration expenditures for 1997 were approximately $86,300,000, or 9% lower than the Company's domestic offshore capital and exploration expenditures of approximately $94,400,000 (excluding approximately $2,000,000 of net property acquisitions) for 1996 and 128% higher than the Company's domestic offshore capital and exploration expenditures of approximately $37,800,000 for 1995 (excluding approximately $650,000 of net property acquisitions) for 1995. The decrease in the Company's domestic offshore capital and exploration expenditures for 1997, compared with 1996, resulted primarily from a decrease in drilling activity and in construction and installation of offshore platforms, pipelines and other facilities, which was partially offset by the increased costs to the Company (and the entire oil and gas industry generally) because of price increases by the oil and gas services, construction and supply industries due to the shortage of skilled workers and the comparative scarcity of certain equipment, such as drilling rigs, and critical materials, such as certain types of steel pipe. The increase in the Company's domestic offshore capital and exploration expenditures for 1997, compared to 1995, resulted primarily from increased drilling activity and increased costs associated with 46 47 the construction and installation of offshore platforms, pipelines and other facilities and the increase in prices discussed above. See "Management's Discussion and Analysis of Financial Condition and Results of Operations." Leases acquired by the Company and other participants in its bidding groups are customarily committed, on a block-by-block basis, to separate operating agreements under which the appointed operator supervises exploration and development operations for the account and at the expense of the group. These agreements usually contain terms and conditions which have become relatively standardized in the industry. Major decisions regarding development and operations typically require the consent of at least a majority (in working interest) of the participants. Because the Company generally has a meaningful working interest position, the Company believes it can significantly influence (but not always control) decisions regarding development and operations on most of the leases in which it has a working interest even though it may not be the operator of a particular lease. The Company was the operator on all or a portion of 30 of the 101 offshore leases in which it had an interest on December 31, 1997. Platforms and related facilities are installed on an offshore lease block when, in the judgment of the lease interest owners, the necessary capital expenditures are justified. A decision to install a platform generally is made after the drilling of one or more exploratory wells with contracted drilling equipment. Platforms are used to accommodate both development drilling and additional exploratory drilling. Over the three years ended December 31, 1997, the gross cost of production platforms and related facilities to the joint ventures in which the Company has varying net interests has ranged from approximately $3,000,000 to approximately $16,500,000. Platform costs vary and more expensive platforms could be required in the future depending on, among other factors, the number of slots, water depth, currents, and sea floor conditions. For example, during 1997, the Company and its joint venture partners approved construction of a platform located on Viosca Knoll Block 823 which will be located in approximately 1,200 feet of water. This platform, together with its related pipelines and other facilities, is estimated to have a gross cost of approximately $140,000,000 (approximately $15,100,000 net to the Company's current working interest). Significant Domestic Offshore Operating Areas During 1997 EUGENE ISLAND. A significant portion of the Company's reserves and a substantial part of its production are located in the Eugene Island area off the Louisiana coast in the Gulf of Mexico. The Eugene Island area has been an important part of the Company's operations since the first lease in that area was purchased in 1970 and production began in 1973. As of December 31, 1997, the Company held interests in 10 blocks in the Eugene Island area. These blocks comprise eight fields containing 64 oil and gas wells producing from multiple reservoirs and horizons. During 1997, the Company participated in the drilling of eight wells in the Eugene Island operating area. The Eugene Island Block 330 field is one of the Company's most significant producing assets. This field, located in 245 feet of water, contains three drilling and production platforms in which the Company holds a 35% working interest, as well as an additional platform in which the Company holds a 30% working interest. As of December 31, 1997, there were 12 wells producing primarily natural gas and 34 wells producing primarily oil on the block. The Company and its joint venture partners drilled six new wells which added significant new reserves in this field during 1997. MAIN PASS. The Company's 12 lease blocks in the Main Pass area, including two acquired in 1997, are located near the mouth of the Mississippi River in the Gulf of Mexico and include leases in which the Company has held an interest since 1974. The majority of the Company's production from the Main Pass area comes from a field that includes Main Pass Blocks 72, 73 and 72/74 which was unitized in 1982. The Company's working interest in this field is 35%. As of December 31, 1997, this field contained 20 producing oil wells and nine producing natural gas wells from three platforms operated by the Company's joint venture partner and is located in 125 feet of water. The Company participated in the drilling of 3 exploratory wells in the Main Pass area during 1997. EAST CAMERON. The first leasehold interest acquired by the Company in the East Cameron area off the Texas/Louisiana border in the Gulf of Mexico commenced production in February 1973. Presently, the Company has interests in five offshore blocks in this area which contain two fields and 19 producing gas wells. Two of the 47 48 five blocks were awarded to the Company and its joint venture partners during 1997 and have yet to be fully evaluated. During 1997, the Company and its partners were active in the East Cameron Block 334/335 field. In February 1997, the Company and one of its joint venture partners completed construction of the East Cameron "E" platform and commenced production from two wells. Following mechanical problems in one of these wells which caused it to be shut in, production was restored in the first week of January 1998. The Company and its joint venture partners completed construction of a sixth platform during 1997, known as the "F" platform. Production from the well served by this platform, in which the Company holds a 42% interest, commenced in December 1997. DOMESTIC ONSHORE OPERATIONS The Company has onshore division staffs in Houston and Midland, Texas. Its onshore activities are concentrated in known oil and gas provinces, principally the Permian Basin area of southeastern New Mexico, West Texas and Northwest Texas, and in the onshore Gulf Coast areas of South Texas, East Texas and South Louisiana. See "-- Significant Domestic Onshore Operating Areas During 1997." Lease Acquisitions Commencing in 1995 and continuing into 1997, the Company increased its activities in the onshore Gulf Coast areas of East Texas and South Louisiana through its participation in several large proprietary 3-D seismic surveys, in connection with which the Company typically purchases an option to acquire an interest in the acreage covered by the 3-D seismic survey. As it has in recent years, in 1997 the Company also successfully participated in various onshore federal and state lease sales and acquired interests in prospective acreage from private individuals. As of December 31, 1997, the Company held interests in approximately 237,000 gross (113,000 net) acres onshore in the United States, an increase of approximately 12% from year end 1996. Exploration and Development The Company's primary drilling objective in the Permian Basin is the Brushy Canyon (Delaware) formation which generally produces oil from depths of 6,000 to 9,000 feet. Since the Company began exploring in the Brushy Canyon (Delaware) formation in October 1989, it has participated in drilling 357 wells in the Permian Basin, West and Northwest Texas areas through December 31, 1997, including 58 wells in 1997. The Company's primary drilling activity in East Texas has been in the Cotton Valley formation reef play. In South Louisiana, the Company participated in drilling 11 wells in 1997 to test various Hackberry formation and Yegua formation prospects, all of which were identified on proprietary 3-D seismic surveys that the Company and its industry partners have acquired since 1995. The Company also actively explores for oil and gas onshore in South Texas. In total, the Company participated in the drilling of 25 wells in the onshore Gulf Coast areas of South Texas, East Texas and South Louisiana, including 14 exploratory wells (principally in East Texas and South Louisiana) and 11 developmental wells (principally in the Lopeno Field in South Texas). See "-- Significant Domestic Onshore Operating Areas During 1997; South Texas." Domestic onshore reserves as of December 31, 1997, accounted for approximately 41% of the Company's domestic proved reserves and approximately 21% of its total proved reserves. During 1997, approximately 16% of the Company's natural gas production and 27% of its oil and condensate production was from its domestic onshore properties, contributing approximately 20% of the Company's consolidated oil and gas revenues. The Company generally conducts its onshore activities through joint ventures and other interest-sharing arrangements with major and independent oil companies. The Company operates many of its own onshore properties using independent contractors. The Company's domestic onshore capital and exploration expenditures were approximately $60,000,000 (excluding approximately $1,700,000 of net property acquisitions) for 1997, or 28% higher than the Company's 48 49 domestic onshore capital and exploration expenditures of approximately $47,000,000 (excluding approximately $3,800,000 of net property acquisitions) for 1996 and 82% higher than the Company's domestic onshore capital and exploration expenditures of approximately $33,000,000 (excluding approximately $7,800,000 of net property acquisitions) for 1995. The increase in the Company's domestic onshore capital and exploration expenditures for 1997, compared to 1996 and 1995, resulted primarily from increased drilling activity in South Texas, East Texas and South Louisiana and, to a lesser extent, by the increased costs to the Company (and the entire oil and gas industry generally) because of price increases by the oil and gas services, construction and supply industries due to the shortage of skilled workers and the comparative scarcity of certain equipment, such as drilling rigs and critical materials, such as certain types of steel pipe. Significant Domestic Onshore Operating Areas During 1997 NEW MEXICO. The Company believes that during the past five years it has been one of the most active companies drilling for oil and natural gas in the southeastern New Mexico (Lea and Eddy Counties) portion of the Permian Basin where the Company has interests in over 79,000 gross acres. The Company's primary drilling objective is the Brushy Canyon (Delaware) formation. Fields in the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of the Permian Basin are generally characterized by production from relatively shallow depths (6,000 to 9,000 feet), multiple producing zones in most wells and relatively high initial rates of production (frequently equaling the top field allowables which typically range from 142 Bbls to 230 Bbls per day, depending on the depth of production from the field). The Company has achieved rapid cost recovery with respect to its New Mexico wells drilled to date because of relatively low capital costs and high initial rates of production. Since the Company began exploring in the Brushy Canyon (Delaware) formation in the southeastern New Mexico portion of the Permian Basin in October 1989, it has participated through December 31, 1997, in the drilling of, among others, 94 wells in the Sand Dunes field where the Company's working interest ranges from 4% to 100%, 27 wells in the East Loving field where the Company's working interest ranges from 33% to 98%, 60 wells in the Livingston Ridge field where the Company's working interest ranges from 25% to 100%, 61 wells in the Red Tank field where the Company's working interest ranges from 89% to 100%, 31 wells in the Cedar Canyon field where the Company's working interest ranges from 38% to 100% (including 15 during 1997), 15 wells in the Lost Tank field where the Company's working interest ranges from 50% to 100% (including 12 during 1997), and 3 wells in the Poker Lake Field where the Company's working interest ranges from 60% to 100%. SOUTH TEXAS. The Company has increased its activity in South Texas in recent years, where, as of December 31, 1997, it was active in two fields, both of which primarily produce natural gas. The most significant of these two fields is the Lopeno Field, which is located within 40 miles of the border with Mexico. The Company acquired its initial interest in the Lopeno Field in 1983. As of December 31, 1997, the Company had interests in over 7,800 gross acres in South Texas containing 29 producing wells, with working interests generally averaging approximately 50%. The Lopeno Field produces from over 20 upper Wilcox sandstone reservoirs ranging in depth up to 12,500 feet. Based in part on a 3-D seismic survey acquired over the field in 1994, the Company and its joint venture partners commenced an active development drilling program in the fourth quarter of 1995. In 1997, the Company drilled seven successful wells in the Lopeno Field and drilled additional wells in this field during 1998. INTERNATIONAL OPERATIONS The Company has conducted international exploration activities since the late 1970's in numerous oil and gas areas throughout the world. Currently, the Company maintains an office in Bangkok, Thailand from which it directs field operations in the Gulf of Thailand on its Thailand Concession through its wholly owned subsidiary Thaipo. As a result of its acquisition in 1995 and March 1997 of portions of the original interest of Maersk Oil (Thailand) Ltd., a former joint venture partner that owned a 31.67% interest in the Thailand Concession, the Company has increased its ownership interest in the Thailand Concession so that it currently owns, directly or indirectly, a 46.34% working interest in the entire Thailand Concession. The remainder of the working interest is owned, directly or indirectly by Thai Romo Ltd. (46.34%), a subsidiary of RMOC, and Palang Sophon Limited ("Palang") (7.32%). Thaipo is currently the operator of the Thailand Concession, pursuant to the joint operating agreement and as designated by the 49 50 government of Thailand. On December 23, 1998, RMOC, the parent company of Thai Romo, Ltd., announced that it had agreed to be acquired by Chevron. Their agreement is subject to conditions, several of which are outside of RMOC's control. One of these conditions is that Chevron reach agreement with the Company on a new joint operating agreement that would include the transfer of operatorship on the Thailand Concession from Thaipo to a subsidiary of Chevron. The merger is also conditioned upon Chevron reaching agreement with Palang, the third partner in the Thailand Concession, to acquire at least a 5 percent interest in the Concession from Palang and upon all parties waiving any preferential rights that may arise in connection with the acquisition. The Company cannot predict whether Chevron will reach agreement with the Company and Palang or whether the other conditions to Chevron's acquisition of RMOC will be satisfied or waived. RMOC has also stated that its financial resources will be exhausted in February 1999, and that its banks have currently refused to lend it any additional funds. Chevron has agreed to lend additional funds to RMOC if most of the conditions to the acquisition have been satisfied, including Chevron's reaching agreement with us on a new joint operating agreement. Thai Romo's failure to pay its share of the expenses of our projects in the Gulf of Thailand could have a material adverse effect on the Company, due to the increased capital requirements that funding Thai Romo's share of the project development costs could have on the Company. As of December 31, 1997, the Company's proved reserves located in the Kingdom of Thailand accounted for approximately 48% of the Company's total proved reserves. During 1997, approximately 19% of the Company's natural gas production and 14% of its oil and condensate production came from its operations on the Thailand Concession, contributing approximately 14% of the Company's consolidated oil and gas revenues. Exploration and Development The Company's international capital and exploration expenditures were approximately $88,300,000 (excluding approximately $28,600,000 of net property acquisitions) for 1997, or 37% higher than the Company's international capital and exploration expenditures of approximately $64,400,000 for 1996 and 152% higher than the Company's international capital and exploration expenditures of approximately $35,000,000 (excluding approximately $4,200,000 of net property acquisitions) for 1995. The increase in the Company's international capital and exploration expenditures for 1997, compared to 1996 and 1995, resulted primarily from increased platform and facilities construction costs related to initial development of the Benchamas Field, increased drilling activity and, to a lesser extent, by the increased costs to the Company (and the entire oil and gas industry generally) because of price increases by the oil and gas services, construction and supply industries due to the shortage of skilled workers and the comparative scarcity of certain equipment, such as drilling rigs, and certain critical materials, such as certain types of steel pipe. Substantially all of the Company's international capital and exploration expenditures for 1997 were related to the Company's license in the Kingdom of Thailand. In addition, the Company continues to evaluate other international opportunities that are consistent with the Company's international exploration strategy. Platforms are installed on the Thailand Concession in fields where, in the judgment of Thaipo and its joint venture partners, the necessary capital expenditures are justified. A decision to install a platform generally is made after the drilling of one or more exploratory wells with contracted drilling equipment and the area where the platform would be located has been designated a production area by the Thai government. See "-- Contractual Terms Governing the Thailand Concession and Related Production." Platforms are used to accommodate both development drilling and additional exploratory drilling. Over the three years ended December 31, 1997, the gross cost of the first four production platforms and related facilities in the Tantawan Field has averaged approximately $20,000,000. Platform costs vary and more (or less) expensive platforms could be required in the future depending on, among other factors, the number of slots, water depth, currents, and sea floor conditions. See "-- Significant International Operating Areas During 1997; Tantawan Field." Significant International Operating Areas During 1997 TANTAWAN FIELD. In August 1995, at the request of Thaipo and its joint venture partners, the government of Thailand designated a portion of the Thailand Concession comprising approximately 68,000 acres as the Tantawan production area. The Tantawan production area has been named the Tantawan Field. Through March 13, 1998, 19 exploration and 29 development wells have been drilled in the Tantawan Field. Initial production from the Tantawan Field commenced on February 1, 1997, from wells located on two platforms. Currently, there are wells producing 50 51 from four platforms. The Company is currently planning to install a fifth platform in the Tantawan Field from which production is currently expected to commence in the second half of 1999. Oil and gas production from the Tantawan Field is gathered through pipelines from the platforms into the FPSO named the "Tantawan Explorer." The FPSO is a converted oil tanker with a capacity of slightly less than 1,000,000 Bbls, that is moored in the Tantawan Field, on which hydrocarbon processing, separation, dehydration, compression, metering and other production related equipment is installed. Following processing on board the FPSO, natural gas produced from the field is delivered to PTT through an export pipeline. Oil and condensate produced from the field is stored on board the FPSO and transferred to shore by oil tanker. The FPSO and its processing equipment is leased from a third party under a bareboat charter by Tantawan Services, LLC, an affiliate of Thaipo. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Thaipo and its joint venture partners pay a processing fee to Tantawan Services, LLC to process the production from the Tantawan Field through the FPSO. BENCHAMAS FIELD AND THE MALIWAN PRODUCTION AREA. In July 1997, the government of Thailand designated another portion of the Thailand Concession comprising approximately 102,000 acres of the Benchamas and Pakakrong production area as the Benchamas Field. This area includes at least two discrete geologic structures which were previously designated as the Benchamas and Pakakrong areas, respectively. In September 1997, the government of Thailand designated an additional 91,000 acres of the Thailand Concession as the Maliwan production area. Through March 13, 1998, 14 exploration wells have been drilled in the Benchamas Field and four exploration wells have been drilled in the Maliwan production area. Current development plans call for the staged development of these fields, with the Benchamas Field to be brought on production first. The Benchamas Field development plan contemplates the initial installation of three production platforms, with natural gas and oil from these platforms delivered by undersea pipeline to a central processing and compression platform where the oil, condensate and natural gas will be processed and separated. The natural gas will then be sold to PTT and delivered into export pipelines for transportation to shore, while the oil and condensate produced from the field will be stored on board the FSO for sale and ultimate transfer to shore by oil tanker. The FSO will be moored in the Benchamas Field. Its capacity will be approximately 1,400,000 Bbls of oil, or slightly more than the FPSO. The field's current development plan calls for initial production to commence in the third quarter of 1999. OTHER AREAS. In addition to the above mentioned fields, Thaipo and its joint venture partners have identified other potentially promising areas on the Thailand Concession. Since acquiring their interest in the Thailand Concession, Thaipo and its joint venture partners have acquired 3-D seismic surveys covering approximately 673,650 acres of the Thailand Concession, including 221,650 acres during the fourth quarter of 1997 over what is known as the Jarmjuree area. Interpretation of the Jarmjuree 3-D seismic survey commenced in the first quarter of 1998 and is ongoing. Contractual Terms Governing the Thailand Concession and Related Production The Thailand Concession was granted in August 1991. The original exploratory term of the concession agreement governing those portions of the Thailand Concession not designated as a production area expired on July 31, 1997. However, on application from Thaipo and its joint venture partners, the government of Thailand agreed in a supplemental concession agreement to extend the exploratory term for those portions of the Thailand Concession that have not yet been designated a production area (comprising approximately 474,000 acres) until July 31, 2000. In exchange, the Company and its joint venture partners committed to, among other things, an additional work program which includes the drilling of two wells and the acquisition of 148,000 acres of 3-D seismic data during the remainder of the exploratory term. (This work commitment was satisfied during the ordinary course of the Company's operations on the Thailand Concession during 1998.) For those portions of the Thailand Concession that have been designated as production areas the initial production period term is 20 years, which is also subject to extension, generally for a term of ten years. See also "-- Miscellaneous; Sales." Currently, the Tantawan, Maliwan, and Benchamas and Pakakrong areas have been designated as production areas. Subject to governmental approval, other portions of the Thailand Concession may be designated production areas in the future. 51 52 Production resulting from the Thailand Concession is subject to a royalty ranging from 5% to 15% of oil and gas sales, plus certain fixed U.S. dollar amounts payable at specified cumulative production levels. Revenue from production in Thailand is also subject to income taxes and other similar governmental charges including a Special Remuneratory Benefit tax ("SRB"). On November 7, 1995, Thaipo and its joint venture partners announced the signing of a thirty-year Gas Sales Agreement with PTT, initially governing gas production from the Tantawan Field. On November 12, 1997, Thaipo and its joint venture partners entered into an amendment to the gas sales agreement to include the reserves and anticipated gas production from the Benchamas Field. The terms of the Gas Sales Agreement currently include a minimum daily contract quantity ("DCQ") of 85 MMcf per day, which the Company currently anticipates will continue until the Benchamas Field commences production, at which time the DCQ will, subject to certain exceptions, be based on a percentage of the remaining proved reserves, but in any event, will not be less than 125 MMcf per day. The DCQ is the minimum daily volume that PTT has agreed to take, or pay for if not taken under the agreement. Likewise, Thaipo and its joint venture partners are subject to certain penalties if they are unable to meet the DCQ, principal among which is a decrease in sales price of up to 25% of the then current sales price. As a result of declining production from existing wells in the Tantawan Field, the need to shut-in existing wells while drilling additional wells from the same platform, and the decision to emphasize oil and condensate production from the Tantawan Field, commencing on October 1, 1998, the Company and its joint venture partners are currently delivering less natural gas than is being nominated by PTT under the Gas Sales Agreement. This could result in the Company receiving only 75% of the current contract price on a portion of its future natural gas sales to PTT. The Company is taking actions that it currently believes will minimize the penalty that it will incur on future gas sales to PTT by, among other things, increasing production from the Tantawan Field. The contract sales price is subject to automatic semi-annual adjustments based upon a formula which takes into account, among other things, changes in: Singapore fuel oil prices; the U.S. Bureau of Labor Statistics Oilfield Machinery and Tool Index; the Thai wholesale producer price index; and the U.S./Thai currency exchange rate. However, the Gas Sales Agreement provides for adjustment on a more frequent basis in the event that certain indices and factors on which the price is based fluctuate outside a given range. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Results of Operations; Foreign Currency Transaction Gain (Loss)" and "-- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." MISCELLANEOUS Other Assets The Company and a subsidiary, Pogo Offshore Pipeline Co., own interests in eight pipelines (excluding field gathering pipelines) through which offshore hydrocarbon production is transported. In addition, the Company owns approximately 19% interest in a cryogenic gas processing plant near Erath, Louisiana, which entitles it to process up to 186 MMcf of natural gas and 5,478 Bbls of natural gas liquids per day. The plant is not currently operating at full capacity. See also "-- Arch and its Subsidiaries." In 1989, the Company entered into a limited partnership agreement as general partner of Pogo Gulf Coast, Ltd., a Texas limited partnership ("Pogo Gulf Coast"). As of December 31, 1997, Pogo Gulf Coast had interests in 5 federal offshore leases. The Company owned 40% of any interest in properties acquired by the limited partnership. Unless otherwise noted, the statistical data reported in this offering memorandum reflect only the Company's share of Pogo Gulf Coast's holdings as of March 13, 1998. Effective September 1, 1998, the Company acquired all of the limited partnership interest of Pogo Gulf Coast. Sales The marketing of offshore oil and gas production is subject to the availability of pipelines and other transportation, processing and refining facilities, as well as the existence of adequate markets. As a result, even if hydrocarbons are discovered in commercial quantities, a substantial period of time may elapse before commercial production commences. If pipeline facilities in an area are insufficient, the Company may have to await the construction or expansion of pipeline capacity before production from that area can be marketed. The Company's 52 53 domestic offshore properties are generally located in areas where a pipeline infrastructure is well developed and there is adequate availability in such pipelines to handle the Company's current and projected future production. The Company's Thailand Concession is traversed by two major (34 inches and 36 inches in diameter, respectively) natural gas pipelines that are owned and operated by PTT and which come within approximately 25 miles of the Tantawan Field (and are slightly closer to the Benchamas Field). Thaipo and its joint venture partners in the Tantawan Field signed a long term gas sales contract with PTT in November 1995 which has since been amended to include production from the Benchamas Field. All oil and condensate production from the Tantawan field is initially stored aboard the FPSO and is then sold to various third parties, including PTT, on a tanker load by tanker load basis at prices based on then current world oil prices, typically with reference to the Malaysian Tapis crude oil benchmark price. The buyer is responsible for sending a tanker to off load the oil and condensate it has purchased. It is currently anticipated that crude oil and condensate production from the Benchamas Field, when it commences production, will be initially stored aboard the FSO and sold in the same manner. See "-- International Operations; Contractual Terms Governing the Thailand Concession and Related Production." The marketing of domestic onshore oil and gas production is also subject to the availability of pipelines, crude oil hauling and other transportation, processing and refining facilities as well as the existence of adequate markets. Generally, the Company's onshore domestic oil and gas production is located in areas where commercial production of economic discoveries can be rapidly effectuated. Most of the Company's domestic natural gas sales are currently made in the "spot market" for no more than one month at a time at then currently available prices. Prices on the spot market fluctuate with demand. Crude oil and condensate production is also generally sold one month at a time at the price that is then currently available. Other than any futures contracts which may exist from time to time, and which are referred to in "-- Miscellaneous; Competition and Market Conditions," and the Gas Sales Agreement with PTT for production from the Tantawan and Benchamas Fields (see "-- International Operations; Contractual Terms Governing the Thailand Concession and Related Production"), the Company has no existing contracts that require the delivery of fixed quantities of oil or natural gas other than on a best efforts basis. Enron Corp. and its affiliates and PTT, who purchased $57,965,000 (20% of the Company's consolidated gross revenues) and $30,108,000 (11% of the Company's consolidated gross revenues) of the Company's oil and gas production during 1997, respectively, were the Company's only customers to which sales exceeded 10% of its 1997 revenues. The oil and gas sold to Enron Corp. and its affiliates was sold under a number of short term, generally month to month, contracts. Competition and Market Conditions The Company experiences competition from other oil and gas companies in all phases of its operations, as well as competition from other energy related industries. The Company's profitability and cash flow are highly dependent upon the prices of oil and natural gas, which historically have been seasonal, cyclical and volatile. In general, prices of oil and gas are dependent upon numerous factors beyond the control of the Company, including various weather, economic, political and regulatory conditions. In the past, when natural gas prices in the United States were low, the Company at times elected to curtail certain quantities of its production. In the future, the Company may again elect to curtail certain quantities of its natural gas production. Current oil prices which, on an inflation adjusted basis are at historic lows, continue to have a material adverse effect on the Company's cash flows and, if sustained for a significant length, could have a material adverse effect on the Company's operations and financial condition and may result in a further reduction in funds available under the Company's Credit Agreement. Because it is impossible to predict future oil and gas price movements with any certainty, the Company from time to time enters into contracts on a portion of its production to hedge against the volatility in oil and gas prices. Such hedging transactions, historically, have never exceeded 50% of the Company's total oil and gas production on an energy equivalent basis for any given period. While intended to limit the negative effect of price declines, such transactions could effectively limit the Company's participation in price increases for the covered period, which increases could be significant. As of December 31, 1998, the Company was not a party to any natural gas futures contracts, crude oil swap agreements or other commodity hedging arrangements. When the Company does engage in 53 54 such hedging activities, it may satisfy its obligations with its own production or by the purchase (or sale) of third party production. The Company may also cancel all delivery obligations by offsetting such obligations with equivalent agreements, thereby effecting a purely cash transaction. Operating and Uninsured Risks The Company's operations are subject to risks inherent in the exploration for and production of oil and natural gas, such as blowouts, cratering, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, pollution and other environmental risks. Offshore oil and gas operations are subject to the additional hazards of marine and helicopter operations, such as capsizing, collision and adverse weather and sea conditions. These hazards could result in substantial losses to the Company due to injury or loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations. The Company carries insurance which it believes is in accordance with customary industry practices, but is not fully insured against all risks incident to its business. Drilling activities are subject to numerous risks, including the risk that no commercially productive hydrocarbon reserves will be encountered. The cost of drilling, completing and operating wells and of installing production facilities and pipelines is often uncertain. The Company's drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including title problems, weather conditions, compliance with governmental requirements and shortages or delays in the delivery or availability of material, equipment and fabrication yards. The availability of a ready market for the Company's natural gas production depends on a number of factors, including the demand for and supply of natural gas, the proximity of natural gas reserves to pipelines, the capacity of such pipelines and government regulations. Risks of Foreign Operations Ownership of property interests and production operations in Thailand, and in any other areas outside the United States in which the Company may choose to do business, are subject to the various risks inherent in foreign operations. These risks may include, among other things, currency restrictions and exchange rate fluctuations, loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, insurrection and other political risks, risks of increases in taxes and governmental royalties, renegotiation of contracts with governmental entities, changes in laws and policies governing operations of foreign-based companies and other uncertainties arising out of foreign government sovereignty over the Company's international operations. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Results of Operations; Foreign Currency Transaction Gain (Loss)," and "-- Liquidity and Capital Resources; Other Matters; Southeast Asia Economic Issues." The Company's international operations may also be adversely affected by laws and policies of the United States affecting foreign trade, taxation and investment. In addition, in the event of a dispute arising from foreign operations, the Company may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons to the jurisdiction of the courts of the United States. The Company seeks to manage these risks by concentrating its international exploration efforts in areas where the Company believes that the existing government is stable and favorably disposed towards United States exploration and production companies. EXPLORATION AND PRODUCTION DATA In the following data "gross" refers to the total acres or wells in which the Company has an interest and "net" refers to gross acres or wells multiplied by the percentage working interest owned by the Company. Acreage The following table shows the Company's interest in developed and undeveloped oil and gas acreage as of December 31, 1997: 54 55
DEVELOPED UNDEVELOPED ACREAGE(a) ACREAGE(b) ------------------- --------------------- Gross Net Gross Net ----- --- ----- --- DOMESTIC ONSHORE Louisiana.............................. 2,475 598 36,074 10,895 New Mexico............................. 21,021 12,591 58,410 42,932 Texas.................................. 12,084 4,346 103,100 40,769 Other.................................. 3,200 333 238 55 ------ ------ ------ ------ Total Domestic Onshore......... 38,780 17,868 197,822 94,651 ------ ------ ------- ------ DOMESTIC OFFSHORE Louisiana (State)...................... 7,942 3,255 1,508 753 Louisiana (Federal)(c)................. 186,422 61,378 152,879 56,061 Texas (Federal)........................ 40,320 10,251 56,905 16,530 ------ ------ ------ ------ Total Domestic Offshore........ 234,684 74,854 211,292 73,344 ------- ------ ------- ------ Total Domestic................. 273,464 92,722 409,114 167,995 ------- ------ ------- ------- INTERNATIONAL Kingdom of Thailand.................... 260,407 120,682 473,733 219,530 ------- ------- ------- ------- Total Company.................. 533,871 213,404 882,847 387,525 ======= ======= ======= =======
- ----------------- (a) "Developed acreage" consists of lease acres spaced or assignable to production (including acreage held by production) on which wells have been drilled or completed to a point that would permit production of commercial quantities of oil or natural gas. "Developed acreage" in Thailand includes all acreage designated as production area by the Thai government, which currently includes the Tantawan, Maliwan, Benchamas and Pakakrong production areas. (b) "Undeveloped acreage" includes acreage under lease or subject to lease or purchase options that the Company currently expects to exercise. Less than 1% of the Company's total domestic offshore net undeveloped acreage is under leases that have terms expiring in 1998 (unless otherwise extended) and another approximately 1% of total domestic offshore net undeveloped acreage will expire in 1999 (unless otherwise extended). Approximately 7% of the Company's total domestic onshore net undeveloped acreage is under leases that have terms expiring in 1998 (unless otherwise extended) and another approximately 15% of total domestic onshore net undeveloped acreage will expire in 1999 (unless otherwise extended). The Company's total international net undeveloped acreage must be relinquished to the Thai government on July 31, 2000, unless designated as a production area or unless the exploration term is extended. See "--International Operations; Contractual Terms Governing the Thailand Concession and Related Production." (c) The Company also owns overriding royalty interests in one federal lease offshore Louisiana totaling 5,000 gross acres (1,250 net acres). Productive Wells and Drilling Activity The following table shows the Company's interest in productive oil and natural gas wells as of December 31, 1997. For purposes of this table "productive wells" are defined as wells producing hydrocarbons and wells "capable of production" (e.g., natural gas wells waiting for pipeline connections or necessary governmental certification to commence deliveries and oil wells waiting to be connected to currently installed production facilities). This table does not include exploratory or developmental wells which have located commercial quantities of oil or natural gas but which are not capable of commercial production without the installation of material production facilities or which, for a variety of reasons, the Company does not currently believe will be placed on production. 55 56
NATURAL GAS OIL WELLS(a) WELLS(a) ------------------ ---------------- GROSS NET GROSS NET ----- --- ----- --- Offshore United States......................... 129 33.3 113 33.8 Onshore United States.......................... 339 214.4 91 33.1 Kingdom of Thailand............................ -- -- 34 15.8 --- ----- --- ---- Total................................ 468 247.7 238 82.7 === ===== === ====
- ------------------- (a) One or more completions in the same bore hole are counted as one well. The data in the above table includes five gross (.6 net) oil wells and 45 gross (20.4 net) natural gas wells with multiple completions. The following table shows the number of successful gross and net exploratory and development wells in which the Company has participated and the number of gross and net wells abandoned as dry holes during the periods indicated. An onshore well is considered successful upon the installation of permanent equipment for the production of hydrocarbons or when electric logs run to evaluate such wells indicate the presence of commercial hydrocarbons and the Company currently intends to complete such wells. Successful offshore wells consist of exploratory or development wells that have been completed or are "suspended" pending completion (which has been determined to be feasible and economic) and exploratory test wells that were not intended to be completed and that encountered commercially producible hydrocarbons. A well is considered a dry hole upon reporting of permanent abandonment to the appropriate agency.
1997 1996 1995 ------------------ ---------------- ----------------- SUCCESSFUL DRY SUCCESSFUL DRY SUCCESSFUL DRY ---------- --- ---------- --- ---------- --- Gross Wells: Offshore United States Exploratory....................... 4.0 1.0 4.0 2.0 7.0 4.0 Development....................... 12.0 3.0 17.0 3.0 3.0 1.0 Onshore United States Exploratory....................... 18.0 12.0 12.0 4.0 8.0 1.0 Development....................... 50.0 3.0 39.0 1.0 47.0 1.0 Offshore Kingdom of Thailand Exploratory....................... 18.0 1.0 7.0 -- 3.0 -- Development....................... 12.0 -- 16.0 -- 7.0 -- ----- ----- ---- ---- ---- ---- Total........................ 114.0 20.0 95.0 10.0 75.0 7.0 ===== ===== ==== ==== ==== ==== NET WELLS: Offshore United States Exploratory....................... 1.21 .25 1.7 1.5 3.0 1.6 Development....................... 4.15 1.05 4.9 1.5 1.0 0.4 Onshore United States Exploratory....................... 11.27 7.40 6.5 0.9 4.6 1.0 Development....................... 30.18 1.41 24.4 0.7 31.3 0.1 Onshore Kingdom of Thailand Exploratory....................... 8.34 .46 2.4 -- 1.1 -- Development....................... 5.11 -- 7.4 -- 3.2 -- ----- ----- --- ---- ---- --- Total........................ 60.26 10.57 47.3 4.6 44.2 3.1 ===== ===== ==== ==== ==== ===
As of December 31, 1997, the Company was participating in the drilling of 3 gross (1.1 net) offshore domestic wells, 6 gross (4.2 net) onshore wells and 1 gross (0.5 net) wells offshore the Kingdom of Thailand. 56 57 Production and Sales The following table summarizes the Company's average daily production, net of all royalties, overriding royalties and other outstanding interests, for the periods indicated. Natural gas production refers only to marketable production of natural gas on an "as sold" basis.
1997 1996 1995 ------- ------- ------- Located in the United States Natural Gas (Mcf per day)................................... 147,200 107,700 121,000 ======= ======= ======= Liquid Hydrocarbons (Bbls per day) Crude Oil and Condensate................................. 13,712 11,968 11,786 Natural Gas Liquids(a)................................... 2,923 2,173 1,998 ------- ------- ------- Total Domestic Liquid Hydrocarbons.................. 16,635 14,141 13,784 ======= ======= ======= Located in the Kingdom of Thailand Natural Gas (Mcf per day)................................... 37,700 -- -- ======= ======= ======= Liquid Hydrocarbons (Bbls per day) Crude Oil and Condensate................................. 2,421 -- -- ======= ======= =======
- ------------------- (a) NGL production sales includes sales attributable to both the Company's leasehold and plant ownership. The following table shows the average sales prices received by the Company for its production and the average production (lifting) costs per unit of production during the periods indicated. See "-- Miscellaneous; Competition" and "-- Miscellaneous; Market Conditions and Sales."
1997 1996 1995 ------- -------- -------- SALES PRICES: Located in the United States Natural Gas (per Mcf).................................. $ 2.50 $ 2.40 $ 1.63 Crude Oil and Condensate (per Bbl)..................... $ 19.49 $ 22.12 $ 17.80 Natural Gas Liquids (per Bbl).......................... $ 12.89 $ 14.92 $ 11.10 Located in the Kingdom of Thailand Natural Gas (per Mcf).................................. $ 1.93 -- -- Crude Oil and Condensate (per Bbl).......................... $ 18.60 -- -- PRODUCTION (LIFTING) COSTS(a): Located in the United States Natural Gas, Crude Oil, Condensate and Natural Gas Liquids (per Mcf equivalent)...................... $ .49 $ .53 $ .47 Located in the Kingdom of Thailand Natural Gas, Crude Oil and Condensate (per Mcf equivalent)(b)........................................ $ 1.12 -- --
- -------------------- (a) Production costs were converted to common units of measure on the basis of relative energy content. Such production costs exclude all depletion and amortization associated with property and equipment. (b) The major contributing factor to lifting costs are lease operating expenses. A substantial portion of the Company's lease operating expenses in the Kingdom of Thailand relate to lease payments made by a subsidiary of the Company in connection with its bareboat charter of the FPSO, which amounted to $10,200,000 during 1997. See "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources; Future Capital Requirements; Other Material Long-Term Commitments." 57 58 Reserves The following table sets forth information as to the Company's net proved and proved developed reserves as of December 31, 1997, 1996, and 1995, and the present value as of such dates (based on an annual discount rate of 10%) of the estimated future net revenues from the production and sale of those reserves, as estimated by Ryder Scott in accordance with criteria prescribed by the SEC.
AS OF DECEMBER 31, ----------------------------------- 1997 1996 1995 -------- -------- ------- TOTAL PROVED RESERVES(a): Oil, condensate, and natural gas liquids (MBbls) Located in the United States............................ 29,382 28,270 26,185 Located in the Kingdom of Thailand...................... 28,783 21,332 18,997 -------- -------- -------- Total Company...................................... 58,165 49,602 45,182 ======== ======== ======== Natural Gas (MMcf) Located in the United States............................ 216,720 215,946 196,454 Located in the Kingdom of Thailand...................... 184,768 144,998 131,607 -------- -------- -------- Total Company...................................... 401,488 360,944 328,061 ======== ======== ======== Present value of estimated future net revenues, before income taxes (in thousands)(b) Located in the United States............................ $406,161 $773,127 $400,845 Located in the Kingdom of Thailand...................... 56,620 181,418 131,630 -------- -------- -------- Total Company...................................... $462,781 $954,545 $532,745 ======== ======== ======== TOTAL DEVELOPED RESERVES(a): Oil, condensate, and natural gas liquids (MBbls) Located in the United States............................ 26,168 25,898 22,488 Located in the Kingdom of Thailand...................... 6,982 5,192 -- -------- -------- -------- Total Company...................................... 33,150 31,090 22,488 ======== ======== ======== Natural Gas (MMcf) Located in the United States............................ 179,972 192,034 164,679 Located in the Kingdom of Thailand...................... 59,760 45,998 -- -------- -------- -------- Total Company...................................... 239,732 238,032 164,679 ======== ======== ======== Present value of estimated future net revenues, before income taxes (in thousands)(b) Located in the United States............................ $377,530 $710,871 $359,984 Located in the Kingdom of Thailand...................... 36,692 69,062 -- -------- -------- -------- Total Company...................................... $414,222 $779,933 $359,984 ======== ======== ========
- ------------------------ (a) Gives no effect to the Company's acquisition of Arch in August 1998. See "-- Arch and its Subsidiaries; Oil and Gas Reserves." (b) The Company believes, for the reasons set forth in succeeding paragraphs, that the present value of estimated future net revenues set forth in the Annual Report and calculated in accordance with SEC guidelines are not necessarily indicative of the true present value of the Company's reserves and, due to the fact that essentially all of the Company's domestic natural gas production is currently sold on the spot market, whereas all of the Company's Thai natural gas production is sold pursuant to a long term gas sales contract, such estimates of future net revenues from the Company's domestic and Thai reserves are, accordingly, not useful for comparative purposes. See the discussion on the following pages for the prices used in making these calculations. Natural gas liquids comprised approximately 7% of the Company's total proved liquids reserves and approximately 11% of the Company's proved developed liquids reserves as of December 31, 1997. All hydrocarbon liquid reserves are expressed in standard 42 gallon Bbls. All gas volumes and gas sales are expressed in MMcf at the pressure and temperature bases of the area where the gas reserves are located. Proved reserves of crude oil, condensate, natural gas, and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions. Reservoirs are considered proved if economic producibility is supported by 58 59 actual production or formation tests. In certain instances, proved reserves are assigned on the basis of a combination of core analysis and electrical and other type logs which indicate the reservoirs are analogous to reservoirs in the same field which are producing or have demonstrated the ability to produce on a formation test. The area of a reservoir considered proved includes (i) that portion delineated by drilling and defined by fluid contacts, if any, and (ii) the adjoining portions not yet drilled that can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of data on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir. Proved reserves are estimates of hydrocarbons to be recovered from a given date forward. They may be revised as hydrocarbons are produced and additional data becomes available. Proved natural gas reserves are comprised of non-associated, associated and dissolved gas. An appropriate reduction in gas reserves has been made for the expected removal of liquids, for lease and plant fuel and the exclusion of non-hydrocarbon gases if they occur in significant quantities and are removed prior to sale. Reserves that can be produced economically through the application of established improved recovery techniques are included in the proved classification when these qualifications are met: (i) successful testing by a pilot project or the operation of an installed program in the reservoir provides support for the engineering analysis on which the project or program was based, and (ii) it is reasonably certain the project will proceed. Improved recovery includes all methods for supplementing natural reservoir forces and energy, or otherwise increasing ultimate recovery from a reservoir, including, (i) pressure maintenance, (ii) cycling, and (iii) secondary recovery in its original sense. Improved recovery also includes the enhanced recovery methods of thermal, chemical flooding, and the use of miscible and immiscible displacement fluids. Estimates of proved reserves do not include crude oil, condensate, natural gas, or natural gas liquids being held in underground storage. Depending on the status of development, these proved reserves are further subdivided into: (i) "developed reserves" which are those proved reserves reasonably expected to be recovered through existing wells with existing equipment and operating methods, including (a) "developed producing reserves" which are those proved developed reserves reasonably expected to be produced from existing completion intervals now open for production in existing wells, and (b) "developed non-producing reserves" which are those proved developed reserves which exist behind casing of existing wells which are reasonably expected to be produced through these wells in the predictable future where the cost of making such hydrocarbons available for production should be relatively small compared to the cost of new wells; and (ii) "undeveloped reserves" which are those proved reserves reasonably expected to be recovered from new wells on undrilled acreage, from existing wells where a relatively large expenditure is required and from acreage for which an application of fluid injection or other improved recovery technique is contemplated where the technique has been proved effective by actual tests in the area in the same reservoir. Reserves from undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are included only where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation. In computing future revenues from gas reserves attributable to the Company's domestic interests, prices in effect at December 31, 1997 were used, including current market prices, contract prices and fixed and determinable price escalations where applicable. In accordance with SEC guidelines, the gas prices that were used make no allowances for seasonal variations in gas prices which are likely to cause future yearly average gas prices to be somewhat lower than December gas prices. For domestic gas sold under contract, the contract gas price including fixed and determinable escalations, exclusive of inflation adjustments, was used until the contract expires and then was adjusted to the current market price for the area and held at this adjusted price to depletion of the reserves. In computing future revenues from liquids attributable to the Company's domestic interests, prices in effect at December 31, 1997 were used and these prices were held constant to depletion of the properties. The future revenues are adjusted to reflect the Company's net revenue interest in these reserves as well as any ad valorem and other severance taxes but do not include, unless otherwise noted, any provisions for corporate income taxes. 59 60 In computing future revenues from the Company's gas reserves attributable to the Company's interests in the Kingdom of Thailand, the current contract price under the Gas Sales Agreement was used, without giving effect to any of the adjustments provided for in the Gas Sales Agreement, due to their indeterminate nature as of December 31, 1997, in accordance with SEC guidelines. In computing future revenues from liquids attributable to the Company's interests in the Kingdom of Thailand, a price was used which the Company believes approximates the price that the Company would have received for its production from the Thailand Concession based upon the world market price for Tapis benchmark crude on December 31, 1997, and this price was held constant until depletion of the Company's reserves in the Kingdom of Thailand. The future revenues are adjusted to reflect the Company's net revenue interest in these reserves and the Company's obligations under the Thailand Concession, including the payment of SRB and applicable production bonuses, but does not include, unless otherwise noted, any provisions for U.S. or Thai corporate income or other taxes. In accordance with SEC guidelines, the prices used by the Company to calculate the present value of estimated future revenues are determined on a well or field by field basis, as applicable, as described above and were held constant over the productive life of the reserves. The initial weighted average prices used by Ryder Scott were as follows:
AS OF DECEMBER 31, ------------------------------- 1997 1996 1995 ------ ------ ------ INITIAL WEIGHTED AVERAGE PRICE (in U.S. dollars): Oil, condensate, and natural gas liquids (per Bbl) Located in the United States............................ $16.60 $24.06 $19.10 Located in the Kingdom of Thailand...................... $16.00 $24.56 $18.71 Natural Gas (per Mcf) Located in the United States............................ $ 2.30 $ 3.93 $ 2.08 Located in the Kingdom of Thailand...................... $ 1.83 $ 2.09 $ 2.02
The estimates of future net revenue from the Company's domestic and Thailand properties are based on existing law where the properties are located and are calculated in accordance with SEC guidelines. Operating costs for the leases and wells include only those costs directly applicable to the leases or wells. When applicable, the operating costs include a portion of general and administrative costs allocated directly to the leases and wells under terms of operating agreements. Development costs are based on authorization for expenditure for the proposed work or actual costs for similar projects. The current operating and development costs were held constant throughout the life of the properties. For properties located onshore, the estimates of future net revenues and the present value thereof do not consider the salvage value of the lease equipment or the abandonment cost of the lease since both are relatively insignificant and tend to offset each other. The estimated net cost of abandonment after salvage was considered for offshore properties where such costs net of salvage are significant. No deduction was made for indirect costs such as general and administrative and overhead expenses, loan repayments, interest expenses, and exploration and development prepayments. Accumulated gas production imbalances, if any, have been taken into account. Production data used to arrive at the estimates set forth above includes estimated production for the last few months of 1997. The future production rates from reservoirs now on production may be more or less than estimated because of, among other reasons, mechanical breakdowns and changes in market demand or allocable set by regulatory bodies. Properties which are not currently producing may start producing earlier or later than anticipated in the estimates of future production rates. The future prices received by the Company for the sales of its production may be higher or lower than the prices used in calculating the estimates of future net revenues and the present value thereof as set forth herein, and the operating costs and other costs relating to such production may also increase or decrease from existing levels; however, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in arriving at such estimates. See "Risk Factors -- Volatility of oil and gas markets affects us" and "-- Miscellaneous; Competition and Market Conditions." 60 61 There are numerous uncertainties in estimating the quantity of proved reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers might differ materially from those of Ryder Scott, the Company's reserve engineers. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate, which revisions may be material. Accordingly, reserve estimates are often different from the quantities of oil and gas that are ultimately recovered. The Company is periodically required to file estimates of its oil and gas reserve data with various U.S. governmental regulatory authorities and agencies, including the Federal Energy Regulatory Commission ("FERC") and the Federal Trade Commission; with respect to reserves located in Canada, with the Alberta Energy Utilities Board and, with respect to reserves located in Thailand, the Kingdom of Thailand's Department of Mineral Resources and PTT, which the Company considers a quasi-governmental authority. In addition, estimates are from time to time furnished to governmental agencies in connection with specific matters pending before such agencies. The basis for reporting reserves to these agencies, in some cases, is not comparable to that furnished by Ryder Scott in accordance with SEC guidelines because of the nature of the various reports required. The major differences generally include differences in the time as of which such estimates are made, differences in the definition of reserves, requirements to report in some instances on a gross, net or total operator basis and requirements to report in terms of smaller geographical units. During 1997, no estimates by the Company of its total proved net oil and gas reserves were filed with or included in reports to any governmental authority or agency other than the SEC and, with respect to reserves relating to the Company's properties located in Thailand, the Kingdom of Thailand's Department of Mineral Resources and PTT. GOVERNMENT REGULATION The Company's operations are affected from time to time in varying degrees by political developments and governmental laws and regulations. Rates of production of oil and gas have for many years been subject to governmental conservation laws and regulations, and the petroleum industry has been subject to federal and state tax laws dealing specifically with it. Federal Income Tax The Company's operations are significantly affected by certain provisions of the federal income tax laws applicable to the petroleum industry. The principal provisions affecting the Company are those that permit the Company, subject to certain limitations, to deduct as incurred, rather than to capitalize and amortize, its domestic "intangible drilling and development costs" and to claim depletion on a portion of its domestic oil and gas properties based on 15% of its oil and gas gross income from such properties (up to an aggregate of 1,000 Bbls per day of domestic crude oil and/or equivalent units of domestic natural gas) even though the Company has little or no basis in such properties. Under certain circumstances, however, a portion of such intangible drilling and development costs and the percentage depletion allowed in excess of basis will be tax preference items that will be taken into account in computing the Company's alternative minimum tax. Environmental Matters Domestic oil and gas operations are subject to extensive federal regulation and, with respect to federal leases, to interruption or termination by governmental authorities on account of environmental and other considerations including the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") also known as the "Superfund Law." The recent trend towards stricter standards in environmental legislation and regulation may continue, and this could increase costs to the Company and others in the industry. Oil and gas lessees are subject to liability for the costs of clean-up of pollution resulting from a lessee's operations, and may also be subject to liability for pollution damages. The Company maintains insurance against costs of clean-up operations, but is not fully insured against all such risks. A serious incident of pollution may, as it has in the past, 61 62 also result in the Department of the Interior requiring lessees under federal leases to suspend or cease operation in the affected area. The operators of the Company's properties have numerous applications pending before the Environmental Protection Agency (the "EPA") for National Pollution Discharge Elimination System water discharge permits with respect to offshore drilling and production operations. The issue generally involved is whether effluent discharges from each facility or installation comply with the applicable federal regulations. The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder impose a variety of regulations on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills in United States waters. A "responsible party" includes the owner or operator of a facility or vessel, or the lessee or permittee of the area in which an offshore facility is located. The OPA assigns liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party fails to report a spill or cooperate fully in the cleanup, liability limits likewise do not apply. Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on responsible parties, including proof of financial responsibility to cover at least some costs in a potential spill. For tank vessels, including mobile offshore drilling rigs, the OPA imposes on owners, operators and charterers of the vessels, an obligation to maintain evidence of financial responsibility of up to $10,000,000 depending on gross tonnage. With respect to offshore facilities, proof of greater levels of financial responsibility may be applicable. For offshore facilities that have a worst case oil spill potential of more than 1,000 Bbls (which includes many of the Company's offshore producing facilities), certain amendments to the OPA that were enacted in 1996 provide that the amount of financial responsibility that must be demonstrated for most facilities ranges from $10,000,000 to $35,000,000, depending upon location, with higher amounts, up to $150,000,000 in certain limited circumstances. The Company believes that it currently has established adequate proof of financial responsibility for its offshore facilities at no significant increase in expense over recent prior years. However, the Company cannot predict whether these financial responsibility requirements under the OPA amendments will result in the imposition of substantial additional annual costs to the Company in the future or otherwise materially adversely effect the Company. The impact, however, should not be any more adverse to the Company than it will be to other similarly situated or less capitalized owners or operators in the Gulf of Mexico. The Company's onshore operations are subject to numerous United States federal, state, and local laws and regulations controlling the discharge of materials into the environment or otherwise relating to the protection of the environment including CERCLA. Such laws and regulations, among other things, impose absolute liability on the lessee under a lease for the cost of clean-up of pollution resulting from a lessee's operations, subject the lessee to liability for pollution damages, may require suspension or cessation of operations in affected areas, and impose restrictions on the injection of liquids into subsurface aquifers that may contaminate groundwater. Such laws could have a significant impact on the operating costs of the Company, as well as the oil and gas industry in general. Federal, state and local initiatives to further regulate the disposal of oil and gas wastes are also pending in certain states, and these initiatives could have a similar impact on the Company. The Company is asked to comment on the costs it incurred during the prior year on capital expenditures for environmental control facilities and the amount it anticipates incurring during the coming year. The Company believes that, in the course of conducting its oil and gas operations, many of the costs attributable to environmental control facilities would have been incurred absent environmental regulations as prudent, safe oilfield practice. During 1997, the Company incurred capital expenditures of approximately $610,000 for environmental control facilities, primarily relating to the installation of certain environmental control facilities on two platforms installed in the Gulf of Thailand. The Company budgeted approximately $1,630,000 for expenditures involving environmental control facilities during 1998, including, among other things, two salt water disposal facilities in New Mexico and 62 63 environmental control equipment for three platforms in the Gulf of Thailand and two platforms in the Gulf of Mexico. Other Laws and Regulations Various laws and regulations often require permits for drilling wells and also cover spacing of wells, the prevention of waste of oil and gas including maintenance of certain gas/oil ratios, rates of production and other matters. The effect of these laws and regulations, as well as other regulations that could be promulgated by the jurisdictions in which the Company has production, could be to limit the number of wells that could be drilled on the Company's properties and to limit the allowable production from the successful wells completed on the Company's properties, thereby limiting the Company's revenues. The Minerals Management Service of the Department of the Interior (the "MMS") administers the oil and gas leases held by the Company on federal onshore lands and offshore tracts in the Outer Continental Shelf. The MMS holds a royalty interest in these federal leases on behalf of the federal government. While the royalty interest percentage is fixed at the time that the lease is entered into, from time to time the MMS changes or reinterprets the applicable regulations governing its royalty interests, and such action can indirectly affect the actual royalty obligation that the Company is required to pay. In a letter dated May 3, 1993, the MMS announced a reinterpretation of its right to collect royalty payments from producers on certain settlements in which such producers and pipeline companies were involved a number of years ago. The MMS reinterpretation has been challenged in court by various producers and trade groups representing them. On August 27, 1996, in Independent Petroleum Association of America, et al. v. Babbit et al., Nos. 95-5210 etc., the United States Court of Appeals for the District of Columbia Circuit held that the May 3, 1993, reinterpretation was invalid and unenforceable. Unless and until this or other similar cases are resolved in favor of the MMS' reinterpretation of its regulations, it is unlikely that the Company or other producers will be legally required to pay royalties on such settlement agreements. The Company was involved in several settlement agreements with pipelines that could be subject to the MMS' new reinterpretation. The MMS has reviewed the Company's and other producers' settlement agreements, to determine whether it believes any additional royalty payments may be due and has asserted that additional royalties may be due in connection with two of the Company's settlement agreements. Based upon existing case law, the Company has asserted through the administrative appeals process, and continues to believe, that it does not owe any additional royalties beyond what it has previously paid. However, in the event that the MMS is able to successfully assert that additional royalty is due from the Company in connection with settlement agreements to which the Company is a party, the Company does not currently believe that such additional assessment will have a material adverse impact on the financial position or results of operations of the Company. Recently the MMS and various state and municipal authorities have attempted to collect alleged underpayment of royalties from various integrated oil companies in connection with sale transactions between exploration and production affiliates and pipeline affiliates of the same company. The Company has not been named in any of these collection efforts, a fact that the Company believes is primarily due to its never having sold any oil or gas production from one of its affiliates to another. The Company does not believe that it has any material liability for underpayment of royalty in connection with affiliate transactions, including those described above. The FERC has recently embarked on regulatory initiatives relating to its jurisdiction over rates for natural gas gathering services provided by interstate pipelines and to the availability of market-based and other alternative rate mechanisms to such pipelines for transmission and storage services. Among the FERC initiatives is the creation of a pilot program to determine the effect on rates of lifting price caps on the rates for interruptible transportation, short-term firm transportation, and for transportation using capacity released by the firm transportation customers of interstate pipelines. In addition, the FERC has announced and implemented a policy allowing pipelines and transportation customers to negotiate rates above the otherwise applicable maximum lawful cost-based rates on the condition that the pipelines alternatively offer so-called recourse rates equal to the maximum lawful cost-based rates. This negotiated/recourse rate policy has been challenged in the United States Court of Appeals for the District of Columbia, and the appeal remains pending. With respect to gathering services, the FERC has issued orders declaring that certain facilities owned by interstate pipelines primarily perform a gathering function, and may be transferred to 63 64 affiliated and non-affiliated entities that are not subject to the FERC's rate jurisdiction. These orders have been generally upheld on appeal to the courts. The Company cannot predict the ultimate outcome of these developments, nor the effect of these developments on transportation rates. Inasmuch as the rates for these pipeline services can affect the gas prices received by the Company for the sale of its production, the FERC's actions may have an impact on the Company. However, the impact should not be substantially different on the Company than it will on other similarly situated gas producers and sellers. EMPLOYEES As of December 31, 1998, the Company and its subsidiaries had 185 full-time employees, including 24 in its Bangkok, Thailand office and seven in its Calgary, Canada office. None of the Company's employees are presently represented by a union for collective bargaining purposes. The Company considers its relations with its employees to be excellent. ARCH AND ITS SUBSIDIARIES Overview Arch and its subsidiaries primarily engage in oil and natural gas exploration, development, production, transportation and marketing in the Southwestern United States and Western Canada. Arch and its subsidiaries are also active in the acquisition of interests in both producing and non-producing oil and gas leases. Arch was acquired by the Company in a stock-for-stock tax-free merger accounted for as a purchase. In connection with the merger, the Company paid off $36,500,000 of Arch's existing bank debt and a $15,246,000 production payment obligation (the "VPP") utilizing funds under its Credit Agreement. The Company also exchanged $5,000,000 of Arch's existing convertible subordinated notes, 777,273 shares of Arch preferred stock (having a liquidation preference of $20,000,000) and 17,321,804 shares of Arch common stock for approximately 2,540,000 shares of Common Stock. As of January 1, 1999, Pogo Canada Ltd. (formerly known as Arch Petroleum Ltd. ("APL")), Saginaw Pipeline Company, L.C. ("Saginaw") and its subsidiary Industrial Natural Gas, L.C. ("ING") were the only subsidiaries of Arch. All of the Company's and Arch's operations in Canada are conducted by Pogo Canada Ltd. Saginaw owns a six inch pipeline that extends approximately 100 miles from Wichita Falls, Texas to Saginaw, Texas. ING, a subsidiary of Saginaw, markets the sale and transmission of natural gas through the Saginaw pipeline. Oil and Gas Reserves The following table sets forth a summary of Arch's oil and gas reserve quantities and present value of future net cash flows associated therewith at the dates indicated. All domestic oil and gas reserves were estimated by Ryder Scott, independent petroleum engineers, and are detailed in a report prepared for the exclusive use of Arch. Oil and gas reserves for APL were estimated by Ryder Scott and Sproule Associates Limited, both independent petroleum engineers in Canada in 1997 and 1996, respectively. All such estimations were made in accordance with regulations promulgated by the SEC. Such reserve reports are available for examination at Arch's corporate headquarters in Houston, Texas.
UNITED STATES CANADA TOTAL -------------- ------------ ------------- Present value of discounted future net cash flows before income taxes: December 31, 1997............................... $ 60,289,500 $ 8,422,300 $ 68,711,800 December 31, 1996............................... 101,701,100 11,775,700 113,476,800 December 31, 1995............................... 64,296,200 -- 64,296,200 Proved developed and undeveloped reserves: Oil (Bbls) December 31, 1997............................... 5,060,500 812,900 5,873,400 December 31, 1996............................... 3,861,000 856,900 4,717,900
64 65
December 31, 1995............................... 4,030,200 -- 4,030,200 Gas (Mcf) December 31, 1997............................... 68,430,700 6,575,000 75,005,700 December 31, 1996............................... 59,120,900 1,136,000 60,256,900 December 31, 1995............................... 61,286,300 -- 61,286,300 Proved developed reserves: Oil (Bbls) December 31, 1997............................... 4,475,600 693,800 5,169,400 December 31, 1996............................... 3,128,400 809,900 3,938,300 December 31, 1995............................... 2,993,600 -- 2,993,600 Gas (Mcf) December 31, 1997............................... 65,324,800 6,489,000 71,813,800 December 31, 1996............................... 54,981,200 504,000 55,485,200 December 31, 1995............................... 55,628,500 -- 55,628,500
The United States figures above exclude 1.9 Bcf, 8.7 Bcf and 11.9 Bcf of proved gas reserves and $436,400, $2,960,600 and $11,672,700 of discounted future net cash flows (after operating expenses and severance taxes) at December 31, 1997, 1996 and 1995, respectively, which were sold to Enron Corp. in the VPP. See "-- Exploration and Production Data; Reserves" for key factors and additional information related to Arch's reserve estimates. Leases and Wells Owned At December 31, 1997, Arch owned interests in the following acreage.
UNITED STATES CANADA TOTAL ------------- ------- ------- Developed acres: Gross........................................... 67,017 35,223 102,240 Net............................................. 16,950 3,810 20,760 Undeveloped acres: Gross........................................... 74,435 106,705 181,140 Net............................................. 23,452 51,777 75,229
As of December 31, 1997, Arch's interests in wells owned were as follows:
TOTAL UNITED STATES CANADA ----------------- ----------------- ----------------- Gross Net Gross Net Gross Net TYPE Wells Wells Wells Wells Wells Wells - ------ ----- ----- ----- ----- ----- ----- Oil ...... 1,209 363.7 1,076 344.8 133 18.9 Gas ...... 134 62.8 131 62.2 3 0.6 ----- ----- ----- ----- --- ---- 1,343 426.5 1,207 407.0 136 19.5 ===== ===== ===== ===== === ====
65 66 MANAGEMENT AND BOARD OF DIRECTORS EXECUTIVE OFFICERS Executive officers of the Company are appointed annually to serve for the ensuing year or until their successors have been elected or appointed. The executive officers of the Company, their age as of December 31, 1998, and the year each was elected to his present position are as follows:
YEAR EXECUTIVE OFFICER EXECUTIVE OFFICE AGE ELECTED - ------------------------ ----------------------------------------------- --- ------- Paul G. Van Wagenen Chairman of the Board, President and Chief 52 1991 Executive Officer Stuart P. Burbach Executive Vice President-- Exploration 46 1998 Kenneth R. Good Executive Vice President 61 1998 Jerry A. Cooper Senior Vice President and Western Division 50 1998 Manager R. Phillip Laney Senior Vice President and Manager of Worldwide 58 1998 New Ventures John O. McCoy, Jr. Senior Vice President and Chief Administrative 47 1998 Officer J. D. McGregor Senior Vice President-- Sales 54 1998 Bruce E. Archinal Vice President and Onshore Division Manager 46 1997 David R. Beathard Vice President-- Engineering 40 1997 Stephen R. Brunner Vice President-- Operations 40 1997 Frank Davis III Vice President-- Land 52 1997 John W. Elsenhans Vice President and Chief Financial Officer 46 1998 Thomas E. Hart Vice President and Controller 56 1988 Ronald B. Manning Vice President and General Counsel 45 1995 Gerald A. Morton Vice President-- Law and Corporate 40 1997 Secretary
Prior to assuming their present positions with the Company, the business experience of each executive officer for more than the last five years was as follows: Mr. Van Wagenen, who joined the Company in 1979, served as President and Chief Operating Officer of the Company since 1990; Mr. Burbach served as Vice President and Offshore Division Manager since rejoining the Company in 1991; Mr. Good, who joined the Company in 1977, served as Corporate Senior Vice President of the Company since 1996 and prior thereto served as the Company's Senior Vice President -- Land and Budgets since 1991; Mr. Cooper, who joined the Company in 1979, served as Vice President and Western Division Manager for the Company since 1991; Mr. Laney, who joined the Company in 1977, served as Vice President and International Exploration Manager for the Company since 1991; Mr. McCoy, who joined the Company in 1978, served as Vice President and Chief Administrative Officer of the Company since 1989; Mr. McGregor, who joined the Company in 1981, served as Vice President -- Sales since 1988; Mr. Archinal, who joined the Company in 1982, served as the Company's Onshore Division Manager since 1994 and prior thereto served as Offshore Division Exploration Manager for the Company since 1991; Mr. Beathard, who joined the Company in 1982, served as Manager of Petroleum Engineering for the Company since 1991; Mr. Brunner served as Resident Manager of the Company's Thailand operations since 1995, prior to which he was an Operations Manager for the Company since joining in 1994 and prior thereto held various positions in the energy industry, the most recent of which was as Operations Manager for Zilkha Energy since 1991; Mr. Davis, who joined the Company in 1978, served as Land Manager for the Company since 1991; Mr. Elsenhans, who joined the Company in 1991, served as Vice President -- Finance and Treasurer for the Company since 1995, and prior thereto was Director, Corporate Finance for the Company since 1991; Mr. Hart was Controller for the Company since joining the Company in 1977; Mr. Manning, who joined the Company in 1987, was Corporate Secretary and an Associate General Counsel for the Company since 1990; and Mr. Morton was an Associate General Counsel for the Company since 1993. 66 67 BOARD OF DIRECTORS The following is a list of the members of the Company's Board of Directors and their principal occupations.
NAME PRINCIPAL OCCUPATION - ---- -------------------- Paul G. Van Wagenen.............................. Chairman of the Board, President and Chief Executive Officer of the Company Jerry M. Armstrong*.............................. Rancher Tobin Armstrong*................................. Rancher Jack S. Blanton.................................. President, Eddy Refining Company; Chairman, Houston Endowment, Inc. W. M. Brumley, Jr................................ Personal Investments John B. Carter, Jr............................... Director, Sterling Bancshares William L. Fisher................................ Barrow Chair and Geological Sciences Professor University of Texas at Austin Gerrit W. Gong................................... Freeman Chair and Director of Asian Studies, Center for Strategic and International Studies J. Stuart Hunt................................... Personal Investments Frederick A. Klingenstein........................ Chairman of the Board, Klingenstein, Fields & Co., L.P. Jack A. Vickers.................................. Chairman of the Board, The Vickers Companies
- ---------- * Jerry M. Armstrong and Tobin Armstrong are not related to each other. 67 68 THE EXCHANGE OFFER PURPOSE AND EFFECT OF THE EXCHANGE OFFER The Company entered into a Registration Rights Agreement with the initial purchasers of the outstanding notes in which the Company agreed to file a registration statement relating to an offer to exchange the outstanding notes for new notes. The Company also agreed to use its reasonable best efforts to complete that offer within 180 days after January 15, 1999. The Company is offering the new notes under this prospectus to satisfy those obligations under the Registration Rights Agreement. Under limited circumstances, the Company will use its reasonable best efforts to cause the SEC to declare effective a shelf registration statement with respect to the resale of the outstanding notes and keep the shelf registration statement effective for up to two years after the effective date of the shelf registration statement. These circumstances include: o if any changes in law or applicable interpretations by the staff of the SEC do not permit the Company to effect the exchange offer as contemplated by the Registration Rights Agreement o if the exchange offer is not consummated within 180 days after January 15, 1999 o if any initial purchaser of the outstanding notes so requests, in certain circumstances If the Company fails to comply with deadlines for registering the issuance of the new notes and completion of the exchange offer, it will be required to pay additional interest to holders of the outstanding notes. Please read the section captioned "Outstanding Notes Registration Rights Agreement" for more details regarding the Registration Rights Agreement. To exchange an outstanding note for transferable new notes in the exchange offer, the holder of that outstanding note will be required to make the following representations: o any new note the holder receives will be acquired in the ordinary course of its business o the holder has no arrangement with any person to participate in the distribution of the new notes o if the holder is not a broker-dealer, that holder is not engaged in and does not intend to engage in the distribution of the new notes o if the holder is a broker-dealer that will receive new notes for its own account in exchange for outstanding notes that were acquired as a result of market-making activities, that holder will deliver a prospectus, as required by law, in connection with any resale of such new notes o the holder is not the Company's "affiliate," as defined in Rule 405 of the Securities Act, nor a broker-dealer tendering outstanding notes acquired directly from the Company for its own account RESALE OF NEW NOTES Based on interpretations of the SEC staff in no action letters issued to third parties, the Company believes that each new note issued under the exchange offer may be offered for resale, resold and otherwise transferred by the holder of that new note without compliance with the registration and prospectus delivery provisions of the Securities Act if: o the holder is not the Company's "affiliate" within the meaning of Rule 405 under the Securities Act 68 69 o such new note is acquired in the ordinary course of the holder's business o the holder does not intend to participate in the distribution of new notes If a holder of outstanding notes tenders in the exchange offer with the intention of participating in any manner in a distribution of the new notes, that holder o cannot rely on such interpretations by the SEC staff o must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction Unless an exemption from registration is otherwise available, any security holder intending to distribute new notes should be covered by an effective registration statement under the Securities Act containing the selling securityholder's information required by Item 507 of Regulation S-K under the Securities Act. This prospectus may be used for an offer to resell, resale or other retransfer of new notes only as specifically described in this prospectus. Only broker-dealers that acquired the outstanding notes as a result of market-making activities or other trading activities may participate in the exchange offer. Please read the section captioned "Plan of Distribution" for more details regarding the transfer of new notes. TERMS OF THE EXCHANGE OFFER Upon the terms and subject to the conditions described in this prospectus and in the letter of transmittal, the Company will accept for exchange any outstanding notes properly tendered and not withdrawn prior to the expiration date. The Company will issue $1,000 principal amount of new notes in exchange for each $1,000 principal amount of outstanding notes surrendered under the exchange offer. Outstanding notes may be tendered only in integral multiples of $1,000. The exchange offer is not conditioned upon any minimum aggregate principal amount of outstanding notes being tendered for exchange. As of the date of this prospectus, $150 million aggregate principal amount of the outstanding notes are outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of outstanding notes. There will be no fixed record date for determining registered holders of outstanding notes entitled to participate in the exchange offer. The Company intends to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934 and the rules and regulations of the SEC. Outstanding notes that are not tendered for exchange in the exchange offer will remain outstanding and continue to accrue interest and will be entitled to the rights and benefits such holders have under the indenture relating to the notes and the Registration Rights Agreement. The Company will be deemed to have accepted for exchange properly tendered outstanding notes when it has given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the Registration Rights Agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from the Company. Holders tendering outstanding 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 outstanding notes. The Company will pay all charges and expenses, other than certain applicable taxes described below, in connection with the exchange offer. It is important for noteholders to read the section labeled "--Fees and Expenses" for more details regarding fees and expenses incurred in the exchange offer. 69 70 The Company will return any outstanding notes that it does not accept for exchange for any reason without expense to the tendering holder as promptly as practicable after the expiration or termination of the exchange offer. EXPIRATION DATE The exchange offer will expire at 5:00 p.m., New York City time on April 5, 1999, unless in the Company's sole discretion, the Company extends it. EXTENSIONS, DELAY IN ACCEPTANCE, TERMINATION OR AMENDMENT The Company expressly reserves the right, at any time or at various times, to extend the period of time during which the exchange offer is open. During any such extensions, all outstanding notes previously tendered will remain subject to the exchange offer, and the Company may accept them for exchange. In order to extend the exchange offer, the Company will notify the exchange agent orally or in writing of any extension. The Company will also make a public announcement of the extension no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date. If any of the conditions described below under "--Conditions to the Exchange Offer" have not been satisfied, the Company reserves the right, in its sole discretion to delay accepting for exchange any outstanding notes or to extend the exchange offer or to terminate the exchange offer by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the Registration Rights Agreement, the Company also reserves the right to amend the terms of the exchange offer in any manner. 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 of outstanding notes. If the Company amends the exchange offer in a manner that it determines to constitute a material change, it will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the outstanding notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, the Company will extend the exchange offer if the exchange offer would otherwise expire during such period. Without limiting the manner in which the Company may choose to make public announcements of any delay in acceptance, extension, termination or amendment of the exchange offer, the Company will have no obligation to publish, advertise, or otherwise communicate any such public announcement, other than by making a timely release to the Dow Jones News Service. CONDITIONS TO THE EXCHANGE OFFER Despite any other term of the exchange offer, the Company will not be required to accept for exchange, or exchange any new notes for, any outstanding notes, and the Company may terminate the exchange offer as provided in this prospectus before accepting any outstanding notes for exchange, if in the Company's reasonable judgment the exchange offer, or the making of any exchange by a holder of outstanding notes, would violate applicable law or any applicable interpretation of the staff of the SEC. In addition, the Company will not be obligated to accept for exchange the outstanding notes of any holder that has not made to us (1) the representations described under "--Purpose and Effect of the Exchange Offer," "--Procedures for Tendering" and "Plan of Distribution" and (2) such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to make available to the Company an appropriate form for registration of the new notes under the Securities Act. The Company expressly reserves the right to amend or terminate the exchange offer, and to reject for exchange any outstanding notes not previously accepted for exchange, upon the occurrence of any of the conditions 70 71 to the exchange offer specified above. The Company will give oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the outstanding notes as promptly as practicable. These conditions are for the Company's sole benefit and the Company may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If the Company fails at any time to exercise any of these rights, this failure will not mean that the Company has waived its rights. Each such right will be deemed an ongoing right that the Company may assert at any time or at various times. In addition, the Company will not accept for exchange any outstanding notes tendered, and will not issue new notes in exchange for any such outstanding notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939. PROCEDURES FOR TENDERING How to Tender Generally Only a holder of outstanding notes may tender such outstanding notes in the exchange offer. To tender in the exchange offer, a holder must: o complete, sign and date the letter of transmittal, or a facsimile of the letter of transmittal; have the signature on the letter of transmittal guaranteed if the letter of transmittal so requires; and mail or deliver such letter of transmittal or facsimile to the exchange agent prior to the expiration date o comply with the automated tender offer program procedures of The Depository Trust Company, or DTC, described below In addition, either: o the exchange agent must receive outstanding notes along with the letter of transmittal o the exchange agent must receive, prior to the expiration date, a timely confirmation of book-entry transfer of such outstanding notes into the exchange agent's account at DTC according to the procedure for book-entry transfer described below or a properly transmitted agent's message, or o the holder must comply with the guaranteed delivery procedures described below To be tendered effectively, the exchange agent must receive any physical delivery of the letter of transmittal and other required documents at its address provided above under "Prospectus Summary--The Exchange Agent" prior to the expiration date. The tender by a holder that is not withdrawn prior to the expiration date will constitute an agreement between the holder and the Company in accordance with the terms and subject to the conditions described in this prospectus and in the letter of transmittal. THE METHOD OF DELIVERY OF OUTSTANDING NOTES, THE LETTER OF TRANSMITTAL AND ALL OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE HOLDER'S ELECTION AND RISK. RATHER THAN MAIL THESE ITEMS, THE COMPANY RECOMMENDS THAT HOLDERS USE AN OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, HOLDERS SHOULD ALLOW SUFFICIENT TIME TO ASSURE DELIVERY TO THE EXCHANGE AGENT BEFORE THE EXPIRATION DATE. HOLDERS SHOULD NOT SEND THE LETTER OF TRANSMITTAL OR OUTSTANDING NOTES TO THE COMPANY. HOLDERS MAY REQUEST THEIR BROKERS, DEALERS, COMMERCIAL BANKS, TRUST COMPANIES OR OTHER NOMINEES TO EFFECT THE ABOVE TRANSACTIONS FOR YOU. 71 72 How to Tender--Beneficial Owners Beneficial owners of outstanding notes that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee wishing to tender those notes should contact the registered holder promptly and instruct it to tender on the beneficial owner's behalf. Beneficial owners who wish to tender on their own behalf must, prior to completing and executing the letter of transmittal and delivering their outstanding notes, either: o make appropriate arrangements to register ownership of the outstanding notes in their name, or o obtain a properly completed bond power from the registered holder of outstanding notes The transfer of registered ownership may take considerable time and may not be completed prior to the expiration date. Signatures and Signature Guarantees Holders of outstanding notes must have signatures on a letter of transmittal or a notice of withdrawal described below guaranteed 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 Securities Exchange Act of 1934, that is a member of one of the recognized signature guarantee programs identified in the letter of transmittal, unless the outstanding notes are tendered: o by a registered holder who has not completed the box entitled "Special Issuance Instructions" or "Special Delivery Instructions" on the letter of transmittal and the new notes are being issued directly to the registered holder of the outstanding notes tendered in the exchange for those new notes o for the account of 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 When Endorsements or Bond Powers are Needed If the letter of transmittal is signed by a person other than the registered holder of any outstanding notes, the outstanding notes must be endorsed or accompanied by a properly completed bond power. The bond power must be signed by the registered holder as the registered holder's name appears on the outstanding notes and 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 must guarantee the signature on the bond power. If the letter of transmittal or any outstanding notes or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or other acting in a fiduciary or representative capacity, those persons should so indicate when signing. Unless waived by the Company, they should also submit evidence satisfactory to the Company of their authority to deliver the letter of transmittal. Tendering Through DTC's Automated Tender Offer Program The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC's system may use DTC's automated tender offer program to tender. Participants in the program may, instead of physically completing and signing the letter of transmittal and delivering it to the exchange agent, transmit their acceptance of the exchange offer electronically. They may do so by causing DTC to transfer the outstanding notes to 72 73 the exchange agent in accordance with its procedures for transfer. DTC will then send an agent's message to the exchange agent. The term "agent's message" means a message transmitted by DTC, received by the exchange agent and forming part of the book-entry confirmation, to the effect that: o DTC has received an express acknowledgment from a participant in its automated tender offer program that is tendering outstanding notes that are the subject of such book-entry confirmation o such participant has received and agrees to be bound by the terms of the letter of transmittal or, in the case of an agent's message relating to guaranteed delivery, that such participant has received and agrees to be bound by the applicable notice of guaranteed delivery o the agreement may be enforced against such participant Determinations Under the Exchange Offer The Company will determine in its sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered outstanding notes and withdrawal of tendered outstanding notes. The Company's determination will be final and binding. The Company reserves the absolute right to reject any outstanding notes not properly tendered or any outstanding notes the Company's acceptance of which would, in the opinion of its counsel, be unlawful. The Company also reserves the right to waive any defects, irregularities or conditions of tender as to particular outstanding 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 outstanding notes must be cured within such time as the Company shall determine. Neither the Company, the exchange agent nor any other person will be under any duty to give notification of defects or irregularities with respect to tenders of outstanding notes, and they will incur no liability for failure to give such notification. Tenders of outstanding notes will not be deemed made until such defects or irregularities have been cured or waived. Any outstanding notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date. When the Company Will Issue New Notes In all cases, the Company will issue new notes for outstanding notes that it has accepted for exchange under the exchange offer only after the exchange agent timely receives: o outstanding notes or a timely book-entry confirmation of such outstanding notes into the exchange agent's account at DTC o a properly completed and duly executed letter of transmittal and all other required documents or a properly transmitted agent's message Return of Outstanding Notes Not Accepted or Exchanged If the Company does not accept any tendered outstanding notes for exchange for any reason described in the terms and conditions of the exchange offer or if outstanding notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged outstanding notes will be returned without expense to their tendering holder. In the case of outstanding notes tendered by book-entry transfer into the exchange agent's account at DTC according to the procedures described below, such non-exchanged outstanding notes will be credited to an account maintained with DTC. These actions will occur as promptly as practicable after the expiration or termination of the exchange offer. 73 74 Representations to the Company Each holder, by signing or agreeing to be bound by the letter of transmittal, will represent to the Company that, among other things: o any new notes that the holder receives will be acquired in the ordinary course of its business o that holder has no arrangement or understanding with any person or entity to participate in the distribution of the new notes o if the holder is not a broker-dealer, that the holder is not engaged in and does not intend to engage in the distribution of the new notes o if the holder is a broker-dealer that will receive new notes for its own account in exchange for outstanding notes that were acquired as a result of market-making activities, that the holder will deliver a prospectus, as required by law, in connection with any resale of such new notes o that holder is not the Company's "affiliate," as defined in Rule 405 of the Securities Act, or, if the holder is an affiliate of the Company, that holder will comply with any applicable registration and prospectus delivery requirements of the Securities Act BOOK-ENTRY TRANSFER The exchange agent will make a request to establish an account with respect to the outstanding notes at DTC for purposes of the exchange offer promptly after the date of this prospectus. Any financial institution participating in DTC's system may make book-entry delivery of outstanding notes by causing DTC to transfer such outstanding notes into the exchange agent's account at DTC in accordance with DTC's procedures for transfer. Holders of outstanding notes who are unable to deliver confirmation of the book-entry tender of their outstanding notes into the exchange agent's account at DTC or all other documents required by the letter of transmittal to the exchange agent on or prior to the expiration date must tender their outstanding notes according to the guaranteed delivery procedures described below. GUARANTEED DELIVERY PROCEDURES Any holder wishing to tender its outstanding notes but whose outstanding notes are not immediately available or who cannot deliver its outstanding notes, the letter of transmittal or any other required documents to the exchange agent or comply with the applicable procedures under DTC's automated tender offer program prior to the expiration date may tender if: o the tender is made through 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 o prior to the expiration date, the exchange agent receives from such member firm of a registered national securities exchange or of the National Association of Securities Dealers, Inc., commercial bank or trust company having an office or correspondent in the United States, or eligible guarantor institution either a properly completed and duly executed notice of guaranteed delivery by facsimile transmission, mail or hand delivery or a properly transmitted agent's message and notice of guaranteed delivery: o setting forth the holder's name and address, the registered number(s) of the holder's outstanding notes and the principal amount of outstanding notes tendered 74 75 o stating that the tender is being made thereby o guaranteeing that, within five business days after the expiration date, the letter of transmittal or facsimile thereof, together with the outstanding notes or a book-entry confirmation, and any other documents required by the letter of transmittal will be deposited by the eligible guarantor institution with the exchange agent o the exchange agent receives such properly completed and executed letter of transmittal or facsimile thereof, as well as all tendered outstanding notes in proper form for transfer or a book-entry confirmation, and all other documents required by the letter of transmittal, within five business days after the expiration date Upon request to the exchange agent, a notice of guaranteed delivery will be sent to a holder if it wishes to tender its outstanding notes according to the guaranteed delivery procedures described above. WITHDRAWAL OF TENDERS Except as otherwise provided in this prospectus, any holder may withdraw its tender at any time prior to 5:00 p.m., New York City time, on the expiration date (unless previously accepted for exchange). For a withdrawal to be effective: o the exchange agent must receive a written notice of withdrawal at one of the addresses listed above under "Prospectus Summary--The Exchange Agent" or o the withdrawing holder must comply with the appropriate procedures of DTC's automated tender offer program system Any notice of withdrawal must: o specify the name of the person who tendered the outstanding notes to be withdrawn (the "Depositor") o identify the outstanding notes to be withdrawn, including the registration number or numbers and the principal amount of such outstanding notes o be signed by the Depositor in the same manner as the original signature on the letter of transmittal used to deposit those outstanding notes (or be accompanied by documents of transfer sufficient to permit the trustee for the outstanding notes to register the transfer into the name of the Depositor withdrawing the tender) o specify the name in which such outstanding notes are to be registered, if different from that of the Depositor If outstanding notes have been tendered under the procedure for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at DTC to be credited with the withdrawn outstanding notes and otherwise comply with the procedures of DTC. The Company will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal, and the Company's determination shall be final and binding on all parties. The Company will deem any outstanding notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer. 75 76 Any outstanding notes that have been tendered for exchange but that are not exchanged for any reason will be returned to their holder without cost to the holder or, in the case of outstanding notes tendered by book-entry transfer into the exchange agent's account at DTC according to the procedures described above, such outstanding notes will be credited to an account maintained with DTC for the outstanding notes. This return or crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. Holders may retender properly withdrawn outstanding notes by following one of the procedures described under "--Procedures for Tendering" above at any time on or prior to the expiration date. FEES AND EXPENSES The Company will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, the Company may make additional solicitation by telegraph, telephone or in person by our officers and regular employees and those of our affiliates. The Company has not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. The Company will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses. The Company may also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus, letters of transmittal and related documents to the beneficial owners of the outstanding notes and in handling or forwarding tenders for exchange. The Company will pay the cash expenses to be incurred in connection with the exchange offer. They include: o SEC registration fees o fees and expenses of the exchange agent and trustee o accounting and legal fees and printing costs o related fees and expenses The Company will pay all transfer taxes, if any, applicable to the exchange of outstanding notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if: o certificates representing outstanding notes for principal amounts not tendered or accepted for exchange are to be delivered to, or are to be issued in the name of, any person other than the registered holder of outstanding notes tendered o tendered outstanding notes are registered in the name of any person other than the person signing the letter of transmittal o a transfer tax is imposed for any reason other than the exchange of outstanding notes under the exchange offer If satisfactory evidence of payment of any transfer taxes payable by a note holder is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to that tendering holder. 76 77 TRANSFER TAXES If a holder tenders its outstanding notes for exchange, it will not be required to pay any transfer taxes. However, if a holder instructs the Company to register new notes in the name of, or request that outstanding notes not tendered or not accepted in the exchange offer be returned to, a person other than that holder, in that holder's capacity as the registered tendering holder, that holder will be required to pay any applicable transfer tax. CONSEQUENCES OF FAILURE TO EXCHANGE Holders who do not exchange their outstanding notes for new notes under the exchange offer will remain subject to the existing restrictions on transfer of the outstanding notes. In general, such a holder may not offer or sell the outstanding notes unless they are registered under the Securities Act, or if the offer or sale is exempt from registration under the Securities Act and applicable state securities laws. Except as required by the Registration Rights Agreement, the Company does not intend to register resales of the outstanding notes under the Securities Act. Based on interpretations of the SEC staff, holders may offer for resale, resell or otherwise transfer new notes issued in the exchange offer without compliance with the registration and prospectus delivery provisions of the Securities Act, if (1) they are not the Company's "affiliate" within the meaning of Rule 405 under the Securities Act, (2) they acquired the new notes in the ordinary course of their business and (3) they have no arrangement or understanding with respect to the distribution of the new notes to be acquired in the exchange offer. If a holder tenders in the exchange offer for the purpose of participating in a distribution of the new notes, it: o cannot rely on the applicable interpretations of the SEC o must comply with the registration and prospectus delivery requirements of the Securities Act in connection with a secondary resale transaction ACCOUNTING TREATMENT No gain or loss for accounting purposes will be recognized by the Company upon the consummation of the exchange offer. The expenses of the exchange offer will be amortized by the Company over the term of the new notes under generally accepted accounting principles. OTHER Participation in the exchange offer is voluntary, and holders of outstanding notes should carefully consider whether to accept. Those holders are urged to consult their financial and tax advisors in making their own decision on what action to take. The Company may in the future seek to acquire untendered outstanding notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. The Company has no present plans to acquire any outstanding notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered outstanding notes. 77 78 DESCRIPTION OF THE NOTES The new notes will be issued, and the outstanding notes were issued, pursuant to an indenture (the "Indenture") between the Company, as issuer, and State Street Bank and Trust Company, as trustee (the "Trustee"). The terms of the notes include those stated in the Indenture and those made part of the Indenture by the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act"). The definitions of certain capitalized terms used in the following summary are set forth below under "-- Certain Definitions." The following description is a summary of the material provisions of the Indenture. It does not restate that agreement in its entirety. The Company urges Holders to read the Indenture because it, and not this description, defines the rights of Holders of these notes. The Company has filed the Indenture as an exhibit to the registration statement which includes this Prospectus. If the exchange offer contemplated by this prospectus (the "Exchange Offer") is consummated, Holders of outstanding notes who do not exchange those notes for new notes in the Exchange Offer will vote together with Holders of new notes for all relevant purposes under the Indenture. In that regard, the Indenture requires that certain actions by the Holders thereunder, including acceleration following an Event of Default, must be taken, and certain rights must be exercised, by specified minimum percentages of the aggregate principal amount of the outstanding securities issued under the Indenture. In determining whether Holders of the requisite percentage in principal amount have given any notice, consent or waiver or taken any other action permitted under the Indenture, any outstanding notes that remain outstanding after the Exchange Offer will be aggregated with the new notes, and the Holders of such outstanding notes and the new notes will vote together as a single series for all such purposes. Accordingly, all references herein to specified percentages in aggregate principal amount of the notes outstanding shall be deemed to mean, at any time after the Exchange Offer is consummated, such percentages in aggregate principal amount of the outstanding notes and the new notes then outstanding. BRIEF DESCRIPTION OF THE NOTES The notes: o are unsecured obligations of the Company; o are limited to $150,000,000 aggregate principal amount; o are subordinated in right of payment to all existing and future Senior Indebtedness of the Company; o are senior in right of payment to all existing and future Subordinated Indebtedness of the Company; and o rank equally with all Pari Passu Indebtedness. The new notes will be issued, and the outstanding notes were issued, only in registered form, without coupons, in denominations of $1,000 and integral multiples thereof. Principal of, premium, if any, on and interest on the notes is payable, and the notes are transferable, at the office or agency of the Company in the City of New York maintained for such purposes, which initially will be the corporate trust office or agency of the Trustee maintained at New York, New York. In addition, interest may be paid, at the option of the Company, by check mailed to the registered Holders of the notes at their respective addresses as shown on the Note Register or, upon application to the Trustee by any Holder of an aggregate principal amount of notes in excess of $500,000 not later than the applicable Regular Record Date, by transfer to an account (such transfer to be made only to a Holder of an aggregate principal amount of notes in excess of $500,000) maintained by such Holder with a bank in New York City. No transfer will be made to any such account unless the Trustee has received written wire instructions not less than 15 days prior to the relevant payment date. No service charge will be made for any transfer, exchange or 78 79 redemption of notes, but the Company or the Trustee may require payment of a sum sufficient to cover any tax or other governmental charge that may be payable in connection therewith. For a discussion of the circumstances in which the interest rate on the outstanding notes may be temporarily increased, see "Outstanding Notes Registration Rights Agreement." Any outstanding notes that remain outstanding after the completion of the Exchange Offer, together with the new notes issued in connection with the Exchange Offer, will be treated as a single class of securities under the Indenture. MATURITY, INTEREST AND PRINCIPAL PAYMENTS The notes will mature on February 15, 2009. Interest on the notes will accrue at the rate of 10 3/8% per annum and will be payable semiannually on February 15 and August 15 of each year (each an "Interest Payment Date"), commencing August 15, 1999, to the Person in whose name the note is registered in the Note Register at the close of business on the February 1, or August 1 next preceding such interest payment date. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months. REDEMPTION Optional Redemption. The notes will be redeemable at the option of the Company, in whole or in part, at any time on or after February 15, 2004, at the redemption prices (expressed as percentages of principal amount) set forth below, plus accrued and unpaid interest, if any, to the redemption date, subject to the right of Holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date, if redeemed during the 12-month period beginning on February 15 of the years indicated below:
REDEMPTION YEAR PRICE - ---- ------------ 2004................................................................................. 105.188% 2005................................................................................. 103.458% 2006................................................................................. 101.729% 2007 and thereafter.................................................................. 100.000%
Selection and Notice In the event that less than all of the notes are to be redeemed at any time, selection of such notes, or any portion thereof that is an integral multiple of $1,000, for redemption will be made by the Trustee from the notes outstanding not previously called for redemption, or otherwise purchased by the Company, on a pro rata basis, by lot or by such method as the Trustee shall deem fair and appropriate; provided, however, that no note with a principal amount of $1,000 or less shall be redeemed in part. Notice 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. Another note in a 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 will cease to accrue on the notes or portions thereof called for redemption and accepted for payment. Offers to Purchase As described below: 79 80 (1) upon the occurrence of a Change of Control, the Company is obligated to make an offer to purchase all of the notes then outstanding at a purchase price equal to 101% of the principal amount thereof, together with accrued and unpaid interest, if any, to the date of purchase and (2) upon the occurrence of an Asset Sale, the Company may be obligated to make offers to purchase notes with a portion of the Net Cash Proceeds of such Asset Sale at a purchase price equal to 100% of the principal amount thereof, together with accrued and unpaid interest, if any, to the date of purchase. See "-- Certain Covenants; Change of Control" and "-- Limitation on Disposition of Proceeds of Asset Sales." SUBORDINATION Payments of and distributions on or with respect to the Note Obligations are subordinated, to the extent set forth in the Indenture, in right of payment to the prior payment in full in cash or Cash Equivalents of all existing and future Senior Indebtedness, which includes, without limitation, all Credit Agreement Obligations of the Company. The notes rank prior in right of payment only to other Indebtedness of the Company which is, by its terms, subordinated in right of payment to the notes. In addition, the Note Obligations are effectively subordinated to all creditors of the Company's Subsidiaries, including trade creditors. See "Risk Factors -- The right to receive payments on the notes is junior to our senior debt; The notes are structurally subordinated to obligations of our subsidiaries." In the event of: (1) any insolvency or bankruptcy case or proceeding, or any receivership, liquidation, reorganization or other similar case or proceeding in connection therewith, relating to the Company (or its creditors, as such) or its properties and assets, or (2) any liquidation, dissolution or other winding-up of the Company, whether voluntary or involuntary, or (3) any assignment for the benefit of creditors or other marshaling of assets or liabilities of the Company all Senior Indebtedness of the Company must be paid in full in cash or Cash Equivalents before any direct or indirect payment or distribution, whether in cash, property or securities (excluding certain permitted equity and subordinated debt securities referred to in the Indenture as "Permitted Junior Securities"), is made on account of the Note Obligations. In the event that, notwithstanding the foregoing, the Trustee or the Holder of any note receives any payment or distribution of properties or assets of the Company of any kind or character, whether in cash, property or securities, by set-off or otherwise, in respect of Note Obligations before all Senior Indebtedness is paid or provided for in full in cash or Cash Equivalents, then the Trustee or the Holders of notes receiving any such payment or distribution, other than a payment or distribution in the form of Permitted Junior Securities, will be required to pay or deliver such payment or distribution forthwith to the trustee in bankruptcy, receiver, liquidating trustee, custodian, assignee, agent or other person making payment or distribution of assets of the Company for application to the payment of all Senior Indebtedness remaining unpaid, to the extent necessary to pay all Senior Indebtedness in full. During the continuance of any default in the payment when due, whether at Stated Maturity, upon scheduled repayment, upon acceleration or otherwise, of principal of or premium, if any, or interest on, or of unreimbursed amounts under drawn letters of credit or fees relating to letters of credit constituting, any Designated Senior Indebtedness (a "Payment Default"), no direct or indirect payment or distribution by or on behalf of the Company of any kind or character shall be made on account of the Note Obligations or any obligation under any Subsidiary Guarantee unless and until such default has been cured or waived or has ceased to exist or such Designated Senior Indebtedness shall have been discharged or paid in full in cash or Cash Equivalents. 80 81 In addition, during the continuance of any default other than a Payment Default with respect to any Designated Senior Indebtedness pursuant to which the maturity thereof may then be accelerated (a "Non-payment Default"), after receipt by the Trustee from the holders, or their representative, of such Designated Senior Indebtedness of a written notice of such Non-payment Default, no payment or distribution of any kind or character may be made by the Company on account of the Note Obligations for the period specified below (the "Payment Blockage Period"). The Payment Blockage Period shall commence upon the receipt of notice of a Non-payment Default by the Trustee from the holders (or their representative) of Designated Senior Indebtedness stating that such notice is a payment blockage notice pursuant to the Indenture and shall end on the earliest to occur of the following events: (1) 179 days shall have elapsed since the receipt by the Trustee of such notice; (2) the date, as set forth in a written notice to the Company or the Trustee from the holders, or their representative, of the Designated Senior Indebtedness initiating such Payment Blockage Period, on which such default is cured or waived or ceases to exist (provided, that no other Payment Default or Non-payment Default has occurred or is then continuing after giving effect to such cure or waiver); (3) the date on which such Designated Senior Indebtedness is discharged or paid in full in cash or Cash Equivalents; and (4) the date, as set forth in a written notice to the Company or the Trustee from the holders, or their representative, of the Designated Senior Indebtedness initiating such Payment Blockage Period, on which such Payment Blockage Period shall have been terminated by written notice to the Company or the Trustee from the holders, or their representative, of Designated Senior Indebtedness initiating such Payment Blockage Period, after which the Company, subject to the subordination provisions set forth above and the existence of another Payment Default, shall promptly resume making any and all required payments in respect of the notes, including any missed payments. Only one Payment Blockage Period with respect to the notes may be commenced within any 360 consecutive day period. No Non-payment Default with respect to Designated Senior Indebtedness that existed or was continuing on the date of the commencement of any Payment Blockage Period with respect to the Designated Senior Indebtedness initiating such Payment Blockage Period will be, or can be, made the basis for the commencement of a second Payment Blockage Period, whether or not within a period of 360 consecutive days, unless such default has been cured or waived for a period of not less than 90 consecutive days (it being acknowledged that any subsequent action, or any breach of any financial covenant for a period commencing after the date of commencement of such Payment Blockage Period, that, in either case, would give rise to a Non-payment Default pursuant to any provision under which a Non-payment Default previously existed or was continuing shall constitute a new Non-payment Default for this purpose; provided, however, that, in the case of a breach of a particular financial covenant, the Company shall have been in compliance for at least one full 90 consecutive day period commencing after the date of commencement of such Payment Blockage Period). In no event will a Payment Blockage Period extend beyond 179 days from the date of the receipt by the Trustee of the notice, and there must be a 181 consecutive day period in any 360-day period during which no Payment Blockage Period is in effect. In the event that, notwithstanding the foregoing, the Company makes any payment or distribution to the Trustee or the Holder of any note prohibited by the subordination provision of the Indenture, then such payment or distribution will be required to be paid over and delivered forthwith to the holders, or their representative, of Designated Senior Indebtedness. If the Company fails to make any payment on the notes when due or within any applicable grace period, whether or not on account of the payment blockage provisions referred to above, such failure will constitute an Event of Default under the Indenture and will enable the Holders of the notes to accelerate the maturity thereof. See "-- Events of Default." 81 82 By reason of such subordination, in the event of liquidation, receivership, reorganization or insolvency, creditors of the Company who are holders of Senior Indebtedness may recover more, ratably, than the Holders of the notes, and funds which would be otherwise payable to the Holders of the notes will be paid to the holders of the Senior Indebtedness to the extent necessary to pay the Senior Indebtedness in full, and the Company may be unable to meet its obligations in full with respect to the notes. As of September 30, 1998, after giving effect pro forma to the sale of the outstanding notes and the application of the net proceeds therefrom as if that sale had occurred on that date, the aggregate amount of outstanding Senior Indebtedness would have been approximately $23,179,000. See "Use of Proceeds," "Capitalization" and "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources." Although the Indenture contains limitations on the amount of additional Indebtedness that the Company and the Restricted Subsidiaries may incur, the amounts of such Indebtedness could be substantial and, in any case, such Indebtedness may be Senior Indebtedness or Indebtedness of Subsidiaries to which the notes are subordinated. The Indenture prohibits the incurrence by the Company of Indebtedness that is contractually subordinated in right of payment to any Senior Indebtedness of the Company and senior in right of payment to the notes. Currently, the aggregate amount of outstanding Indebtedness of the Company that is: (1) contractually subordinated in right of payment to the notes is $115,000,000 and (2) pari passu in right of payment with the notes is $100,000,000. POSSIBLE SUBSIDIARY GUARANTEES OF THE NOTES If the Company's existing or future Restricted Subsidiaries guarantee any other Indebtedness of the Company, they will be required by the terms of the Indenture to jointly and severally guarantee the notes on a senior subordinated basis. See "-- Certain Covenants; Limitations on Non-Guarantor Restricted Subsidiaries." At the date hereof, no Subsidiary of the Company has an outstanding guarantee of any Indebtedness of the Company, and the Company does not intend to cause any Subsidiary to guarantee any such Indebtedness in the future, thus requiring it to issue a Subsidiary Guarantee. Any Subsidiary that issues a Subsidiary Guarantee is herein called a Subsidiary Guarantor. Each Subsidiary Guarantor will guarantee, jointly and severally, to each Holder of Notes and the Trustee, the full and prompt performance of the Company's obligations under the Indenture and the notes, including the payment of principal of (or premium, if any, on) and interest on the notes pursuant to its Subsidiary Guarantee. The Subsidiary Guarantees will be subordinated to Guarantor Senior Indebtedness of the Subsidiary Guarantors to the same extent and in the same manner as the notes are subordinated to Senior Indebtedness. The obligations of each Subsidiary Guarantor will be limited to the maximum amount as will, after giving effect to all other contingent and fixed liabilities, including, but not limited to, Guarantor Senior Indebtedness, of such Subsidiary Guarantor and after giving effect to any collections from or payments made by or on behalf of any other Subsidiary Guarantor in respect of the obligations of such other Subsidiary Guarantor under its Subsidiary Guarantee or pursuant to its contribution obligations under the Indenture, result in the obligations of such Subsidiary Guarantor under the Subsidiary Guarantee not constituting a fraudulent conveyance or fraudulent transfer under federal or state law. Each Subsidiary Guarantor that makes a payment or distribution under a Subsidiary Guarantee shall be entitled to a contribution from each other Subsidiary Guarantor, if any, in a pro rata amount based on the Adjusted Net Assets (as defined in the Indenture) of each Subsidiary Guarantor. Each Subsidiary Guarantor may consolidate with or merge into or sell, assign, convey, transfer, lease or otherwise dispose of its properties and assets substantially as an entirety (or any portion thereof) to the Company or another Subsidiary Guarantor without limitation, except to the extent any such transaction is subject to the covenants described below under the caption "-- Merger, Consolidation and Sale of Assets." Each Subsidiary Guarantor may consolidate with or merge into or sell, assign, convey, transfer, lease or otherwise dispose of its properties and assets 82 83 substantially as an entirety in one transaction or series of related transactions to a Person other than the Company or another Subsidiary Guarantor, whether or not affiliated with the Subsidiary Guarantor; provided, that: (1) in the case of a merger or consolidation, if the surviving Person is not the Subsidiary Guarantor, such surviving Person or, in the case of a sale, assignment, conveyance, transfer, lease or other disposition, the transferee Person agrees to assume such Subsidiary Guarantor's Subsidiary Guarantee and all its obligations pursuant to the Indenture, except to the extent that the following paragraph would result in the release of such Subsidiary Guarantee and (2) such transaction does not: (a) violate any of the covenants described below under the caption "-- Certain Covenants" or in the Indenture or (b) result in a Default or Event of Default immediately thereafter. The Subsidiary Guarantee of any Restricted Subsidiary may be released upon the terms and subject to the conditions described under paragraph (2) of the caption "-- Certain Covenants -- Limitation on Non-Guarantor Restricted Subsidiaries." Each Subsidiary Guarantor that is designated as an Unrestricted Subsidiary in accordance with the Indenture shall be released from its Subsidiary Guarantee and related obligations set forth in the Indenture for so long as it remains an Unrestricted Subsidiary. CERTAIN COVENANTS The Indenture contains, among others, the covenants described below: Limitation on Indebtedness. Neither the Company nor any Restricted Subsidiary will create, incur, issue, assume, guarantee or in any manner become directly or indirectly liable for the payment of (collectively "incur") any Indebtedness, including any Acquired Indebtedness, other than Permitted Indebtedness and Permitted Subsidiary Indebtedness, as the case may be; provided, however, that the Company and its Restricted Subsidiaries that are Subsidiary Guarantors may incur additional Indebtedness if: (1) the Company's Consolidated Fixed Charge Coverage Ratio for the four full fiscal quarters immediately preceding the incurrence of such Indebtedness (and for which financial statements are available), taken as one period (at the time of such incurrence, after giving pro forma effect to: (a) the incurrence of such Indebtedness and, if applicable, the application of the net proceeds therefrom as if such Indebtedness had been incurred and the application of such proceeds had occurred at the beginning of such four-quarter period; (b) the incurrence, repayment or retirement of any other Indebtedness, including Permitted Indebtedness and Permitted Subsidiary Indebtedness, by the Company or its Restricted Subsidiaries since the first day of such four-quarter period (including any other Indebtedness to be incurred concurrent with the incurrence of such Indebtedness) as if such Indebtedness had been incurred, repaid or retired at the beginning of such four-quarter period; and (c) notwithstanding clause (4) of the definition of Consolidated Net Income, the acquisition (whether by purchase, merger or otherwise) or disposition (whether by sale, merger or otherwise) of any Person acquired or disposed of by the Company or its Restricted Subsidiaries, as the case may be, since the first day of such four-quarter period, as if such acquisition or disposition had occurred at the beginning of such four-quarter period), would have been equal to at least 2.5 to 1.0 and (2) no Default or Event of Default would occur or be continuing. 83 84 Limitation on Restricted Payments. (1) The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, take any of the following actions (unless such action constitutes a Permitted Investment): (a) declare or pay any dividend on, or make any distribution to holders of, any shares of the Company's Capital Stock (other than dividends or distributions payable solely in shares of Qualified Capital Stock of the Company, options, warrants or other rights to purchase Qualified Capital Stock of the Company); (b) purchase, redeem or otherwise acquire or retire for value any Capital Stock of the Company or any Affiliate thereof (other than any Wholly Owned Restricted Subsidiary of the Company) or any options, warrants or other rights to acquire such Capital Stock; provided, however, that the Company may make any payment of the applicable redemption price in connection with a Qualified Redemption Transaction; (c) make any principal payment on or repurchase, redeem, defease or otherwise acquire or retire for value, prior to any scheduled principal payment, scheduled sinking fund payment or maturity, any Pari Passu Indebtedness or Subordinated Indebtedness, except in any case out of a Pari Passu Offer or a Net Proceeds Deficiency (each as defined in "-- Limitation on Disposition of Proceeds of Asset Sales") pursuant to the provisions of the Indenture described under the caption "-- Limitation on Disposition of Proceeds of Asset Sales" and except upon a Change of Control or similar event required by the indenture or other agreement or instrument pursuant to which such Pari Passu Indebtedness or Subordinated Indebtedness was issued, provided the Company is then obligated to make a Change of Control Offer in compliance with the covenant described below under "-- Change of Control;" provided, however, that the Company may make any payment of the applicable redemption price in connection with a Qualified Redemption Transaction; (d) declare or pay any dividend on, or make any distribution to the holders of, any shares of Capital Stock of any Restricted Subsidiary of the Company (other than to the Company or any of its Wholly Owned Restricted Subsidiaries) or purchase, redeem or otherwise acquire or retire for value any Capital Stock of any Restricted Subsidiary (other than a Wholly Owned Restricted Subsidiary) or any options, warrants or other rights to acquire any such Capital Stock (other than with respect to any such Capital Stock held by the Company or any Wholly Owned Restricted Subsidiary of the Company); (e) make any Investment; or (f) in connection with the acquisition of any property or asset by the Company or its Restricted Subsidiaries after the date of the Indenture, which property or asset would secure or be subject to any Production Payment obligations of the Company or its Restricted Subsidiaries, make any investment (of cash, property or other assets) in such property or asset so acquired in addition to the amount of Indebtedness, including Production Payment obligations, incurred by the Company or its Restricted Subsidiaries in connection with such acquisition; (such payments or other actions described in, but not excluded from, clauses (a) through (f) are collectively referred to as "Restricted Payments"), unless at the time of and after giving effect to the proposed Restricted Payment (with the amount of any such Restricted Payment, if other than cash, being the amount determined by the Board of Directors, whose determination shall be conclusive and evidenced by a resolution), (i) no Default or Event of Default shall have occurred and be continuing, (ii) the Company could incur $1.00 of additional Indebtedness (other than Permitted Indebtedness) in accordance with the covenant described above under the caption "-- Limitation on Indebtedness" and (iii) the aggregate amount of all Restricted Payments declared or made after the date of the Indenture shall not exceed the sum (without duplication) of the following: 84 85 (A) 50% of the aggregate Consolidated Net Income of the Company accrued on a cumulative basis during the period beginning on the first day of the first month after the date of the Indenture and ending on the last day of the Company's last fiscal quarter ending prior to the date of such proposed Restricted Payment (or, if such aggregate cumulative Consolidated Net Income shall be a loss, minus 100% of such loss), plus (B) the aggregate net cash proceeds received after the date of the Indenture by the Company as capital contributions to the Company (other than from any Restricted Subsidiary), plus (C) the aggregate net cash proceeds received after the date of the Indenture by the Company from the issuance or sale (other than to any of its Restricted Subsidiaries) of shares of Qualified Capital Stock of the Company or any options, warrants or rights to purchase such shares of Qualified Capital Stock of the Company, plus (D) the aggregate net cash proceeds received after the date of the Indenture by the Company (other than from any of its Restricted Subsidiaries) upon the exercise of any options, warrants or rights to purchase shares of Qualified Capital Stock of the Company, plus (E) the aggregate net cash proceeds received after the date of the Indenture by the Company from the issuance or sale (other than to any of its Restricted Subsidiaries) of debt securities or shares of Redeemable Capital Stock that have been converted into or exchanged for Qualified Capital Stock of the Company to the extent such debt securities were originally sold for cash, together with the aggregate cash received by the Company at the time of such conversion or exchange, plus (F) to the extent not otherwise included in the Company's Consolidated Net Income, the net reduction in Investments in Affiliates and Unrestricted Subsidiaries resulting from the payments of interest on Indebtedness, dividends, repayments of loans or advances, or other transfers of assets, in each case to the Company or a Restricted Subsidiary after the date of the Indenture from any Affiliate or Unrestricted Subsidiary or from the redesignation of an Unrestricted Subsidiary as a Restricted Subsidiary (valued in each case as provided in the definition of "Investment"), not to exceed in the case of any Affiliate or Unrestricted Subsidiary the total amount of Investments (other than Permitted Investments) in such Affiliate or Unrestricted Subsidiary made by the Company and its Restricted Subsidiaries in such Affiliate or Unrestricted Subsidiary after the date of the Indenture, plus (G) $15,000,000. (2) Notwithstanding paragraph (1) above, the Company and its Restricted Subsidiaries may take the following actions so long as (in the case of clauses (b), (c) and (d) below) no Default or Event of Default shall have occurred and be continuing: (a) the payment of any dividend within 60 days after the date of declaration thereof, if at such declaration date such declaration complied with the provisions of paragraph (1) above (and such payment shall be deemed to have been paid on such date of declaration for purposes of any calculation required by the provisions of paragraph (1) above); (b) the repurchase, redemption or other acquisition or retirement of any shares of any class of Capital Stock of the Company or any Restricted Subsidiary, in exchange for, or out of the aggregate net cash proceeds of, a substantially concurrent issue and sale (other than to a Restricted Subsidiary) of shares of Qualified Capital Stock of the Company; (c) the purchase, redemption, repayment, defeasance or other acquisition or retirement for value of any Subordinated Indebtedness (other than Redeemable Capital Stock) in exchange for or out of 85 86 the aggregate net cash proceeds of a substantially concurrent issue and sale (other than to a Restricted Subsidiary) of shares of Qualified Capital Stock of the Company; (d) the purchase, redemption, repayment, defeasance or other acquisition or retirement for value of Subordinated Indebtedness (other than Redeemable Capital Stock) in exchange for, or out of the aggregate net cash proceeds of, a substantially concurrent incurrence (other than to a Restricted Subsidiary) of Subordinated Indebtedness of the Company so long as (i) the principal amount of such new Indebtedness does not exceed the principal amount (or, if such Subordinated Indebtedness being refinanced provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration thereof, such lesser amount as of the date of determination) of the Subordinated Indebtedness being so purchased, redeemed, repaid, defeased, acquired or retired, plus the amount of any premium required to be paid in connection with such refinancing pursuant to the terms of the Subordinated Indebtedness refinanced or the amount of any premium reasonably determined by the Company as necessary to accomplish such refinancing, plus the amount of fees and expenses of the Company incurred in connection with such refinancing, (ii) such new Subordinated Indebtedness is subordinated to the notes at least to the same extent as such Subordinated Indebtedness so purchased, redeemed, repaid, defeased, acquired or retired, (iii) such new Subordinated Indebtedness has an Average Life to Stated Maturity that is longer than the Average Life to Stated Maturity of the notes and such new Subordinated Indebtedness has a Stated Maturity for its final scheduled principal payment that is at least 91 days later than the Stated Maturity for the final scheduled principal payment of the notes; and (e) repurchases, acquisitions or retirements of shares of Qualified Capital Stock of the Company deemed to occur upon the exercise of stock options or similar rights issued under employee benefit plans of the Company if such shares represent all or a portion of the exercise price or are surrendered in connection with satisfying any Federal income tax obligation. The actions described in clauses (a), (b) and (c) of this paragraph (2) shall be Restricted Payments that shall be permitted to be taken in accordance with this paragraph (2) but shall reduce the amount that would otherwise be available for Restricted Payments under clause (c) of paragraph (1) (provided, that any dividend paid pursuant to clause (a) of this paragraph (2) shall reduce the amount that would otherwise be available under clause (c) of paragraph (1) when declared, but not also when subsequently paid pursuant to such clause (a)), and the actions described in clauses (d) and (e) of this paragraph (2) shall be Restricted Payments that shall be permitted to be taken in accordance with this paragraph and shall not reduce the amount that would otherwise be available for Restricted Payments under clause (c) of paragraph (1). (3) In computing Consolidated Net Income of the Company under paragraph (1) above: (a) the Company shall use audited financial statements for the portions of the relevant period for which audited financial statements are available on the date of determination and unaudited financial statements and other current financial data based on the books and records of the Company for the remaining portion of such period and (b) the Company shall be permitted to rely in good faith on the financial statements and other financial data derived from the books and records of the Company that are available on the date of determination. If the Company makes a Restricted Payment which, at the time of the making of such Restricted Payment, would in the good faith determination of the Company be permitted under the requirements of the Indenture, such Restricted Payment shall be deemed to have been made in compliance with the Indenture notwithstanding any subsequent adjustments made in good faith to the Company's financial statements affecting Consolidated Net Income of the Company for any period. 86 87 Limitation on Issuances and Sales of Restricted Subsidiary Capital Stock. The Company: (1) will not permit any Restricted Subsidiary to issue any Preferred Stock (other than to the Company or a Wholly Owned Restricted Subsidiary) and (2) will not permit any Person (other than the Company and/or one or more Wholly Owned Restricted Subsidiaries) to own any Capital Stock of any Restricted Subsidiary; provided, however, that this covenant shall not prohibit: (1) the issuance and sale of all, but not less than all, of the issued and outstanding Capital Stock of any Restricted Subsidiary owned by the Company or any of its Restricted Subsidiaries in compliance with the other provisions of the Indenture, (2) the ownership by directors of directors' qualifying shares, (3) the ownership by any Person of Capital Stock of a Restricted Subsidiary that was owned by a Person at the time such Restricted Subsidiary became a Restricted Subsidiary or acquired by a Person in connection with the formation of the Restricted Subsidiary (including, in each case, any Capital Stock issued as a result of a stock split, a dividend of shares of Capital Stock to holders of such Capital Stock, a recapitalization affecting such Capital Stock or similar event) and (4) the ownership by any Person of Capital Stock of any Foreign Subsidiary so long as none of the Capital Stock of that Subsidiary has been issued in a public offering. Limitation on Transactions with Affiliates. The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, enter into any transaction or series of related transactions (including, without limitation, the sale, purchase, exchange or lease of assets, property or the rendering of any services) with, or for the benefit of, any Affiliate of the Company other than a Restricted Subsidiary (each, other than a Restricted Subsidiary, being an "Interested Person"), unless: (1) such transaction or series of transactions is on terms that are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that would be available in a comparable arm's length transaction with unrelated third parties who are not Interested Persons, or, in the event no comparable transaction with an unrelated third party who is not an Interested Person is available, on terms that are fair from a financial point of view to the Company or such Restricted Subsidiary, as the case may be, (2) with respect to any one transaction or series of related transactions involving aggregate payments in excess of $10,000,000, the Company delivers an Officers' Certificate to the Trustee certifying that such transaction or series of transactions complies with clause (1) above and such transaction or series of transactions has been approved by the Board of Directors and (3) with respect to any one transaction or series of related transactions involving aggregate payments in excess of $20,000,000, the Officers' Certificate referred to in clause (2) above also includes a certification that such transaction or series of transactions has been approved by a majority of the Disinterested Directors (either of the full Board of Directors or, in the case of action by a committee thereof, of such committee) or, in the event there are no such Disinterested Directors, that the Company has obtained a written opinion from an independent nationally recognized investment banking firm or appraisal firm, in either case specializing or having a specialty in the type and subject matter of the transaction or series of related transactions at issue, which opinion shall be to the effect set forth in clause (1) above; 87 88 provided, however, that this covenant will not restrict the Company from: (1) paying reasonable and customary regular compensation and fees to directors of the Company who are not employees of the Company or any Restricted Subsidiary, (2) paying dividends on, or making distributions with respect to, shares of Capital Stock of the Company on a pro rata basis to the extent permitted by the covenant described above under the caption "-- Limitation on Restricted Payments," (3) making Restricted Payments that are permitted by the provisions of the Indenture described above under the caption "-- Limitation on Restricted Payments," (4) making loans or advances to officers, directors and employees of the Company or any Restricted Subsidiary in the ordinary course of business and consistent with customary practices in the Oil and Gas Business in an aggregate amount not to exceed $1,000,000 outstanding at any one time, (5) making any indemnification or similar payment to any director or officer (a) in accordance with the corporate charter or bylaws of the Company or any Restricted Subsidiary, (b) under any agreement or (c) under applicable law and (6) fulfilling obligations of the Company or any Restricted Subsidiary under employee compensation and other benefit arrangements entered into or provided for in the ordinary course of business. Limitation on Liens. The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create, incur, assume, affirm or suffer to exist or become effective any Lien of any kind, except for Permitted Liens, on or with respect to any of its property or assets (including any intercompany notes), whether owned at the date of the Indenture or thereafter acquired, or any income, profits or proceeds therefrom, or assign or otherwise convey any right to receive income thereon, unless: (1) in the case of any Lien securing Subordinated Indebtedness, the notes are secured by a Lien on such property, assets or proceeds that is senior in priority to such Lien and (2) in the case of any other Lien, the notes are directly secured equally and ratably with the obligation or liability secured by such Lien. The incurrence of additional secured Indebtedness by the Company or any Restricted Subsidiary is subject to further limitations on the incurrence of Indebtedness as described above under the caption "-- Limitation on Indebtedness." Change of Control. Upon the occurrence of a Change of Control, the Company shall be obligated to make an offer to purchase all of the notes then outstanding (a "Change of Control Offer"), and shall purchase, on a business day (the "Change of Control Purchase Date") not more than 75 nor less than 30 days following the Change of Control, all of the notes then outstanding that are validly tendered pursuant to such Change of Control Offer at a purchase price (the "Change of Control Purchase Price") equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the Change of Control Purchase Date. The Change of Control Offer is required to remain open for at least 20 Business Days and until the close of business on the Change of Control Purchase Date. In order to effect such Change of Control Offer, the Company shall, not later than the 30th day after the Change of Control, mail to each Holder of a note a notice of the Change of Control Offer, which notice shall govern 88 89 the terms of the Change of Control Offer and shall state, among other things, the procedures that Holders of the notes must follow to accept the Change of Control Offer. If a Change of Control Offer is made, there can be no assurance that the Company will have available funds sufficient to pay the Change of Control Purchase Price for all of the notes delivered by Holders of the notes seeking to accept the Change of Control Offer. If on a Change of Control Purchase Date the Company does not have available funds sufficient to pay the Change of Control Purchase Price or is prohibited from purchasing the notes, an Event of Default will occur under the Indenture. Moreover, the definition of Change of Control includes a phrase relating to the sale or other disposition of the Company's properties and assets "substantially as an entirety." Although there is a developing body of case law interpreting phrases such as "substantially as an entirety," there is no precise established definition of such phrases under applicable law. Accordingly, the ability of a Holder of the notes to require the Company to repurchase such notes as a result of a sale or other disposition of less than all of the properties and assets of the Company on a consolidated basis to another Person or related group of Persons may be uncertain. 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 at the same purchase price, at the same times and otherwise in substantial compliance with the requirements 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 Company intends to comply with Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder, if applicable, in the event that a Change of Control occurs and the Company is required to purchase notes as described above. The existence of a Holder's right to require, subject to certain conditions, the Company to repurchase its notes upon a Change of Control may deter a third party from acquiring the Company in a transaction that constitutes, or results in, a Change of Control. Limitation on Disposition of Proceeds of Asset Sales. (1) The Company will not, and will not permit any Restricted Subsidiary to, engage in any Asset Sale unless (a) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Sale at least equal to the fair market value of the assets and properties sold or otherwise disposed of pursuant to the Asset Sale (as determined by the Board of Directors, whose determination shall be conclusive and evidenced by a resolution) and (b) at least 75% of the consideration received by the Company or the Restricted Subsidiary, as the case may be, in respect of such Asset Sale consists of cash, Cash Equivalents and/or the assumption by the purchaser of liabilities of the Company (other than liabilities of the Company that are by their terms subordinated to the notes) or any Restricted Subsidiary as a result of which the Company and its remaining Restricted Subsidiaries are no longer liable. (2) If the Company or any Restricted Subsidiary engages in an Asset Sale, the Company may either: (a) apply the Net Cash Proceeds thereof to reduce Senior Indebtedness, to reduce Guarantor Senior Indebtedness or to reduce Indebtedness of any Restricted Subsidiary incurred pursuant to clause (13) of the definition of Permitted Subsidiary Indebtedness, provided, if any such Senior Indebtedness, Guarantor Senior Indebtedness or Permitted Subsidiary Indebtedness has been incurred under any revolving credit facility, that the related commitment to lend or the amount available to be reborrowed under such facility is also reduced, or (b) invest all or any part of the Net Cash Proceeds thereof, within 365 days after such Asset Sale, in properties and assets which replace the properties and assets that were the subject of the Asset Sale or in properties and assets that will be used in the business of the Company or its Restricted Subsidiaries, as the case may be ("Replacement Assets"). The amount of such Net Cash Proceeds not applied or invested as provided in this paragraph constitutes "Excess Proceeds." (3) When the aggregate amount of Excess Proceeds equals or exceeds $15,000,000, the Company shall make an offer to purchase, from all Holders of the notes and any then outstanding Pari Passu Indebtedness 89 90 required to be repurchased or repaid on a permanent basis in connection with an Asset Sale, an aggregate principal amount of notes and any then outstanding Pari Passu Indebtedness equal to such Excess Proceeds as follows: (a) (i) the Company shall make an offer to purchase (a "Net Proceeds Offer") from all Holders of the notes in accordance with the procedures set forth in the Indenture the maximum principal amount (expressed as a multiple of $1,000) of notes that may be purchased out of an amount (the "Payment Amount") equal to the product of such Excess Proceeds, multiplied by a fraction, the numerator of which is the outstanding principal amount of the notes and the denominator of which is the sum of the outstanding principal amount of the notes and such Pari Passu Indebtedness, if any (subject to proration in the event such amount is less than the aggregate Offered Price (as defined below) of all notes tendered), and (ii) to the extent required by such Pari Passu Indebtedness and provided there is a permanent reduction in the principal amount of such Pari Passu Indebtedness, the Company shall make an offer to purchase Pari Passu Indebtedness (a "Pari Passu Offer") in an amount (the "Pari Passu Indebtedness Amount") equal to the excess of the Excess Proceeds over the Payment Amount. (b) The offer price for the notes shall be payable in cash in an amount equal to 100% of the principal amount of the notes tendered pursuant to a Net Proceeds Offer, plus accrued and unpaid interest, if any, to the date such Net Proceeds Offer is consummated (the "Offered Price"), in accordance with the procedures set forth in the Indenture. To the extent that the aggregate Offered Price of the notes tendered pursuant to a Net Proceeds Offer is less than the Payment Amount relating thereto or the aggregate amount of the Pari Passu Indebtedness that is purchased or repaid pursuant to the Pari Passu Offer is less than the Pari Passu Indebtedness Amount (such shortfall constituting a "Net Proceeds Deficiency"), the Company may use such Net Proceeds Deficiency for general corporate purposes, subject to the limitations described above under the caption "-- Limitation on Restricted Payments." (c) If the aggregate Offered Price of notes validly tendered and not withdrawn by Holders thereof exceeds the Payment Amount, notes to be purchased will be selected on a pro rata basis. Upon completion of such Net Proceeds Offer and Pari Passu Offer, the amount of Excess Proceeds shall be reset to zero. The Company intends to comply with Rule 14e-1 under the Exchange Act, and any other securities laws and regulations thereunder, if applicable, in the event that an Asset Sale occurs and the Company is required to purchase notes as described above. The Credit Agreement may prohibit the Company from purchasing any notes from Excess Proceeds. Any future credit agreements or other agreements relating to Senior Indebtedness to which the Company becomes a party may contain similar restrictions. In the event a Net Proceeds Offer occurs at a time when the Company is prohibited by the terms of any Senior Indebtedness from purchasing the notes, the Company could seek the consent of the holders of such Senior Indebtedness to the purchase or could attempt to refinance such Senior Indebtedness. If the Company does not obtain such a consent or repay such Senior Indebtedness, the Company may remain prohibited from purchasing the 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 and possibly a default under other agreements relating to Senior Indebtedness. In such circumstances, the subordination provisions in the Indenture would likely restrict payments to the Holders of the notes. Limitation on Non-Guarantor Restricted Subsidiaries. (1) The Company will not permit any Restricted Subsidiary that is not a Subsidiary Guarantor to guarantee the payment of any Indebtedness of the Company unless (a)(i) such Restricted Subsidiary simultaneously executes and delivers a supplemental indenture to the Indenture providing for a Subsidiary Guarantee of the notes by such Restricted Subsidiary which Subsidiary Guarantee will be subordinated to Guarantor Senior Indebtedness (but no other Indebtedness) to the same extent that the notes are subordinated to Senior Indebtedness and (ii), with respect to any guarantee of Subordinated Indebtedness by a Restricted Subsidiary, any such guarantee shall be subordinated 90 91 to such Restricted Subsidiary's Subsidiary Guarantee at least to the same extent as such Subordinated Indebtedness is subordinated to the notes; (b) such Restricted Subsidiary waives, and agrees not in any manner whatsoever to claim or take the benefit or advantage of, any rights of reimbursement, indemnity or subrogation or any other rights against the Company or any other Restricted Subsidiary as a result of any payment by such Restricted Subsidiary under its Subsidiary Guarantee until such time as the obligations guaranteed thereby are paid in full; and (c) such Restricted Subsidiary shall deliver to the Trustee an Opinion of Counsel to the effect that such Subsidiary Guarantee has been duly executed and authorized and constitutes a valid, binding and enforceable obligation of such Restricted Subsidiary, except insofar as enforcement thereof (i) may be limited by bankruptcy, insolvency or similar laws (including, without limitation, all laws relating to fraudulent transfers and fraudulent conveyances), (ii) is subject to general principles of equity and (iii) any implied covenant of good faith or fair dealing. (2) Notwithstanding the foregoing and the other provisions of the Indenture, each Subsidiary Guarantee shall provide by its terms that it shall be automatically and unconditionally released and discharged upon (a) (i) any sale, exchange or transfer of all the Capital Stock in the applicable Subsidiary Guarantor owned by the Company and any Restricted Subsidiary or (ii) any sale, assignment, conveyance, transfer, lease or other disposition of the properties and assets of such Subsidiary Guarantor substantially as an entirety, in each case, in a single transaction or series of related transactions to any Person that is not a Restricted Subsidiary (provided, that such transaction or series of transactions is not prohibited by the Indenture), (b) the merger or consolidation of such Subsidiary Guarantor with or into the Company or a Restricted Subsidiary (provided, that, in the case of a merger into or consolidation with a Restricted Subsidiary that is not then a Subsidiary Guarantor, the surviving Restricted Subsidiary assumes the Subsidiary Guarantee and that transaction or series of transactions is not prohibited by the Indenture) or (c) the release or discharge of all guarantees by such Subsidiary Guarantor of Indebtedness other than the Note Obligations, except a discharge or release by or as a result of the payment of such Indebtedness by such Subsidiary Guarantor pursuant to its Subsidiary Guarantee. Limitation on Dividends and Other Payment Restrictions Affecting Restricted Subsidiaries. The Company will not, and will not permit any Restricted Subsidiary to, directly or indirectly, create or otherwise cause or suffer to exist or become effective any consensual encumbrance or restriction of any kind on the ability of any Restricted Subsidiary to: (1) pay dividends, in cash or otherwise, or make any other distributions on or in respect of its Capital Stock to the Company or any Restricted Subsidiary, (2) pay any Indebtedness owed to the Company or any Restricted Subsidiary, (3) make an Investment in the Company or any Restricted Subsidiary or (4) transfer any of its properties or assets to the Company or any Restricted Subsidiary; except for such encumbrances or restrictions: (a) pursuant to any agreement in effect or entered into on the date of the Indenture, (b) pursuant to any agreement or other instrument of a Person acquired by the Company or any Restricted Subsidiary in existence at the time of such acquisition (but not created in contemplation thereof), which encumbrance or restriction is not applicable to any other Person, or the properties or assets of any other Person, other than the Person, or the property or assets of the Person, so acquired, (c) by reason of customary non-assignment provisions in leases and licenses entered into in the ordinary course of business, 91 92 (d) pursuant to capital leases and purchase money obligations for property leased or acquired in the ordinary course of business that impose restrictions of the nature described in clause (4) above on the property so leased or acquired, (e) pursuant to any merger agreements, stock purchase agreements, asset sale agreements and similar agreements limiting the transfer of properties and assets pending consummation of the subject transaction, (f) pursuant to Permitted Liens which are customary limitations on the transfer of collateral, (g) pursuant to applicable law, (h) pursuant to agreements among holders of Capital Stock of any Restricted Subsidiary of the Company requiring distributions in respect of such Capital Stock to be made pro rata based on the percentage of ownership in and/or contribution to such Restricted Subsidiary or (i) existing under any agreement that extends, renews, refinances or replaces the agreements containing the restrictions in the preceding clauses (a) and (b), provided, that the terms and conditions of any such restrictions are not materially less favorable to the Holders of the notes than those under or pursuant to the agreement evidencing the Indebtedness so extended, renewed, refinanced or replaced. Limitation on Other Senior Subordinated Indebtedness. The Company will not incur, directly or indirectly, any Indebtedness which is expressly subordinate or junior in right of payment in any respect to Senior Indebtedness unless such Indebtedness ranks pari passu in right of payment with the notes, or is expressly subordinated in right of payment to the notes. Reports. The Company (and the Subsidiary Guarantors, if applicable) must file on a timely basis with the SEC, to the extent such filings are accepted by the SEC and whether or not the Company has a class of securities registered under the Exchange Act, the annual reports, quarterly reports and other documents that the Company would be required to file if it were subject to Section 13 or 15(d) of the Exchange Act. The Company is (and any future Subsidiary Guarantors will be) also required: (1) to file with the Trustee, and provide to each Holder of notes, 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 SEC or the date on which the Company (and the Subsidiary Guarantors, if applicable) would be required to file such reports and documents if the Company (and the Subsidiary Guarantors, if applicable) were so required and (2) if filing such reports and documents with the SEC is not accepted by the SEC or is prohibited under the Exchange Act, to furnish at the Company's cost copies of such reports and documents to any Holder of notes promptly upon written request. The Company is obligated to make available, upon request, to any Holder of notes or prospective purchaser the information required by Rule 144A(d)(4) under the Securities Act, during any period in which the Company is not subject to Section 13 or 15(d) of the Exchange Act and for so long as the transfer of any note is restricted under the Securities Act. Future Designation of Restricted and Unrestricted Subsidiaries. The preceding covenants, including calculation of financial ratios and the determination of limitations on the incurrence of Indebtedness and Liens, may be affected by the designation by the Company of any existing or 92 93 future Subsidiary of the Company as an Unrestricted Subsidiary. Generally, a Restricted Subsidiary includes any Subsidiary of the Company, whether existing on or after the date of the Indenture, unless the Subsidiary of the Company is designated as an Unrestricted Subsidiary pursuant to the terms of the Indenture. The definition of "Unrestricted Subsidiary" set forth below under the caption "-- Certain Definitions" describes the circumstances under which a Subsidiary of the Company may be designated as an Unrestricted Subsidiary by the Board of Directors. CONSOLIDATION, MERGER, ETC. The Company will not, in any single transaction or series of related transactions, consolidate or merge with or into any other Person, or sell, assign, convey, transfer, lease or otherwise dispose of the properties and assets of the Company and its Restricted Subsidiaries substantially as an entirety on a consolidated basis to any Person, and the Company will not permit any Restricted Subsidiary to enter into any transaction or series of related transactions if such transaction or series of transactions would result in a sale, assignment, conveyance, transfer, lease or other disposition of the properties and assets of the Company and its Restricted Subsidiaries substantially as an entirety on a consolidated basis to any Person, unless at the time and after giving effect thereto: (1) either (a) if the transaction or series of related transactions is a merger or consolidation, the Company shall be the surviving Person of such merger or consolidation, or (b) the Person, if other than the Company, formed by such consolidation or into which the Company or such Restricted Subsidiary is merged or to which the properties and assets of the Company or such Restricted Subsidiary, as the case may be, are sold, assigned, conveyed, transferred, leased or otherwise disposed of (any such surviving Person or transferee Person being the "Surviving Entity") shall be a corporation organized and existing under the laws of the United States of America, any state thereof or the District of Columbia and shall, in either case, expressly assume by a supplemental indenture to the Indenture executed and delivered to the Trustee, in form satisfactory to the Trustee, all the obligations of the Company under the notes and the Indenture, and, in each case, the Indenture shall remain in full force and effect; (2) immediately before and immediately after giving effect to such transaction or series of transactions on a pro forma basis (and treating any Indebtedness not previously an obligation of Company or any of its Restricted Subsidiaries in connection with or as a result of such transaction or series of transactions as having been incurred at the time of such transaction or series of transactions), no Default or Event of Default shall have occurred and be continuing; (3) except in the case of the consolidation or merger of any Restricted Subsidiary with or into the Company, immediately after giving effect to such transaction or series of transactions on a pro forma basis, the Consolidated Net Worth of the Company (or the Surviving Entity if the Company is not the continuing obligor under the Indenture) is at least equal to the Consolidated Net Worth of the Company immediately before such transaction or series of transactions; (4) except in the case of the consolidation or merger of (a) any Restricted Subsidiary with or into the Company or any Wholly Owned Restricted Subsidiary or (b) the Company with or into any Person that has no Indebtedness outstanding, immediately before and immediately after giving effect to such transaction or series of transactions on a pro forma basis (on the assumption that the transaction or series of transactions occurred on the first day of the period of four fiscal quarters ending immediately prior to the consummation of such transaction or series of transactions, with the appropriate adjustments with respect to such transaction or series transactions being included in such pro forma calculation), the Company, or the Surviving Entity if the Company is not the continuing obligor under the Indenture, could incur $1.00 of additional Indebtedness, other than Permitted Indebtedness, pursuant to the covenant described above under the caption "--Limitation on Indebtedness;" 93 94 (5) each Subsidiary Guarantor, unless it is the other party to the transactions or series of transactions described above, shall have by supplemental indenture to the Indenture confirmed that its Subsidiary Guarantee shall apply to such Person's obligations under the Indenture and the notes; and (6) if any of the properties or assets of the Company or any Restricted Subsidiary would upon such transaction or series of transactions become subject to any Lien, other than a Permitted Lien, the creation and imposition of such Lien shall have been in compliance with the covenant described above under the caption "-- Limitation on Liens." In connection with any consolidation, merger, transfer, lease or other disposition contemplated hereby, the Company shall deliver, or cause to be delivered, to the Trustee, in form and substance reasonably satisfactory to the Trustee, an Officers' Certificate stating that such consolidation, merger, transfer, lease or other disposition and the supplemental indenture in respect thereto comply with the requirements under the Indenture and an Opinion of Counsel stating that the requirements of clause (1) of the preceding paragraph have been complied with. Upon any such consolidation or merger or any such sale, assignment, transfer, lease or other disposition substantially as an entirety on a consolidated basis of the properties and assets of the Company in accordance with the foregoing in which the Company is not the continuing Person, the Surviving Entity shall succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture with the same effect as if the Surviving Entity had been named as the Company therein, and thereafter the Company, except in the case of a lease, will be discharged from all obligations and covenants under the Indenture and the notes. EVENTS OF DEFAULT The following are "Events of Default" under the Indenture: (1) default in the payment of the principal of or premium, if any, on any of the notes, whether such payment is due at maturity, upon redemption, upon repurchase pursuant to a Change of Control Offer or a Net Proceeds Offer, upon acceleration or otherwise; or (2) default in the payment of any installment of interest on any of the notes, when it becomes due and payable, and the continuance of such default for a period of 30 days; or (3) default in the performance or breach of the provisions of the "Consolidation, Merger, Etc." section of the Indenture, the failure to make or consummate a Change of Control Offer in accordance with the provisions of the Indenture described under the caption "-- Change of Control" or the failure to make or consummate a Net Proceeds Offer in accordance with the provisions of the Indenture described under the caption "-- Limitation on Disposition of Proceeds of Asset Sales;" or (4) the Company or any Subsidiary Guarantor shall fail to perform or observe any other term, covenant or agreement contained in the notes, any Subsidiary Guarantee or the Indenture (other than a default specified in (1), (2) or (3) above) for a period of 45 days after written notice of such failure requiring the Company to remedy the same shall have been given (a) to the Company by the Trustee or (b) to the Company and the Trustee by the holders of at least 25% in aggregate principal amount of the notes then outstanding; or (5) the occurrence and continuation beyond any applicable grace period of any default in the payment of the principal of (or premium, if any, on) or interest on any Indebtedness of the Company (other than the notes or any Non-Recourse Indebtedness) or any Restricted Subsidiary for money borrowed when due, or any other default causing acceleration of any Indebtedness (other than Non-Recourse Indebtedness) of the Company or any Restricted Subsidiary for money borrowed, provided that the aggregate principal amount of such Indebtedness shall exceed $12,000,000; provided further, that if any such default is cured or waived or any such acceleration rescinded, or such Indebtedness is repaid, within a period of 10 days from the continuation of such default beyond the applicable grace period or the occurrence of such acceleration, as the case may be, such Event of Default under the Indenture and any 94 95 consequential acceleration of the notes shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree; or (6) the commencement of proceedings, or the taking of any enforcement action, including by way of set-off, by any holder of at least $12,000,000 in aggregate principal amount of Indebtedness, other than Non- Recourse Indebtedness, of the Company or any Restricted Subsidiary, after a default under such Indebtedness, to retain in satisfaction of such Indebtedness or to collect or seize, dispose of or apply in satisfaction of such Indebtedness, property or assets of the Company or any Restricted Subsidiary having a fair market value (as determined by the Board of Directors) in excess of $12,000,000 individually or in the aggregate, provided, that if any such proceedings or actions are terminated or rescinded, or such Indebtedness is repaid, such Event of Default under the Indenture and any consequential acceleration of the notes shall be automatically rescinded, so long as (a) such rescission does not conflict with any judgment or decree and (b) the holder of such Indebtedness shall not have applied any such property or assets in satisfaction of such Indebtedness; or (7) any Subsidiary Guarantee shall for any reason cease to be, or be asserted by the Company or any Subsidiary Guarantor, as applicable, not to be, in full force and effect, enforceable in accordance with its terms (except pursuant to the release of any such Subsidiary Guarantee in accordance with the Indenture); or (8) certain events giving rise to ERISA liability; or (9) final judgments or orders rendered against the Company or any Restricted Subsidiary that are unsatisfied and that require the payment in money, either individually or in an aggregate amount, that is more than $12,000,000 over the coverage under applicable insurance policies and either (a) commencement by any creditor of an enforcement proceeding upon such judgment (other than a judgment that is stayed by reason of pending appeal or otherwise) or (b) the occurrence of a 60-day period during which a stay of such judgment or order, by reason of pending appeal or otherwise, was not in effect; or (10) the entry of a decree or order by a court having jurisdiction in the premises (a) for relief in respect of the Company or any Material Restricted Subsidiary in an involuntary case or proceeding under any applicable federal or state bankruptcy, insolvency, reorganization or other similar law or (b) adjudging the Company or any Material Restricted Subsidiary bankrupt or insolvent, or approving a petition seeking reorganization, arrangement, adjustment or composition of the Company or a Material Restricted Subsidiary under any applicable federal or state law, or appointing under any such law a custodian, receiver, liquidator, assignee, trustee, sequestrator or other similar official of the Company or any Material Restricted Subsidiary or of a substantial part of their consolidated assets, or ordering the winding up or liquidation of their affairs, and the continuance of any such decree or order for relief or any such other decree or order unstayed and in effect for a period of 60 consecutive days; or (11) the commencement by the Company or any Material Restricted Subsidiary of a voluntary case or proceeding under any applicable federal or state bankruptcy, insolvency, reorganization or other similar law or any other case or proceeding to be adjudicated bankrupt or insolvent, or the consent by the Company or any Material Restricted Subsidiary to the entry of a decree or order for relief in respect thereof in an involuntary case or proceeding under any applicable federal or state bankruptcy, insolvency, reorganization or other similar law or to the commencement of any bankruptcy or insolvency case or proceeding against it, or the filing by the Company or any Material Restricted Subsidiary of a petition or consent seeking reorganization or relief under any applicable federal or state law, or the consent by it under any such law to the filing of any such petition or to the appointment of or taking possession by a custodian, receiver, liquidator, assignee, trustee or sequestrator (or other similar official) of any of the Company or any Material Restricted Subsidiary or of any substantial part of their consolidated assets, or the making by it of an assignment for the benefit of creditors under any such law. If an Event of Default (other than as specified in clause (10) or (11) above) shall occur and be continuing, the Trustee, by written notice to the Company, or the holders of at least 25% in aggregate principal amount of the notes then outstanding, by notice to the Trustee and the Company, may declare the principal of, premium, if any, and accrued interest on all of the notes then outstanding due and payable immediately, upon which declaration all 95 96 amounts payable in respect of the notes shall be immediately due and payable. If an Event of Default specified in clause (10) or (11) above occurs and is continuing, then the principal of, premium, if any, and accrued interest on all of the notes then outstanding shall ipso facto become and be immediately due and payable without any declaration, notice or other act on the part of the Trustee or any Holder of notes. After a declaration of acceleration under the Indenture, but before a judgment or decree for payment of the money due has been obtained by the Trustee, the Holders of a majority in aggregate principal amount of the notes then outstanding, by written notice to the Company and the Trustee, may rescind such declaration if: (1) the Company or any Subsidiary Guarantor has paid or deposited with the Trustee a sum sufficient to pay: (a) all sums paid or advanced by the Trustee under the Indenture and the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, (b) all overdue interest on all notes then outstanding, (c) the unpaid principal of and premium, if any, on any notes which have become due otherwise than by such declaration of acceleration, including any securities required to have been purchased pursuant to a Change of Control Offer or a Net Proceeds Offer, as applicable, and interest thereon at the rate borne by the notes, and (d) to the extent that payment of such interest is lawful, interest upon overdue interest and overdue principal at the rate borne by the notes which has become due otherwise than by such declaration of acceleration; (2) the rescission would not conflict with any judgment or decree of a court of competent jurisdiction; and (3) all Events of Default, other than the nonpayment of principal of, premium, if any, and interest on the notes that has become due solely by such declaration of acceleration, have been cured or waived. The Holders of not less than a majority in aggregate principal amount of the notes then outstanding may on behalf of the Holders of all the notes waive any past defaults under the Indenture, except a default in the payment of the principal of (or premium, if any, on) or interest on any note or a default in respect of a covenant or provision which under the Indenture cannot be modified or amended without the consent of the Holder of each note then outstanding affected thereby. No Holder of any of the notes has any right to institute any proceeding with respect to the Indenture or any remedy thereunder, unless such Holder has previously given written notice to the Trustee of a continuing Event of Default, the Holders of at least 25% in aggregate principal amount of the notes then outstanding have made written request, and offered reasonable indemnity, to the Trustee to institute such proceeding as Trustee under the notes and the Indenture, the Trustee has failed to institute such proceeding within 60 days after receipt of such notice and offer of indemnity and the Trustee, within such 60-day period, has not received directions inconsistent with such written request by Holders of a majority in aggregate principal amount of the notes then outstanding. Such limitations do not apply, however, to a suit instituted by a Holder of a note for the enforcement of the payment of the principal of, premium, if any, or interest on such note on or after the respective due dates expressed in such note. During the existence of an Event of Default, the Trustee is required to exercise such of the rights and powers vested in it under the Indenture, and use the same degree of care and skill in its exercise, as a prudent person would exercise or use under the circumstances in the conduct of such person's own affairs. Subject to the provisions of the Indenture relating to the duties of the Trustee, the Trustee under the Indenture is not under any obligation to exercise any of its rights or powers under the Indenture at the request or direction of any Holders of the notes unless such Holders shall have offered to the Trustee reasonable security or indemnity. Subject to certain provisions in the Indenture relating to the rights of the Trustee, the Holders of a majority in aggregate principal amount of the notes 96 97 then outstanding have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee under the Indenture. If a Default or an Event of Default occurs and is known to the Trustee, the Trustee shall mail to each Holder of notes notice of the Default or Event of Default within 60 days after the occurrence thereof in the manner and to the extent provided in Section 313(c) of the Trust Indenture Act. Except in the case of a Default or an Event of Default in payment of principal of, premium, if any, or interest on any notes, the Trustee may withhold the notice to the Holders of such notes if and so long as the board of directors, the executive committee, or a trust committee of directors and/or responsible officers of the Trustee in good faith determine that the withholding of such notice is in the interest of the Holders of the notes. The Company is required to furnish to the Trustee annual and quarterly statements as to the performance by the Company of its obligations under the Indenture and as to any default in such performance. The Company is also required to notify the Trustee within ten days after any Default. LEGAL DEFEASANCE OR COVENANT DEFEASANCE OF INDENTURE The Company may, at its option and at any time, terminate the obligations of the Company and the Subsidiary Guarantors with respect to the notes then outstanding ("legal defeasance"). Such legal defeasance means that the Company and the Subsidiary Guarantors shall be deemed to have paid and discharged the entire Indebtedness represented by the notes then outstanding, except for: (1) the rights of Holders of notes then outstanding to receive payment in respect of the principal of, premium, if any, on and interest on such notes when such payments are due, (2) the Company's obligations to issue temporary notes, register the transfer or exchange of any notes, replace mutilated, destroyed, lost or stolen notes and maintain an office or agency for payments in respect of the notes, (3) the rights, powers, trusts, duties and immunities of the Trustee, and (4) the defeasance provisions of the Indenture. In addition, the Company may, at its option and at any time, elect to terminate the obligations of the Company and any Subsidiary Guarantor with respect to certain covenants that are set forth in the Indenture, some of which are described above under the caption "-- Certain Covenants," and any omission to comply with such obligations shall not constitute a Default or an Event of Default with respect to the notes ("covenant defeasance"). In order to exercise either legal defeasance or covenant defeasance: (1) the Company or any Subsidiary Guarantor must irrevocably deposit, with the Trustee, in trust, for the benefit of the holders of the notes, cash in United States dollars, U.S. Government Obligations (as defined in the Indenture), or a combination thereof, in such amounts as will be sufficient, in the opinion of a nationally recognized firm of independent public accountants, to pay the principal of, premium, if any, on and interest on the notes then outstanding to redemption or maturity; (2) the Company shall have delivered to the Trustee an Opinion of Counsel to the effect that the Holders of the notes then outstanding will not recognize income, gain or loss for federal income tax purposes as a result of such legal defeasance or covenant defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such legal defeasance or covenant defeasance had not occurred (in the case of legal defeasance, such opinion must refer to and be based upon a published ruling of the Internal Revenue Service or a change in applicable federal income tax laws); 97 98 (3) no Default or Event of Default shall have occurred and be continuing on the date of such deposit; (4) such legal defeasance or covenant defeasance shall not cause the Trustee to have a conflicting interest under the Indenture or the Trust Indenture Act with respect to any securities of the Company or any Subsidiary Guarantor; (5) such legal defeasance or covenant defeasance shall not result in a breach or violation of, or constitute a default under, any material agreement or instrument to which the Company or any Subsidiary Guarantor is a party or by which it is bound; and (6) the Company shall have delivered to the Trustee an Officers' Certificate and an Opinion of Counsel satisfactory to the Trustee, which, taken together, state that all conditions precedent under the Indenture to either legal defeasance or covenant defeasance, as the case may be, have been complied with and that no violations under agreements governing any other outstanding Indebtedness would result therefrom. SATISFACTION AND DISCHARGE The Indenture will be discharged and will cease to be of further effect (except as to surviving rights or registration of transfer or exchange of the notes, as expressly provided for in the Indenture) as to all notes then outstanding when: (1) either (a) all the notes theretofore authenticated and delivered (except lost, stolen or destroyed notes which have been replaced or paid and notes for whose payment money has theretofore been deposited in trust or segregated and held in trust by the Company and thereafter repaid to the Company or discharged from such trust) have been delivered to the Trustee for cancellation or (b) all notes not theretofore delivered to the Trustee for cancellation have become due and payable or will become due and payable at their Stated Maturity within one year, or are to be called for redemption within one year under arrangements satisfactory to the Trustee for the serving of notice of redemption by the Trustee in the name, and at the expense, of the Company, and the Company has irrevocably deposited or caused to be deposited with the Trustee funds in an amount sufficient to pay and discharge the entire indebtedness on the notes not theretofore delivered to the Trustee for cancellation, for principal of (and premium, if any, on) and interest on the notes to the date of deposit (in the case of notes which have become due and payable) or to the Stated Maturity or Redemption Date, as the case may be, together with instructions from the Company irrevocably directing the Trustee to apply such funds to the payment thereof at maturity or redemption, as the case may be; (2) the Company has paid all other sums payable under the Indenture by the Company; and (3) the Company has delivered to the Trustee an Officers' Certificate and an Opinion of Counsel satisfactory to the Trustee, which, taken together, state that all conditions precedent under the Indenture relating to the satisfaction and discharge of the Indenture have been complied with and that no violations under agreements governing any other outstanding Indebtedness would result therefrom. AMENDMENTS From time to time, the Company and the Trustee may, without the consent of the Holders of the notes, modify, amend or supplement the Indenture or the notes for certain specified purposes, including, among other things, curing ambiguities, defects or inconsistencies, qualifying, or maintaining the qualification of, the Indenture under the Trust Indenture Act, provided that such change does not adversely affect the rights of any Holder of the notes. Other modifications and amendments of the Indenture or the notes may be made by the Company, the Subsidiary Guarantors and the Trustee with the consent of the Holders of not less than a majority of the aggregate principal amount of the notes then outstanding; provided, however, that no such modification or amendment may, without the consent of the Holder of each note then outstanding affected thereby: 98 99 (1) change the Stated Maturity of the principal of, or any installment of interest on any note, (2) reduce the principal amount of (or the premium, if any, on) or interest on any note, (3) change the place, coin or currency of payment of principal of (or the premium, if any, on) or interest on, any note, (4) impair the right to institute suit for the enforcement of any payment on or with respect to any note, (5) reduce the above-stated percentage of aggregate principal amount of notes then outstanding necessary to modify or amend the Indenture, (6) reduce the percentage of aggregate principal amount of notes then outstanding necessary for waiver of compliance with certain provisions of the Indenture or for waiver of certain defaults under the Indenture, (7) modify or amend any provisions of the Indenture relating to the modification and amendment of the Indenture or relating to the waiver of past defaults or covenants, except as otherwise specified, (8) modify or amend any provision of the Indenture relating to Subsidiary Guarantees in a manner adverse to the Holders or (9) modify or amend the obligation of the Company to make and consummate a Change of Control Offer in the event of a Change of Control or to make and consummate the Net Proceeds Offer with respect to any Asset Sale or modify any of the provisions or definitions with respect thereto. THE TRUSTEE Prior to a Default, the Trustee shall not be liable except for the performance of such duties as are specifically set out in the Indenture. If an Event of Default has occurred and is continuing, the Trustee will exercise such rights and powers vested in it under the Indenture, and use the same degree of care and skill in its exercise, as a prudent person would exercise or use under the circumstances in the conduct of such person's own affairs. The Indenture and the Trust Indenture Act contain limitations on the rights of the Trustee thereunder, should it become a creditor of the Company, to obtain payment of claims in certain cases or to realize on certain property received by it in respect of any such claims, as security or otherwise. The Trustee is permitted to engage in other transactions; provided, however, that if it acquires any conflicting interest (as defined in the Trust Indenture Act) it must eliminate such conflict or resign. State Street Bank and Trust Company is also trustee under indentures for the 2007 Notes and the 2006 Notes. Pursuant to the Trust Indenture Act, should a default occur with respect to either the notes or the 2006 Notes, State Street Bank and Trust Company would be required to resign as trustee under either the Indenture and the indenture for the 2007 Notes or the indenture for the 2006 Notes within 90 days of such default unless such default were cured, duly waived or otherwise eliminated. GOVERNING LAW The Indenture, the notes and the Subsidiary Guarantees provide that they will be governed by the laws of the State of New York. CERTAIN DEFINITIONS "Acquired Indebtedness" means Indebtedness of a Person: 99 100 (1) assumed in connection with an Asset Acquisition from such Person, (2) outstanding at the time such Person becomes a Subsidiary of any other Person (other than any Indebtedness incurred in connection with, or in contemplation of, such Asset Acquisition or such Person becoming such a Subsidiary) or (3) any renewals, extensions, substitutions, refinancings or replacements (each, for purposes of this clause, a "refinancing") by the Company of any Indebtedness described in clause (1) or (2) of this definition, including any successive refinancings, so long as (a) any such new Indebtedness shall be in a principal amount that does not exceed the principal amount (or, if such Indebtedness being refinanced provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration thereof, such lesser amount as of the date of determination) so refinanced plus the amount of any premium required to be paid in connection with such refinancing pursuant to the terms of the Indebtedness refinanced or the amount of any premium reasonably determined by the Company as necessary to accomplish such refinancing, plus the amount of expenses of the Company incurred in connection with such refinancing, (b) in the case of any refinancing of Subordinated Indebtedness, such new Indebtedness is made subordinate to the notes at least to the same extent as the Indebtedness being refinanced and (c) such new Indebtedness has an Average Life longer than the Average Life of the notes and a final Stated Maturity later than the final Stated Maturity of the notes. "Adjusted Consolidated Net Tangible Assets" means, without duplication, as of the date of determination: (1) the sum of: (a) discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated by a nationally recognized firm of independent petroleum engineers in a reserve report prepared as of the end of the Company's most recently completed fiscal year, as increased by, as of the date of determination, the estimated discounted future net revenues from (i) estimated proved oil and gas reserves acquired since the date of such year-end reserve report, and (ii) estimated oil and gas reserves attributable to upward revisions of estimates of proved oil and gas reserves since the date of such year-end reserve report due to exploration, development or exploitation activities, in each case calculated in accordance with SEC guidelines (using the prices utilized in such year-end reserve report), and decreased by, as of the date of determination, the estimated discounted future net revenues from (iii) estimated proved oil and gas reserves produced or disposed of since the date of such year-end reserve report and (iv) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since the date of such year-end reserve report due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated in accordance with SEC guidelines (using the prices utilized in such year-end reserve report); provided, that in the case of each of the determinations made pursuant to clauses (i) through (iv), such increases and decreases shall be as estimated by the Company's petroleum engineers, except that in the event there is a Material Change as a result of such acquisitions, dispositions or revisions, then the discounted future net revenues used for purposes of this clause (1) (a) shall be confirmed in writing by a nationally recognized firm of independent petroleum engineers, (b) the capitalized costs that are attributable to oil and gas properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company's 100 101 books and records as of a date no earlier than the date of the Company's latest annual or quarterly financial statements, (c) the Net Working Capital on a date no earlier than the date of the Company's latest annual or quarterly financial statements and (d) the greater of (i) the net book value on a date no earlier than the date of the Company's latest annual or quarterly financial statements or (ii) the appraised value, as estimated by independent appraisers, of other tangible assets (including, without duplication, Investments in unconsolidated Restricted Subsidiaries) of the Company and its Restricted Subsidiaries, as of the date no earlier than the date of the Company's latest audited financial statements, (2) minus the sum of (a) minority interests (other than a minority interest in a Subsidiary that is a business trust or similar entity formed for the primary purpose of issuing preferred securities the proceeds of which are loaned to the Company or a Restricted Subsidiary), (b) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company's latest audited financial statements, (c) to the extent included in (1) (a) above, the discounted future net revenues, calculated in accordance with SEC guidelines (using the prices utilized in the Company's year-end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments on the schedules specified with respect thereto and (d) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (1) (a) above, would be necessary to fully satisfy the payment obligations of the Company and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments on the schedules specified with respect thereto. If the Company changes its method of accounting from the successful efforts method to the full cost method or a similar method of accounting, "Adjusted Consolidated Net Tangible Assets" will continue to be calculated as if the Company were still using the successful efforts method of accounting. "Affiliate" means, with respect to any specified Person, any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, "control," when used with respect to any Person, means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms "controlling" and "controlled" have meanings correlative to the foregoing. For purposes of this definition, beneficial ownership of 10% or more of the voting common equity (on a fully diluted basis) or options or warrants to purchase such equity (but only if exercisable at the date of determination or within 60 days thereof) of a Person shall be deemed to constitute control of such Person. No Person shall be deemed an Affiliate of an oil and gas royalty trust solely by virtue of ownership of units of beneficial interest in such trust. "Asset Acquisition" means: (1) an Investment by the Company or any Restricted Subsidiary in any other Person pursuant to which such Person shall become a Restricted Subsidiary or any Restricted Subsidiary shall be merged with or into the Company or any Restricted Subsidiary or 101 102 (2) the acquisition by the Company or any Restricted Subsidiary of the properties and assets of any Person which constitute all or substantially all of the properties and assets of such Person or any division or line of business of such Person. "Asset Sale" means any sale, issuance, conveyance, transfer, lease or other disposition to any Person other than the Company or any of its Restricted Subsidiaries (including by means of a Sale/Leaseback Transaction or by way of merger or consolidation) (collectively, for purposes of this definition, a "transfer"), directly or indirectly, in one or a series of related transactions, of: (1) any Capital Stock of any Restricted Subsidiary held by the Company or any Restricted Subsidiary; (2) the properties and assets of any division or line of business of the Company or any of its Restricted Subsidiaries substantially as an entirety; or (3) any other properties or assets of the Company or any of its Restricted Subsidiaries other than a disposition of hydrocarbons or other mineral products in the ordinary course of business. For the purposes of this definition, the term "Asset Sale" shall not include: (1) any transfer of properties or assets that is governed by, and made in accordance with, the provisions described under the caption "-- Consolidation, Merger, etc." (2) any transfer of properties or assets to any Person, if permitted under the provisions described under the caption "-- Limitation on Restricted Payments;" (3) any trade or exchange of properties and assets used in the Oil and Gas Business of the Company or any Restricted Subsidiary or shares of Capital Stock in any Person in the Oil and Gas Business owned by the Company or any Restricted Subsidiary for properties and assets used in the Oil and Gas Business of any Person or shares of Capital Stock in any Person owned or held by another Person, provided, that: (a) the fair market value of the properties, assets and shares traded or exchanged by the Company or such Restricted Subsidiary (including any cash or Cash Equivalents, not to exceed 15% of such fair market value, to be delivered by the Company or such Restricted Subsidiary) is reasonably equivalent to the fair market value of the properties, assets and shares of Capital Stock (together with any cash or Cash Equivalents, not to exceed 15% of such fair market value) to be received by the Company or such Restricted Subsidiary as determined in good faith by (i) any officer of the Company if such fair market value is less than $5,000,000 and (ii) the Board of Directors of the Company as certified by a certified resolution delivered to the Trustee if such fair market value is equal to or in excess of $5,000,000; provided, that if such fair market value is equal to or in excess of $10,000,000 the Company shall deliver a written appraisal by a nationally recognized investment banking firm or appraisal firm, in each case specializing or having a speciality in oil and gas properties, and (b) such exchange is approved by a majority of the Disinterested Directors; or (4) any transfer of properties or assets in a single transaction or series of related transactions having a fair market value of less than $5,000,000. "Attributable Indebtedness" means, with respect to any particular lease under which any Person is at the time liable and at any date as of which the amount thereof is to be determined, the present value of the total net amount of rent required to be paid by such Person under the lease during the primary term thereof, without giving effect to any renewals at the option of the lessee, discounted from the respective due dates thereof to such date of determination at the rate of interest per annum implicit in the terms of the lease. As used in the preceding sentence, 102 103 the "net amount of rent" under any lease for any such period shall mean the sum of rental and other payments required to be paid with respect to such period by the lessee thereunder, excluding any amounts required to be paid by such lessee on account of maintenance and repairs, insurance, taxes, assessments, water rates or similar charges. In the case of any lease which is terminable by the lessee upon payment of a penalty, such net amount of rent shall also include the amount of such penalty, but no rent shall be considered as required to be paid under such lease subsequent to the first date upon which it may be so terminated. "Average Life" means, with respect to any Indebtedness, as at any date of determination, the quotient obtained by dividing: (1) the sum of the products of (a) the number of years (and any portion thereof) from the date of determination to the date or dates of each successive scheduled principal payment (including, without limitation, any sinking fund or mandatory redemption payment requirements) of such Indebtedness multiplied by (b) the amount of each such principal payment by (2) the sum of all such principal payments. "Board of Directors" means: (1) with respect to the Company, either the board of directors of the Company or any properly constituted committee thereof that is (a) authorized to take the action in question and (b) comprised of members, a majority of whom are not officers or employees of the Company or any Subsidiary of the Company, and (2) with respect to any Restricted Subsidiary, the board of directors of that Restricted Subsidiary or any properly constituted committee thereof that is authorized to take the action in question. "Capital Stock" means, with respect to any Person, any and all shares, interests, participations, rights in or other equivalents in the equity interests (however designated) in such Person, and any rights (other than debt securities convertible into an equity interest), warrants or options exercisable for, exchangeable for or convertible into such an equity interest in such Person. "Capitalized Lease Obligation" means any obligation to pay rent or other amounts under a lease of, or other agreement conveying the right to use, any property (whether real, personal or mixed) that is required to be classified and accounted for as a capital lease obligation under GAAP, and, for the purpose of the Indenture, the amount of such obligation at any date shall be the capitalized amount thereof at such date, determined in accordance with GAAP. "Cash Equivalents" means: (1) any evidence of Indebtedness with a maturity of 365 days or less issued or directly and fully guaranteed or insured by the United States of America or any agency or instrumentality thereof (provided, that the full faith and credit of the United States of America is pledged in support thereof), (2) demand and time deposits and certificates of deposit or acceptances with a maturity of 365 days or less of any financial institution that is a member of the Federal Reserve System having combined capital and surplus and undivided profits of not less than $100,000,000 or any commercial bank organized under the laws of any country other than the United States of America that is a member of the Organization for Economic Cooperation and Development ("OECD") and has total assets in excess of $100,000,000, (3) commercial paper with a maturity of 365 days or less issued by a Person that is not an Affiliate of the Company and is organized under the laws of any state of the United States of America or the District of Columbia and rated at least A-1 by S&P or at least P-1 by Moody's (or, if at any time neither S&P nor 103 104 Moody's shall be rating such obligations, then from such other rating service as may be acceptable to the Trustee), (4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clause (1) above entered into with any commercial bank meeting the specifications of clause (2) above, (5) overnight bank deposits and bankers' acceptances at any commercial bank meeting the qualifications specified in clause (2) above, and (6) investments in money market mutual or similar funds which have assets in excess of $500,000,000. "Change of Control" means the occurrence of any of the following events: (1) the Company's properties and assets are sold or otherwise disposed of substantially as an entirety on a consolidated basis to any Person or related group of Persons in any one transaction or a series of related transactions; (2) there shall be consummated any consolidation or merger of the Company (a) in which the Company is not the continuing or surviving Person (other than a consolidation or merger with a wholly owned Subsidiary of the Company in which all shares of Common Stock outstanding immediately prior to the effectiveness thereof are changed into or exchanged for the same number of shares of Common Stock of such Subsidiary) or (b) pursuant to which the Common Stock would be converted into cash, securities or other property, in each case, other than a consolidation or merger of the Company in which the holders of the Common Stock immediately prior to the consolidation or merger have, directly or indirectly, at least a majority of the Common Stock of the continuing or surviving Person immediately after such consolidation or merger; or (3) any Person or any Persons acting together which would constitute a "group" for purposes of Section 13(d) of the Exchange Act (other than the Company, any Subsidiary of the Company, any employee stock purchase plan, stock option plan or other stock incentive plan or program, retirement plan or automatic dividend reinvestment plan or any substantially similar plan of the Company or any Subsidiary of the Company or any Person holding securities of the Company for or pursuant to the terms of any such employee benefit plan), together with any Affiliates thereof, shall acquire beneficial ownership (as defined in Rule 13d-3 under the Exchange Act) of at least 50% of the Voting Stock of the Company. "Common Stock" of any Person means Capital Stock of such Person that does not rank prior, as to the payment of dividends or as to the distribution of assets upon any voluntary or involuntary liquidation, dissolution or winding up of such Person, to shares of Capital Stock of any other class of such Person. "Consolidated Fixed Charge Coverage Ratio" means, for any period, the ratio of: (1) the sum of Consolidated Net Income, Consolidated Interest Expense, Consolidated Income Tax Expense and Consolidated Non-cash Charges deducted in computing Consolidated Net Income, in each case, for such period, of the Company and its Restricted Subsidiaries on a consolidated basis, all determined in accordance with GAAP, decreased (to the extent included in determining Consolidated Net Income) by the sum of (a) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments and (b) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments, to 104 105 (2) the sum of such Consolidated Interest Expense for such period; provided, that: (a) in making such computation, the Consolidated Interest Expense attributable to interest on any Indebtedness required to be computed on a pro forma basis in accordance with clause (1) of the covenant described under the caption "-- Limitation on Indebtedness" and bearing a floating interest rate shall be computed as if the rate in effect on the date of computation had been the applicable rate for the entire period, (b) in making such computation, the Consolidated Interest Expense attributable to interest on any Indebtedness under a revolving credit facility required to be computed on a pro forma basis in accordance with clause (1) of the covenant described under the caption "--Limitation on Indebtedness" shall be computed based upon the average daily balance of such Indebtedness during the applicable period, provided, that such average daily balance shall be reduced by the amount of any repayment of Indebtedness under a revolving credit facility during the applicable period, which repayment permanently reduced the commitments or amounts available to be reborrowed under such facility, (c) notwithstanding clauses (a) and (b) of this proviso, interest on Indebtedness determined on a fluctuating basis, to the extent such interest is covered by agreements relating to Interest Rate Protection Obligations, shall be deemed to have accrued at the rate per annum resulting after giving effect to the operation of such agreements and (d) in making such calculation, Consolidated Interest Expense shall exclude interest attributable to Dollar-Denominated Production Payments. "Consolidated Income Tax Expense" means, for any period, the provision for federal, state, local and foreign income taxes of the Company and its Restricted Subsidiaries for such period as determined on a consolidated basis in accordance with GAAP. "Consolidated Interest Expense" means, for any period, without duplication, the sum of: (1) the interest expense of the Company and its Restricted Subsidiaries for such period as determined on a consolidated basis in accordance with GAAP, including, without limitation: (a) any amortization of debt discount, (b) the net cost under Interest Rate Protection Obligations (including any amortization of discounts), (c) the interest portion of any deferred payment obligation, (d) all commissions, discounts and other fees and charges owed with respect to letters of credit and bankers' acceptance financing and (e) all accrued interest, in each case to the extent attributable to such period, (2) to the extent any Indebtedness of any Person (other than the Company or a Restricted Subsidiary) is guaranteed by the Company or any Restricted Subsidiary, the aggregate amount of interest paid or accrued by such other Person during such period attributable to any such Indebtedness, in each case to the extent attributable to that period, (3) the aggregate amount of the interest component of Capitalized Lease Obligations paid, accrued and/or scheduled to be paid or accrued by the Company and its Restricted Subsidiaries during such period as determined on a consolidated basis in accordance with GAAP and 105 106 (4) the aggregate amount of dividends paid or accrued on Redeemable Capital Stock or Preferred Stock of the Company and its Restricted Subsidiaries, to the extent such Redeemable Capital Stock or Preferred Stock is owned by Persons other than Restricted Subsidiaries. "Consolidated Net Income" means, for any period, the consolidated net income (or loss) of the Company and its Restricted Subsidiaries for such period as determined in accordance with GAAP, adjusted by excluding: (1) net after-tax extraordinary gains or losses (less all fees and expenses relating thereto), (2) net after-tax gains or losses (less all fees and expenses relating thereto) attributable to Asset Sales, (3) the net income (or net loss) of any Person (other than the Company or any of its Restricted Subsidiaries), in which the Company or any of its Restricted Subsidiaries has an ownership interest, except to the extent of the amount of dividends, interest on indebtedness or other distributions actually paid to the Company or its Restricted Subsidiaries in cash by such other Person during such period (regardless of whether such cash dividends, interest on indebtedness or other distributions is attributable to net income (or net loss) of such Person during such period or during any prior period), (4) net income (or net loss) of any Person combined with the Company or any of its Restricted Subsidiaries on a "pooling of interests" basis attributable to any period prior to the date of combination, (5) the net income of any Restricted Subsidiary to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary is not at the date of determination permitted, directly or indirectly, by operation of the terms of its charter or any agreement, instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, (6) income resulting from transfers of assets received by the Company or any Restricted Subsidiary from an Unrestricted Subsidiary and (7) any write-downs of non-current assets; provided, however, that any ceiling limitation write-downs under SEC guidelines shall be treated as capitalized costs, as if such write-downs had not occurred. "Consolidated Net Worth" means, at any date, the consolidated stockholders' equity of the Company less the amount of such stockholders' equity attributable to Redeemable Capital Stock or treasury stock of the Company and its Restricted Subsidiaries, as determined in accordance with GAAP. "Consolidated Non-cash Charges" means, for any period, the aggregate depreciation, depletion, amortization, impairment and other non-cash expenses of the Company and its Restricted Subsidiaries reducing Consolidated Net Income for such period, determined on a consolidated basis in accordance with GAAP (excluding any such non-cash charge which requires an accrual of or reserve for cash charges for any future period). "Credit Agreement" means the Amended and Restated Credit Agreement dated August 1, 1997, among the Company and Bank of Montreal and Banque Paribas, as co-agents, and the other banks specified therein, including any notes and guarantees executed in connection therewith, as such agreement has been and may be amended, modified, supplemented, extended, restated, replaced (including replacement after the termination of such agreement), restructured, increased, renewed or refinanced from time to time in one or more credit agreements, loan agreements, instruments or similar agreements, whether or not with the same lenders or agents, as such may be further amended, modified, supplemented, extended, restated, replaced (including replacement after the termination of such agreement), restructured, increased, renewed or refinanced from time to time. "Credit Agreement Obligations" means all monetary obligations of every nature of the Company or a Restricted Subsidiary, including without limitation, obligations to pay principal and interest, reimbursement 106 107 obligations under letters of credit, fees, expenses and indemnities, from time to time owed to the lenders or any agent under or in respect of the Credit Agreement. "Default" means any event, act or condition that is, or after notice or passage of time or both would be, an Event of Default. "Designated Senior Indebtedness" means: (1) all Senior Indebtedness constituting Credit Agreement Obligations and (2) any other Senior Indebtedness which (a) at the time of incurrence equals or exceeds $10,000,000 in aggregate principal amount and (b) is specifically designated by the Company in the instrument evidencing such Senior Indebtedness as "Designated Senior Indebtedness" for purpose of the Indenture. "Disinterested Director" means, with respect to any transaction or series of transactions in respect of which the Board of Directors is required to deliver its resolution under the Indenture, a member of the Board of Directors who does not have any material direct or indirect financial interest (other than an interest arising solely from the beneficial ownership of Capital Stock of the Company) in or with respect to such transaction or series of transactions. "Dollar-Denominated Production Payments" means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith. "Event of Default" has the meaning set forth above under the caption "Events of Default." "Foreign Subsidiary" means: (1) any Restricted Subsidiary engaged in the Oil and Gas Business having the majority of its operations outside the United States of America, irrespective of its jurisdiction of organization, and (2) any other Restricted Subsidiary whose assets (excluding any cash and Cash Equivalents) consist exclusively of Capital Stock or Indebtedness of one or more Restricted Subsidiaries described in clause (1) of this definition. "GAAP" means generally accepted accounting principles, consistently applied, that are set forth in the opinions and pronouncements of the Accounting Principles Board of the American Institute of Certified Public Accountants and statements and pronouncements of the Financial Accounting Standards Board or in such other statements by such other entity as may be approved by a significant segment of the accounting profession of the United States of America, which are applicable as of the date of the Indenture. "guarantee" means, as applied to any obligation: (1) a guarantee (other than by endorsement of negotiable instruments for collection in the ordinary course of business), direct or indirect, in any manner, of any part or all of such obligation and (2) an agreement, direct or indirect, contingent or otherwise, the practical effect of which is to assure in any way the payment or performance (or payment of damages in the event of nonperformance) of all or any part of such obligation, including, without limiting the foregoing, the payment of amounts drawn down by letters of credit. When used as a verb, "guarantee" shall have a corresponding meaning. 107 108 "Guarantor Senior Indebtedness" means all Indebtedness of a Subsidiary Guarantor created, incurred, assumed or guaranteed by such Subsidiary Guarantor (and all renewals, substitutions, refinancings or replacements thereof) (including the principal of, interest on and fees, premiums, expenses (including costs of collection), indemnities and other amounts payable in connection with such Indebtedness) (and including, in the case of the Credit Agreement, interest accruing after the filing of a petition by or against such Subsidiary Guarantor under any bankruptcy law, in accordance with and at the rate, including any default rate, specified with respect to such Indebtedness, whether or not a claim for such interest is allowed as a claim after such filing in any proceeding under such bankruptcy law), unless the instrument governing such Indebtedness expressly provides that such Indebtedness is not senior in right of payment to its Subsidiary Guarantee. Notwithstanding the foregoing, Guarantor Senior Indebtedness of a Subsidiary Guarantor will not include: (1) Indebtedness of such Subsidiary Guarantor evidenced by its Subsidiary Guarantee, (2) Indebtedness of such Subsidiary Guarantor that is expressly subordinated or junior in right of payment to any Guarantor Senior Indebtedness of such Subsidiary Guarantor or its Subsidiary Guarantee, (3) Indebtedness which, when incurred and without respect to any election under Section 1111(b) of Title 11 United States Code, is by its terms without recourse to such Subsidiary Guarantor or Non-Recourse Indebtedness, (4) any repurchase, redemption or other obligation in respect of Redeemable Capital Stock of such Subsidiary Guarantor, (5) to the extent it might constitute Indebtedness, any liability for federal, state, local or other taxes owed or owing by such Subsidiary Guarantor, (6) Indebtedness of such Subsidiary Guarantor to the Company or any of the Company's other Subsidiaries or any other Affiliate of the Company or any of such Affiliate's Subsidiaries and (7) that portion of any Indebtedness of such Subsidiary Guarantor which at the time of issuance is issued in violation of the Indenture (but, as to any such Indebtedness, no such violation shall be deemed to exist for purposes of this clause (7) if the holder(s) of such Indebtedness or their representative or such Subsidiary Guarantor shall have furnished to the Trustee an Opinion of Counsel, addressed to the Trustee (which counsel may, as to matters of fact, rely upon a certificate of such Subsidiary Guarantor) to the effect that the incurrence of such Indebtedness does not violate the provisions of such Indenture); provided, that the foregoing exclusions shall not affect the priorities of any Indebtedness arising solely by operation of law in any case or proceeding or similar event described in clause (1), (2) or (3) of the second paragraph under the caption "-- Subordination." "Hedging Obligations" means obligations of any Person arising out of hedging transactions entered into in the ordinary course of business, including, without limitation, swaps, options, forward sales and futures contracts entered into in connection with interest rates, currencies and energy-related commodities. "Holder" means a Person in whose name a note is registered in the Note Register. "Indebtedness" means, with respect to any Person, without duplication: (1) all liabilities of such Person for borrowed money or for the deferred purchase price of property or services, excluding any trade accounts payable and other accrued current liabilities incurred in the ordinary course of business, but including, without limitation, all obligations, contingent or otherwise, of such Person in connection with any letters of credit, bankers' acceptance or other similar credit transaction and in connection with any agreement to purchase, redeem, exchange, convert or otherwise acquire for value any 108 109 Capital Stock of such Person, or any warrants, rights or options to acquire such Capital Stock, now or hereafter outstanding, if, and to the extent, any of the foregoing would appear as a liability upon a balance sheet of such Person prepared in accordance with GAAP, (2) all obligations of such Person evidenced by bonds, notes, debentures or other similar instruments, if, and to the extent, any of the foregoing would appear as a liability upon a balance sheet of such Person prepared in accordance with GAAP, (3) all Indebtedness of such Person created or arising under any conditional sale or other title retention agreement with respect to property acquired by such Person (even if the rights and remedies of the seller or lender under such agreement in the event of default are limited to repossession or sale of such property), but excluding trade accounts payable arising in the ordinary course of business, (4) all Capitalized Lease Obligations of such Person, (5) the Attributable Indebtedness (in excess of any related Capitalized Lease Obligations) related to any Sale/Leaseback Transaction of such Person, (6) all Indebtedness referred to in the preceding clauses of other Persons and all dividends of other Persons, the payment of which is secured by (or for which the holder of such Indebtedness has an existing right, contingent or otherwise, to be secured by) any Lien upon property (including, without limitation, accounts and contract rights) owned by such Person, even though such Person has not assumed or become liable for the payment of such Indebtedness (the amount of such obligation being deemed to be the lesser of the value of such property or asset or the amount of the obligation so secured), (7) all guarantees by such Person of Indebtedness referred to in this definition (including, with respect to any Production Payment, any warranties or guarantees of production or payment by such Person with respect to such Production Payment but excluding other contractual obligations of such Person with respect to such Production Payment), (8) all Redeemable Capital Stock of such Person valued at the greater of its voluntary or involuntary maximum fixed repurchase price plus accrued dividends, (9) all obligations of such Person under or in respect of currency exchange contracts and Interest Rate Protection Obligations and (10) any amendment, supplement, modification, deferral, renewal, extension or refunding of any liability of such Person of the types referred to in clauses (1) through (9) above. For purposes hereof, the "maximum fixed repurchase price" of any Redeemable Capital Stock which does not have a fixed repurchase price shall be calculated in accordance with the terms of such Redeemable Capital Stock as if such Redeemable Capital Stock were purchased on any date on which Indebtedness shall be required to be determined pursuant to the Indenture, and if such price is based upon, or measured by, the fair market value of such Redeemable Capital Stock, such fair market value shall be determined in good faith by the board of directors of the issuer of such Redeemable Capital Stock, provided, however, that if such Redeemable Capital Stock is not at the date of determination permitted or required to be repurchased, the "maximum fixed repurchase price" shall be the book value of such Redeemable Capital Stock. Subject to clause (7) of the first sentence of this definition, neither Dollar-Denominated Production Payments nor Volumetric Production Payments shall be deemed to be Indebtedness. "Interest Rate Protection Obligations" means the obligations of any Person pursuant to any arrangement with any other Person whereby, directly or indirectly, such Person is entitled to receive from time to time periodic payments calculated by applying either a floating or a fixed rate of interest on a stated notional amount in exchange for periodic payments made by such Person calculated by applying a fixed or a floating rate of interest on the same 109 110 notional amount and includes, without limitation, interest rate swaps, caps, floors, collars and similar agreements or arrangements designed to protect against or manage such Person's and any of its Subsidiaries' exposure to fluctuations in interest rates. "Investment" means, with respect to any Person, any direct or indirect advance, loan, guarantee of Indebtedness or other extension of credit or capital contribution to (by means of any transfer of cash or other property or assets to others or any payment for property, assets or services for the account or use of others), or any purchase or acquisition by such Person of any Capital Stock, bonds, notes, debentures or other securities (including derivatives) or evidences of Indebtedness issued by, any other Person. In addition, the fair market value of the net assets of any Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary shall be deemed to be an "Investment" made by the Company in such Unrestricted Subsidiary at such time. "Investments" shall exclude: (1) extensions of trade credit on commercially reasonable terms in accordance with normal trade practices and (2) Interest Rate Protection Obligations entered into in the ordinary course of business or as required by any Permitted Indebtedness, Permitted Subsidiary Indebtedness or any Indebtedness incurred in compliance with the covenant described above under the caption "-- Limitation on Indebtedness," but only to the extent that the notional principal amount of such Interest Rate Protection Obligations does not exceed 105% of the principal amount of such Indebtedness to which such Interest Rate Protection Obligations relate and (3) bonds, notes, debentures or other securities received in compliance with the covenant described under the caption "-- Limitation on Disposition of Proceeds of Asset Sales." "Lien" means any mortgage, charge, pledge, lien (statutory or other), security interest, hypothecation, assignment for security, claim, or preference or priority or other encumbrance or similar agreement or preferential arrangement of any kind or nature whatsoever (including, without limitation, any agreement to give or grant a Lien or any lease, conditional sale or other title retention agreement having substantially the same economic effect as any of the foregoing) upon or with respect to any property of any kind; provided, however, "Lien" shall not include rights created in a third Person in connection with the creation by the Company or a Subsidiary of a Production Payment. A Person shall be deemed to own subject to a Lien any property which such Person has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement. "Material Change" means an increase or decrease (excluding changes that result solely from changes in prices) of more than 50% during a fiscal quarter in the estimated discounted future net cash flows from proved oil and gas reserves of the Company and its Restricted Subsidiaries, calculated in accordance with clause (1) (a) of the definition of Adjusted Consolidated Net Tangible Assets; provided, however, that the following will be excluded from the calculation of Material Change: (1) any acquisitions during the quarter of oil and gas reserves that have been estimated by a nationally recognized firm of independent petroleum engineers and on which a report or reports exist and (2) any disposition of properties held at the beginning of such quarter that have been disposed of as provided in the covenant described under the caption "-- Limitation on Disposition of Proceeds of Asset Sales." "Material Restricted Subsidiary" means, at any particular time: (1) any Subsidiary Guarantor and 110 111 (2) any other Restricted Subsidiary that, together with its Subsidiaries: (a) accounted for more than 5% of the consolidated revenues of the Company and its Restricted Subsidiaries for the most recently completed fiscal year of the Company or (b) was the owner of more than 5% of the consolidated assets of the Company and its Restricted Subsidiaries at the end of such fiscal year, all as shown in the case of (a) and (b) on the consolidated financial statements of the Company and its Restricted Subsidiaries for such fiscal year. "Maturity" means, with respect to any note, the date on which any principal of such note becomes due and payable as provided therein or in the Indenture, whether at the Stated Maturity with respect to such principal or by declaration of acceleration, call for redemption or purchase or otherwise. "Moody's" means Moody's Investors Service, Inc. and its successors. "Net Cash Proceeds" means, with respect to any Asset Sale, the proceeds thereof received by the Company or any Restricted Subsidiary in the form of cash or Cash Equivalents (including payments in respect of deferred payment obligations when received in the form of cash or Cash Equivalents (except to the extent that such obligations are financed or sold with recourse to the Company or any Restricted Subsidiary)), net of: (1) brokerage commissions and other fees and expenses (including fees and expenses of engineers, legal counsel, accountants and investment banks) related to such Asset Sale, (2) provisions for all taxes payable as a result of such Asset Sale, (3) amounts required to be paid (a) to any minority interest holder or other Person (other than the Company or any Restricted Subsidiary) owning a beneficial interest in the assets subject to the Asset Sale or (b) in respect of any Indebtedness (other than Indebtedness under the Credit Agreement) secured by a Lien on any of the properties or assets that were the subject of such Asset Sale and (4) appropriate amounts to be provided by the Company or any Restricted Subsidiary, as the case may be, as a reserve required in accordance with GAAP consistently applied against any liabilities associated with such Asset Sale and retained by the Company or any Restricted Subsidiary, as the case may be, after such Asset Sale, including, without limitation, pension and other post-employment benefit liabilities, liabilities related to environmental matters and liabilities under any indemnification obligations associated with such Asset Sale, all as reflected in an Officers' Certificate delivered to the Trustee; provided, however, that any amounts remaining after adjustments, revaluations or liquidations of such reserves shall constitute Net Cash Proceeds. "Net Working Capital" means: (1) all current assets of the Company and its Restricted Subsidiaries, minus (2) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness, in each case as set forth in financial statements of the Company prepared in accordance with GAAP. "Non-Recourse Indebtedness" means Indebtedness or that portion of Indebtedness of the Company or a Restricted Subsidiary incurred in connection with the acquisition by the Company or a Restricted Subsidiary of any property or assets and as to which: 111 112 (1) the holders of such Indebtedness agree that they will look solely to the property or assets so acquired and securing such Indebtedness for payment on or in respect of such Indebtedness and (2) no default with respect to such Indebtedness would permit (after notice or passage of time or both), according to the terms of any other Indebtedness of the Company or a Restricted Subsidiary, any holder of such other Indebtedness to declare a default under such other Indebtedness or cause the payment of such other Indebtedness to be accelerated or payable prior to its stated maturity. "Note Obligations" means any principal of, premium, if any, and interest on, and any other amounts (including, without limitation, any payment obligations with respect to the notes as a result of any Asset Sale, Change of Control or redemption) owing in respect of, the notes payable pursuant to the terms of the notes or the Indenture or upon acceleration of the notes. "Note Register" means the register maintained by or for the Company in which the Company shall provide for the registration of the notes and of transfer of the notes. "Officers' Certificate" means a certificate delivered to the Trustee signed by the Chairman, the President, a Vice President or the Chief Financial Officer, and by the Treasurer, an Assistant Treasurer, the Secretary or an Assistant Secretary of the Company. "Oil and Gas Business" means: (1) the acquisition, exploration, exploitation, development, operation and disposition of interests in oil, gas and other hydrocarbon properties, (2) the gathering, marketing, treating, processing, storage, refining, selling and transporting of any production from such interests or properties, (3) any business relating to or arising from exploration for or exploitation, development, production, treatment, processing, storage, refining, transportation or marketing of oil, gas and other minerals and products produced in association therewith, (4) any power generation and electrical transmission business in a jurisdiction outside North America where fuel required by such business is supplied, directly or indirectly, from hydrocarbons produced substantially from properties in which the Company or its Restricted Subsidiaries, directly or indirectly, participates and (5) any activity necessary, appropriate or incidental to the activities described in the preceding clauses (1) through (4) of this definition. "Opinion of Counsel" means a written opinion of legal counsel for the Company (or any Subsidiary Guarantor, if applicable) including an employee of the Company (or any Subsidiary Guarantor, if applicable), who is reasonably acceptable to the Trustee. "Pari Passu Indebtedness" means: (1) the Company's 8 3/4% Senior Subordinated Notes due 2007 issued under the Indenture dated as of May 15, 1997 between the Company and Fleet National Bank (now State Street Bank and Trust Company), as Trustee, and (2) any other Indebtedness of the Company that is pari passu in right of payment to the notes. "Permitted Indebtedness" means any of the following: 112 113 (1) Indebtedness of the Company under one or more bank credit or revolving credit facilities in an aggregate principal amount at any one time outstanding not to exceed: (a) the greater of: (i) $270,000,000 and (ii) an amount equal to the sum of (A) $170,000,000 and (B) 10% of Adjusted Consolidated Net Tangible Assets determined as of the date of the most recent quarterly consolidated financial statements of the Company and its Restricted Subsidiaries, less (b) the amount of Net Cash Proceeds applied to reduce Indebtedness pursuant to the covenant of the Indenture described under the caption "-- Limitation on Disposition of Proceeds of Asset Sales" (together with interest and fees under such facilities, the "Maximum Credit Amount," with the Maximum Credit Amount being an aggregate maximum amount for the Company and all Guarantor Subsidiaries, pursuant to clause (1) of the definition of "Permitted Subsidiary Indebtedness"), and any renewals, amendments, extensions, supplements, modifications, deferrals, refinancings or replacements (each, for purposes of this clause, a "refinancing") thereof by the Company, including any successive refinancings thereof by the Company, so long as the aggregate principal amount of any such new Indebtedness, together with the aggregate principal amount of all other Indebtedness outstanding pursuant to this clause (1) (and clause (1) of the definition of "Permitted Subsidiary Indebtedness"), shall not at any one time exceed the Maximum Credit Amount; (2) Indebtedness of the Company under the notes; (3) Indebtedness of the Company outstanding on the date of the Indenture (and not repaid or defeased with the proceeds of the Company's sale of the outstanding notes); (4) obligations of the Company pursuant to Interest Rate Protection Obligations, but only to the extent such obligations do not exceed 105% of the aggregate principal amount of the Indebtedness covered by such Interest Rate Protection Obligations; obligations under currency exchange contracts entered into in the ordinary course of business; and Hedging Obligations; (5) Indebtedness of the Company to any Restricted Subsidiaries; (6) in-kind obligations relating to net gas balancing positions arising in the ordinary course of business and consistent with past practice; (7) Indebtedness in respect of bid, performance or surety bonds issued or other reimbursement obligations for the account of the Company in the ordinary course of business, including guarantees and letters of credit supporting such bid, performance, surety bonds or other reimbursement obligations (in each case other than for an obligation for money borrowed); (8) Non-Recourse Indebtedness; (9) Indebtedness incurred in respect of any letters of credit in the ordinary course of business of the Company or reimbursement obligations in respect thereof; (10) any renewals, extensions, substitutions, refinancings or replacements (each, for purposes of this clause, a "refinancing") by the Company of any Indebtedness of the Company described in clauses (2) or (3) above, including any successive refinancings by the Company, so long as (a) any such new Indebtedness shall be in a principal amount that does not exceed the principal amount (or, if such Indebtedness being refinanced provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration thereof, such lesser amount as of the date of determination) so refinanced plus the amount of any premium required to be paid in connection with such refinancing pursuant to the terms of the Indebtedness refinanced or the amount of any premium reasonably determined by the Company as necessary to accomplish such refinancing, plus the amount of expenses of the Company incurred in connection with such refinancing, and (b) in the case of any refinancing of 113 114 Subordinated Indebtedness, such new Indebtedness is made subordinate to the notes at least to the same extent as the Indebtedness being refinanced and (c) such new Indebtedness has an Average Life equal to or longer than the Average Life of the Indebtedness being refinanced and a final Stated Maturity equal to or later than the final Stated Maturity of the Indebtedness being refinanced; (11) other Indebtedness of the Company in an aggregate principal amount not in excess of $25,000,000 at any one time outstanding. "Permitted Investments" means any of the following: (1) Investments in Cash Equivalents; (2) Investments in the Company or any of its Restricted Subsidiaries; (3) Investments by the Company or any of its Restricted Subsidiaries in another Person, if as a result of such Investment (a) such other Person becomes a Restricted Subsidiary of the Company or (b) such other Person is merged or consolidated with or into, or transfers or conveys all or substantially all of its properties and assets to, the Company or a Restricted Subsidiary; (4) entry into operating agreements, joint ventures, partnership agreements, working interests, royalty interests, mineral leases, processing agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil and natural gas, unitization agreements, pooling arrangements, area of mutual interest agreements, development agreements, joint ownership arrangements and other similar or customary agreements, transactions, properties, interests and arrangements, whether or not any such Investment involves or results in the creation of a legal entity, and Investments and expenditures in connection therewith or pursuant thereto, in each case made or entered into in the ordinary course of the Company or its Restricted Subsidiaries' Oil and Gas Business; (5) entry into any arrangement pursuant to which the Company or any of its Restricted Subsidiaries may incur Hedging Obligations; and (6) other Investments having an aggregate fair market value (measured on the date each such Investment was made without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (6) that are at the time outstanding (net of repayments, dividends and distributions received with respect to such Investments), not to exceed $25,000,000 at any one time outstanding. "Permitted Liens" means the following types of Liens: (1) Liens existing as of the date the notes are first issued; (2) Liens securing the notes; (3) Liens in favor of the Company or a Subsidiary Guarantor; (4) Liens securing Senior Indebtedness or Guarantor Senior Indebtedness; (5) Liens for taxes, assessments and governmental charges or claims either (a) not delinquent or (b) contested in good faith by appropriate proceedings and as to which the Company or its Restricted Subsidiaries shall have set aside on its books such reserves as may be required pursuant to GAAP; (6) statutory Liens of landlords and Liens of carriers, warehousemen, mechanics, suppliers, materialmen, repairmen and other Liens imposed by law incurred in the ordinary course of business for sums not delinquent or being contested in good faith, if such reserve or other appropriate provision, if any, as shall be required by GAAP shall have been made in respect thereof; 114 115 (7) Liens incurred and deposits made in the ordinary course of business in connection with workers' compensation, unemployment insurance and other types of social security, and Liens incurred and deposits made to secure the payment or performance of tenders, statutory or regulatory obligations, surety and appeal bonds, bids, leases, government contracts and leases, trade contracts (other than to secure an obligation for borrowed money), performance and return of money bonds and other similar obligations (exclusive of obligations for the payment of borrowed money but including lessee and operator obligations under statutes, governmental regulations or instruments related to the ownership, exploration and production of oil, gas and minerals on state, federal or foreign lands or waters); (8) pre-judgment Liens and judgment Liens not giving rise to an Event of Default so long as any appropriate legal proceedings which may have been duly initiated for the review of such judgment shall not have been finally terminated or the period within which such proceeding may be initiated shall not have expired; (9) any interest or title of a lessor under any Capitalized Lease Obligation or operating lease; (10) Liens resulting from the deposit of funds or evidences of Indebtedness in trust for the purpose of defeasing Indebtedness of the Company or any of the Subsidiaries; customary Liens for the fees, costs and expenses of trustees and escrow agents pursuant to the indenture, escrow agreement or other similar agreement establishing such trust or escrow arrangement; and Liens pursuant to merger agreements, stock purchase agreements, asset sale agreements and similar agreements (a) limiting the transfer of properties and assets pending consummation of the subject transaction or (b) in respect of earnest money deposits, good faith deposits, purchase price adjustment escrows or similar deposits or escrow arrangements made or established thereunder; (11) Liens securing any Hedging Obligations of the Company or any Restricted Subsidiary; (12) Liens upon specific items of inventory or other goods and proceeds of any Person securing such Person's obligations in respect of bankers' acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods; (13) Liens securing reimbursement obligations with respect to commercial letters of credit which encumber documents and other property relating to such letters of credit and products and proceeds thereof; (14) Liens encumbering property or assets under construction arising from progress or partial payments by a customer of the Company or its Restricted Subsidiaries relating to such property or assets and Liens to secure Indebtedness used to finance all or a part of the construction of property or assets used by the Company or any of its Restricted Subsidiaries in the Oil and Gas Business, provided, that such Liens do not extend to any other property or assets owned by the Company or its Restricted Subsidiaries; (15) Liens encumbering deposits made to secure obligations arising from statutory, regulatory, contractual or warranty requirements of the Company or any of its Restricted Subsidiaries, including rights of offset and set-off; (16) Liens securing Interest Rate Protection Obligations which Interest Rate Protection Obligations relate to Indebtedness that is secured by Liens otherwise permitted under this Indenture; (17) Liens on, or related to, properties or assets to secure all or part of the costs incurred in the ordinary course of business for the exploration, drilling, development or operation thereof; (18) Liens on pipeline or pipeline facilities which arise out of operation of law; (19) Liens arising under operating agreements, joint venture agreements, partnership agreements, oil and gas leases, farm-out agreements, division orders, contracts for the sale, purchase, transportation, processing or exchange of oil, gas or other hydrocarbons, unitization and pooling declarations and agreements, area of mutual 115 116 interest agreements, development agreements, joint ownership arrangements and other agreements which are customary in the Oil and Gas Business; (20) Liens reserved in oil and gas mineral leases for bonus or rental payments and for compliance with the terms of such leases; (21) Liens constituting survey exceptions, encumbrances, easements, or reservations of, or rights to others for, rights-of-way, zoning restrictions and other similar charges and encumbrances as to the use of real properties, and minor defects of title which, in the case of any of the foregoing, were not incurred or created to secure the payment of borrowed money or the deferred purchase price of property, assets or services, and in the aggregate do not interfere in any material respect with the ordinary conduct of the business of the Company or its Restricted Subsidiaries; (22) rights reserved to or vested in any municipality or governmental, statutory or public authority by the terms of any right, power, franchise, grant, license or permit, or by any provision of law, to terminate such right, power, franchise, grant, license or permit or to purchase, condemn, expropriate or recapture or to designate a purchaser of any of the property of such Person; rights reserved to or vested in any municipality or governmental, statutory or public authority to control or regulate any property of such Person, or to use such property in a manner which does not materially impair the use of such property for the purposes for which it is held by such Person; any obligation or duties affecting the property of such Person to any municipality or governmental, statutory or public authority with respect to any franchise, grant, license or permit; (23) Liens securing Non-Recourse Indebtedness; provided, however, that the related Non-Recourse Indebtedness shall not be secured by any property or assets of the Company or any Restricted Subsidiary other than the property and assets acquired by the Company with the proceeds of such Non-Recourse Indebtedness; and (24) Liens securing Acquired Indebtedness; provided, however, that any such lien extends only to the properties or assets that were subject to such Lien prior to the related acquisition by the Company or such Restricted Subsidiary and was not created, incurred or assumed in contemplation of such transaction. Notwithstanding anything in clauses (1) through (24) of this definition, the term "Permitted Liens" does not include any Liens resulting from the creation, incurrence, issuance, assumption or guarantee of any Production Payments other than Production Payments that are created, incurred, issued, assumed or guaranteed in connection with the financing of, and within 30 days after, the acquisition of the properties or assets that are subject thereto. "Permitted Subsidiary Indebtedness" means any of the following: (1) Indebtedness of any Guarantor Subsidiary under one or more bank credit or revolving credit facilities (and "refinancings" thereof) in an amount at any one time outstanding not to exceed the Maximum Credit Amount (in the aggregate for all Guarantor Subsidiaries and the Company, pursuant to clause (1) of the definition of "Permitted Indebtedness"); (2) Indebtedness of any Restricted Subsidiary outstanding on the date of the Indenture; (3) obligations of any Restricted Subsidiary pursuant to Interest Rate Protection Obligations, but only to the extent such obligations do not exceed 105% of the aggregate principal amount of the Indebtedness covered by such Interest Rate Protection Obligations; and Hedging Obligations of any Restricted Subsidiary; (4) the Subsidiary Guarantees (and any assumption of the obligations guaranteed thereby); (5) Indebtedness of any Restricted Subsidiary relating to guarantees by such Restricted Subsidiary of Permitted Indebtedness; 116 117 (6) in-kind obligations relating to net gas balancing positions arising in the ordinary course of business and consistent with past practice; (7) Indebtedness in respect of bid, performance or surety bonds or other reimbursement obligations issued for the account of any Restricted Subsidiary in the ordinary course of business, including guarantees and letters of credit supporting such bid, performance, surety bonds or other reimbursement obligations (in each case other than for an obligation for money borrowed); (8) Indebtedness of any Restricted Subsidiary to any other Restricted Subsidiary or to the Company; (9) Indebtedness relating to guarantees by any Restricted Subsidiary permitted to be incurred pursuant to paragraph (a) of the provisions of the Indenture described under the caption "-- Limitation on Non-Guarantor Restricted Subsidiaries"; (10) Indebtedness incurred in respect of letters of credit in the ordinary course of business of any Restricted Subsidiary or reimbursement obligation in respect thereof; (11) Non-Recourse Indebtedness; (12) any renewals, extensions, substitutions, refinancings or replacements (each, for purposes of this clause, a "refinancing") by any Restricted Subsidiary of any Indebtedness of such Restricted Subsidiary including any successive refinancings by such Restricted Subsidiary, so long as (a) any such new Indebtedness shall be in a principal amount that does not exceed the principal amount (or, if such Indebtedness being refinanced provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration thereof, such lesser amount as of the date of determination) so refinanced plus the amount of any premium required to be paid in connection with such refinancing pursuant to the terms of the Indebtedness refinanced or the amount of any premium reasonably determined by such Restricted Subsidiary as necessary to accomplish such refinancing, plus the amount of expenses of such Subsidiary incurred in connection with such refinancing and (b) such new Indebtedness has an Average Life equal to or longer than the Average Life of the Indebtedness being refinanced and a final Stated Maturity equal to or later than the final Stated Maturity of the Indebtedness being refinanced; and (13) other Indebtedness incurred by one or more Restricted Subsidiaries that are not Guarantor Subsidiaries in an aggregate principal amount not to exceed $20,000,000 at any time outstanding. "Person" means any individual, corporation, limited liability company, partnership, joint venture, association, joint stock company, trust, unincorporated organization or government or any agency or political subdivision thereof. "Preferred Stock" means, with respect to any Person, any and all shares, interests, participations or other equivalents (however designated) of such Person's preferred or preference stock, whether now outstanding issued after the date of the Indenture, including, without limitation, all classes and series of preferred or preference stock of such Person. "Production Payments" means, collectively, Dollar-Denominated Production Payments and Volumetric Production Payments. "Public Market" exists at any time with respect to the Qualified Capital Stock of the Company if such Qualified Capital Stock of the Company is then: (1) registered with the SEC pursuant to Section 12(b) or 12(g) of the Exchange Act and (2) traded either on a national securities exchange or on the NASDAQ Stock Market. 117 118 "Qualified Capital Stock" of any Person means any and all Capital Stock of such Person other than Redeemable Capital Stock. "Qualified Redemption Transaction" means a call for redemption of any Capital Stock or Subordinated Indebtedness (including any Subordinated Indebtedness accounted for as a minority interest of the Company that is held by a Subsidiary that is a business trust or similar entity formed for the primary purpose of issuing preferred securities the proceeds of which are loaned to the Company or a Restricted Subsidiary) that by its terms is convertible into Common Stock of the Company if on the date of notice of such call for redemption: (1) a Public Market exists in the shares of Common Stock of the Company and (2) the average closing price on the Public Market for shares of Common Stock of the Company for the twenty trading days immediately preceding the date of such notice exceeds 120% of the conversion price per share (determined by reference to the redemption price) of Common Stock of the Company issuable upon conversion of the Capital Stock or Subordinated Indebtedness called for redemption. "Redeemable Capital Stock" means any class or series of Capital Stock that, either by its terms, by the terms of any security into which it is convertible or exchangeable or by contract or otherwise, is, or upon the happening of an event or passage of time would be, required to be redeemed prior to 91 days after the final Stated Maturity of the notes or is redeemable at the option of the holder thereof at any time prior to 91 days after such final Stated Maturity, or is convertible into or exchangeable for debt securities at any time prior to 91 days after such final Stated Maturity. "Regular Record Date" for the interest payable on any Interest Payment Date means February 1 or August 1 (whether or not a business day, as the case may be) next preceding each such Interest Payment Date. "Restricted Subsidiary" means any Subsidiary of the Company, whether existing on or after the date of the Indenture, unless such Subsidiary of the Company is an Unrestricted Subsidiary or is designated as an Unrestricted Subsidiary pursuant to the terms of the Indenture. "S&P" means Standard and Poor's Ratings Services, a division of The McGraw-Hill Companies, Inc., and its successors. "Sale/Leaseback Transaction" means, with respect to any Person, any direct or indirect arrangement pursuant to which properties or assets are sold or transferred by such Person or a Subsidiary of such Person and are thereafter leased back from the purchaser or transferee thereof by such Person or one of its Subsidiaries; provided, however, Sale/Leaseback Transactions shall not include transactions whereby property or assets are sold or transferred by the Company or any of its Restricted Subsidiaries to any Affiliate of the Company or pursuant to any Permitted Investment constituting a joint ownership arrangement, which property or assets are leased back, directly or indirectly, to the Company, any Affiliate of the Company or to the constituent parties to any such joint venture arrangement. "Senior Indebtedness" means the principal of, premium, if any, and interest on any Indebtedness of the Company (including, in the case of the Credit Agreement, interest accruing after the filing of a petition by or against the Company under any bankruptcy law, in accordance with and at the rate, including any default rate, specified with respect to such indebtedness, whether or not a claim for such interest is allowed as a claim after such filing in any proceeding under such bankruptcy law), whether outstanding on the date of the Indenture or thereafter created, incurred or assumed, unless, in the case of any particular Indebtedness, the instrument creating or evidencing the same or pursuant to which the same is outstanding expressly provides that such Indebtedness shall not be senior in right of payment to the notes. Notwithstanding the foregoing, "Senior Indebtedness" shall not include: (1) Indebtedness evidenced by the notes, 118 119 (2) Indebtedness that is expressly subordinate or junior in right of payment to any Senior Indebtedness of the Company, (3) Indebtedness which, when incurred and without respect to any election under Section 1111(b) of Title 11 United States Code, is by its terms without recourse to the Company or which is Non-Recourse Indebtedness, (4) any repurchase, redemption or other obligation in respect of Redeemable Capital Stock of the Company, (5) to the extent it might constitute Indebtedness, any liability for federal, state, local or other taxes owed or owing by the Company, (6) Indebtedness of the Company to a Subsidiary of the Company or any other Affiliate of the Company or any of such Affiliate's Subsidiaries and (7) that portion of any Indebtedness of the Company which at the time of issuance is issued in violation of the Indenture (but, as to any such Indebtedness, no such violation shall be deemed to exist for purposes of this clause (7) if the holder(s) of such Indebtedness or their representative or the Company shall have furnished to the Trustee an Opinion of Counsel addressed to the Trustee (which counsel may, as to matters of fact, rely upon a certificate of the Company) to the effect that the incurrence of such Indebtedness does not violate the provisions of such Indenture); provided, that the preceding exclusions shall not affect the priorities of any Indebtedness arising solely by operation of law in any case or proceeding or similar event described in clause (1), (2) or (3) of the second paragraph under the caption "-- Subordination." "Stated Maturity" means, when used with respect to any note or any installment of interest thereon, the date specified in such note as the fixed date on which the principal of such note or such installment of interest is due and payable, and, when used with respect to any other Indebtedness or any installment of interest thereon, means the date specified in the instrument evidencing or governing such Indebtedness as the fixed date on which the principal of such Indebtedness or such installment of interest is due and payable. "Subordinated Indebtedness" means: (1) the Company's 5 1/2% Convertible Subordinated Notes due 2006 issued under the Indenture dated as of June 15, 1996, between the Company and Fleet National Bank (now State Street Bank and Trust Company), as Trustee and (2) other Indebtedness of the Company which, by its terms, is subordinated in right of payment to the notes. "Subsidiary" means, with respect to any Person, a corporation, partnership, limited liability company, association or other business entity a majority of whose Voting Stock is at the time, directly or indirectly owned by such Person, by one or more Subsidiaries of such Person or by such Person and one or more Subsidiaries thereof. For purposes of the foregoing definition, an arrangement by which a Person who owns an interest in an oil and gas property is subject to a joint operating agreement, processing agreement, net profits, interest, overriding royalty interest, farmout agreement, development agreement, area of mutual interest agreement, joint bidding agreement, unitization agreement, pooling arrangement or other similar agreement or arrangement shall not, in and of itself, be considered a Subsidiary. "Subsidiary Guarantee" means any guarantee of the notes by any Restricted Subsidiary in accordance with the provisions set forth in the covenant described under the caption "-- Limitation on Non-Guarantor Restricted Subsidiaries." 119 120 "Subsidiary Guarantor" means each of the Company's Restricted Subsidiaries that becomes a guarantor of the notes in compliance with the provisions described under the caption "-- Limitation on Non-Guarantor Restricted Subsidiaries" or otherwise executes a supplemental indenture in which such Subsidiary agrees to be bound by the terms of the Indenture and to guarantee the payment of the notes pursuant to the provisions described under the caption "-- Possible Subsidiary Guarantees of the Notes." "Unrestricted Subsidiary" means: (1) any Subsidiary of the Company that at the time of determination will be designated an Unrestricted Subsidiary by the Board of Directors of the Company as provided below and (2) any Subsidiary of an Unrestricted Subsidiary. The Board of Directors of the Company may designate any Subsidiary of the Company as an Unrestricted Subsidiary so long as: (a) neither the Company nor any Restricted Subsidiary is directly or indirectly liable pursuant to the terms of any Indebtedness of such Subsidiary; (b) no default with respect to any Indebtedness of such Subsidiary would permit (upon notice, lapse of time or otherwise) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default on such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; (c) neither the Company nor any Restricted Subsidiary has made an Investment in such Subsidiary unless such Investment was made pursuant to, and in accordance with, the covenant described under the caption "-- Limitation on Restricted Payments" (other than Investments of the type described in clause (4) of the definition of "Permitted Investments"); and (d) such designation shall not result in the creation or imposition of any Lien on any of the Properties of the Company or any Restricted Subsidiary (other than any Permitted Lien or any Lien the creation or imposition of which shall have been in compliance with the covenant described under the caption "-- Limitation on Liens"); provided, however, that with respect to clause (a) of this sentence, the Company or a Restricted Subsidiary may be liable for Indebtedness of an Unrestricted Subsidiary if: (i) such liability constituted a Permitted Investment or a Restricted Payment permitted by the provisions of the Indenture described under the caption "-- Limitation on Restricted Payments," in each case at the time of incurrence, or (ii) the liability would be a Permitted Investment at the time of designation of such Subsidiary as an Unrestricted Subsidiary. Any such designation by the Board of Directors shall be evidenced to the Trustee by filing a resolution with the Trustee giving effect to such designation. The Board of Directors may designate any Unrestricted Subsidiary as a Restricted Subsidiary if, immediately after giving effect to such designation: (1) no Default or Event of Default shall have occurred and be continuing, (2) the Company could incur $1.00 of additional Indebtedness (other than Permitted Indebtedness) under the first paragraph of the covenant described above under the caption "-- Limitation on Indebtedness" and 120 121 (3) if any of the Properties of the Company or any of its Restricted Subsidiaries would upon such designation become subject to any Lien (other than a Permitted Lien), the creation or imposition of such Lien shall have been in compliance with the covenant described under the caption "-- Limitations on Liens." "Volumetric Production Payments" means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith. "Voting Stock" means any class or classes of Capital Stock pursuant to which the holders thereof have the general voting power under ordinary circumstances to vote in the election of the directors, managers or trustees of any Person (irrespective of whether or not, at the time, Capital Stock of any other class or classes shall have, or might have, voting power by reason of the happening of any contingency). "Wholly Owned Restricted Subsidiary" means any Restricted Subsidiary to the extent: (1) all of the Capital Stock in such Restricted Subsidiary, other than any directors qualifying shares mandated by applicable law, is owned directly or indirectly by the Company or (2) such Restricted Subsidiary is organized in a foreign jurisdiction and is required by the applicable laws and regulations of such foreign jurisdiction to be partially owned by the government of such foreign jurisdiction or individual or corporate citizens of such foreign jurisdiction in order for such Restricted Subsidiary to transact business in such foreign jurisdiction, provided, that the Company, directly or indirectly, owns the remaining Capital Stock or ownership interest in such Restricted Subsidiary and, by contract or otherwise, controls the management and business of such Restricted Subsidiary and derives the economic benefits of ownership of such Restricted Subsidiary to substantially the same extent as if such Restricted Subsidiary were a wholly owned Subsidiary. OUTSTANDING NOTES REGISTRATION RIGHTS AGREEMENT In connection with the sale of the outstanding notes, the Company entered into a Registration Rights Agreement. Under that agreement, the Company agreed to use its reasonable best efforts to: o file a registration statement with the SEC with respect to an offer to exchange the outstanding notes for new notes having substantially identical terms as the outstanding notes (except that the new notes will not contain terms with respect to transfer restrictions or interest rate increases) o cause that registration statement to be declared effective under the Securities Act within 135 days of the date of original issuance of the outstanding notes o keep that registration statement effective until the closing of the exchange offer o cause the exchange offer to be consummated within 180 days following the original issuance of the outstanding notes Promptly after the exchange offer registration statement has been declared effective, the Company will offer the outstanding notes in exchange for surrender of the new notes. Under the following circumstances, the Company will file with the SEC a shelf registration statement to cover resales of the outstanding notes by those holders who provide required information in connection with the shelf registration statement: o if any changes in law or the applicable interpretations of the staff of the SEC do not permit the Company to effect the exchange offer as contemplated by the Registration Rights Agreement 121 122 o if for any reason the exchange offer registration statement is not declared effective within 135 days after the date of original issuance of the outstanding notes o if the exchange offer is not consummated within 180 days after the date of original issuance of the outstanding notes o if the initial purchasers of outstanding notes request in certain circumstances A "Registration Default" will occur if, among other things: o the exchange offer registration statement is not declared effective on or prior to the 135th day following the date of original issuance of the outstanding notes o the exchange offer is not consummated or a shelf registration statement with respect to the notes is not declared effective on or prior to the 180th day following the date of original issuance of the outstanding notes o the Company files the exchange offer registration statement or shelf registration statement and the SEC declares it effective, but afterward the Company withdraws it, or it becomes subject to an effective stop order suspending the effectiveness of such registration statement (except as specifically permitted in the Registration Rights Agreement) without being succeeded immediately by an additional registration statement filed and declared effective o the Company effects a suspension of offers and sales under the shelf registration statement for more than 60 days, whether or not consecutive, within any period of 12 consecutive months If any Registration Default occurs, the Company will be obligated to pay additional interest to each holder of outstanding notes at a rate equal to 0.50% per annum. This rate will continue until all registration defaults have been cured (and, if applicable, the suspension of offers and sales of notes under the shelf registration statement ceases). Holders who desire to tender their outstanding notes will be required to make to the Company the representations described under "The Exchange Offer - -- Purpose and Effect of the Exchange Offer" and "-- Procedures for Tendering" in order to participate in the exchange offer. In addition, the Company may require holders to deliver information to be used in connection with the shelf registration statement in order to have their notes included in the shelf registration statement and benefit from the provisions regarding additional interest described in the preceding paragraphs. A holder who sells outstanding notes under the shelf registration statement generally will be required to be named as a selling securityholder in the related prospectus and to deliver a prospectus to purchasers. Such a holder will also be subject to the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the Registration Rights Agreement that are applicable to such holder, including indemnification obligations. The description of the Registration Rights Agreement contained in this section is a summary only. For more information, you may review the provisions of the Registration Rights Agreement that the Company filed with the SEC as an exhibit to the registration statement of which this prospectus is a part. BOOK ENTRY; DELIVERY AND FORM The new notes will initially be represented by one or more permanent global notes in definitive, fully registered book-entry form (the "Global Securities") that will be registered in the name of Cede & Co., as nominee of DTC. The Global Securities will be deposited on behalf of the acquirors of the new notes represented thereby with a custodian for DTC for credit to the respective accounts of the acquirors or to such other accounts as they may direct at DTC. See "The Exchange Offer -- Book-Entry Transfer." 122 123 THE GLOBAL SECURITIES The Company expects that under procedures established by DTC o upon deposit of the Global Securities with DTC or its custodian, DTC will credit on its internal system portions of the Global Securities that shall be comprised of the corresponding respective amounts of the Global Securities to the respective accounts of persons who have accounts with such depositary o ownership of the notes will be shown on, and the transfer of ownership thereof will be effected only through, records maintained by DTC or its nominee, with respect to interests of persons who have accounts with DTC ("participants"), and the records of participants, with respect to interests of persons other than participants. So long as DTC or its nominee is the registered owner or holder of any of the notes, DTC or such nominee will be considered the sole owner or holder of such notes represented by the Global Securities for all purposes under the Indenture and under the notes represented thereby. No beneficial owner of an interest in the Global Securities will be able to transfer such interest except in accordance with the applicable procedures of DTC in addition to those provided for under the indenture. Payments on the notes represented by the Global Securities will be made to DTC or its nominee, as the case may be, as the registered owner thereof. None of the Company, the trustee or any paying agent under the Indenture will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in the Global Securities or for maintaining, supervising or reviewing any records relating to such beneficial ownership interest. The Company expects that DTC or its nominee, upon receipt of any payment on the notes represented by the Global Securities, will credit participants' accounts with payments in amounts proportionate to their respective beneficial interests in the Global Securities as shown in the records of DTC or its nominee. The Company also expects that payments by participants to owners of beneficial interests in the Global Securities held through such participants will be governed by standing instructions and customary practice as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. Such payment will be the responsibility of such participants. Transfers between participants in DTC will be effected in accordance with DTC rules and will be settled in immediately available funds. If a holder requires physical delivery of a certificated security for any reason, including to sell notes to persons in states that require physical delivery of such security or to pledge such securities, such holder must transfer its interest in the Global Securities in accordance with the normal procedures of DTC and the procedures in the indenture. DTC has advised the Company that DTC will take any action permitted to be taken by a holder of notes, including the presentation of notes for exchange as described below, only at the direction of one or more participants to whose account the DTC interests in the Global Securities are credited and only in respect of the aggregate principal amount as to which such participant or participants has or have given such direction. However, if there is an event of default under the Indenture, DTC will exchange the Global Securities for certificated securities that it will distribute to its participants. DTC has advised the Company as follows: o DTC is a limited-purpose company organized under the New York Banking Law, a "banking organization" within the meaning of the New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the New York Uniform Commercial Code 123 124 and a "clearing agency" registered under the provisions of Section 17A of the Securities Exchange Act of 1934 o DTC holds securities that its participants deposit with DTC and facilitates the settlement among participants of securities transactions, such as transfers and pledges, in deposited securities through electronic computerized book-entry changes in participants' accounts, thereby eliminating the need for physical movement of securities certificates o Direct participants include securities brokers and dealers, banks, trust companies, clearing corporations and other organizations o DTC is owned by a number of its participants and by the New York Stock Exchange, Inc., the American Stock Exchange, Inc. and the National Association of Securities Dealers, Inc. o Access to the DTC system is also available to others such as securities brokers and dealers, banks and trust companies that clear through or maintain a custodial relationship with a direct participant, either directly or indirectly o The rules applicable to DTC and its participants are on file with the SEC Although DTC is expected to follow these procedures in order to facilitate transfers of interests in the Global Securities among participants of DTC, it is under no obligation to perform such procedures, and such procedures may be discontinued at any time. Neither the Company nor the trustee will have any responsibility for the performance by DTC or its direct or indirect participants on their respective obligations under the rules and procedures governing their operations. CERTIFICATED SECURITIES Interests in the Global Securities will be exchanged for certificated securities if: o DTC or any successor depositary (the "'Depositary") notifies the Company that it is unwilling or unable to continue as depositary for the Global Securities, or DTC ceases to be a "clearing agency" registered under the Securities Exchange Act of 1934, and a successor depositary is not appointed by the Company within 90 days o the Company determines not to have the notes represented by Global Securities Upon the occurrence of either of the events described in the preceding sentence, the Company will cause the appropriate certificated securities to be delivered. Neither the Company nor the trustee will be liable for any delay by the Depositary or its nominee in identifying the beneficial owners of the related notes. Each such person may conclusively rely on, and will be protected in relying on, instructions from such Depositary or nominee for all purposes, including the registration and delivery, and the respective principal amounts, of the notes to be issued. CERTAIN FEDERAL INCOME TAX CONSEQUENCES The following discussion is based on the 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. Legislative, judicial or administrative changes or interpretations may be forthcoming that could alter or modify the statements and conditions set forth herein. Any such changes or interpretations may or may not be retroactive and could affect the tax consequences to holders. Certain holders 124 125 (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. The Company recommends that each holder consult such holder's own tax advisor as to the particular tax consequences of exchanging such holder's outstanding notes for new notes, including the applicability and effect of any state, local or foreign tax laws. The Company believes that the exchange of outstanding notes for new notes pursuant to the exchange offer will not be treated as an "exchange" for federal income tax purposes because the new notes will not be considered to differ materially in kind or extent from the outstanding notes. Rather, the new notes received by a holder will be treated as a continuation of the outstanding notes in the hands of such holder. As a result, there will be no federal income tax consequences to holders exchanging outstanding notes for new notes pursuant to the exchange offer. PLAN OF DISTRIBUTION Based on interpretations by the staff of the SEC in no action letters issued to third parties, the Company believes that any holder may transfer new notes issued under the exchange offer in exchange for the outstanding notes if: o the holder acquires the new notes in the ordinary course of its business o the holder is not engaged in, and does not intend to engage in, and has no arrangement or understanding with any person to participate in, a distribution of such new notes Broker-dealers receiving new notes in the exchange offer will be subject to a prospectus delivery requirement with respect to resales of the new notes. The Company believes that a holder may not transfer new notes issued under the exchange offer in exchange for the outstanding notes if that holder is: o an "affiliate" of the Company within the meaning of Rule 405 under the Securities Act o a broker-dealer that acquired outstanding notes directly from the Company o a broker-dealer that acquired outstanding notes as a result of market-making or other trading activities without compliance with the registration and prospectus delivery provisions of the Securities Act To date, the staff of the SEC has taken the position that participating broker-dealers may fulfill their prospectus deliver requirements with respect to transactions involving an exchange of securities such as this exchange offer, other than a resale of an unsold allotment from the original sale of the outstanding notes, with the prospectus contained in the exchange offer registration statement. In the Registration Rights Agreement, the Company has agreed to permit participating broker-dealers to use this prospectus in connection with the resale of new notes. The Company has agreed that, for a period of up to 180 days after the expiration of the exchange offer, the Company will make this prospectus, and any amendment or supplement to this prospectus, available to any broker-dealer that requests such documents in the letter of transmittal. If a holder wishes to exchange its outstanding notes for new notes in the exchange offer, the holder will be required to make representations to us as described in "The Exchange Offer -- Purpose and Effect of the Exchange Offer" and "-- Procedures for Tendering -- Representations to the Company" of this prospectus and in the letter of transmittal. In addition, if a broker-dealer receives new notes for its own account in exchange for outstanding notes that were acquired by it as a result of market-making activities or other trading activities, it will be required to acknowledge that it will deliver a prospectus in connection with any resale by it of such new notes. 125 126 The Company will not receive any proceeds from any sale of new notes by broker-dealers. Broker-dealers who receive new notes for their own account in the exchange offer may sell them from time to time in one or more transactions in the over-the-counter market: o in negotiated transactions o through the writing of options on the new notes or a combination of such methods of resale o at market prices prevailing at the time of resale o at prices related to such prevailing market prices or negotiated prices Any 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 broker-dealer or the purchasers of any new notes. Any broker-dealer that resells new notes it received for its own account in the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an "underwriter" within the meaning of the Securities Act. Any profit on any resale of new 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 incidental to the exchange offer other than commissions and concessions of any brokers or dealers. The Company will indemnify holders of the outstanding notes, including any broker-dealers, against certain liabilities, including liabilities under the Securities Act, as provided in the Registration Rights Agreement. TRANSFER RESTRICTIONS ON OUTSTANDING NOTES The outstanding notes were not registered under the Securities Act. Those outstanding notes may not be offered or sold in the United States or to, or for the account or benefit of, U.S. persons except in accordance with an exemption from the Securities Act registration requirements. Accordingly, the outstanding notes were offered and sold only in the United States to "qualified institutional buyers" under Rule 144A under the Securities Act in a private sale exempt from the registration requirements of the Securities Act. LEGAL MATTERS The validity of the issuance of the new notes is being passed upon for the Company by Gerald A. Morton, Vice President-Law and Corporate Secretary of the Company. Mr. Morton owns approximately 3,961 shares of the Company's Common Stock directly and through the Company's tax advantaged savings plan and options to purchase an aggregate of 29,000 shares of the Company's common stock, which are or become exercisable in periodic installments through August 1, 2001. EXPERTS The consolidated financial statements of Pogo Producing Company as of December 31, 1997 and 1996, and for the three years in the period ended December 31, 1997, incorporated by reference in this prospectus have been audited by Arthur Andersen LLP, independent public accountants, as indicated in their report with respect thereto, and are incorporated by reference herein in reliance upon the authority of that firm as experts in accounting and auditing in giving that report. 126 127 The estimates of oil and gas reserves set forth herein and in the Annual Report, and the related estimates set forth herein and therein of discounted present values of estimated future net revenues therefrom, are extracted from the report of Ryder Scott attached as an exhibit to the Annual Report. Such information is incorporated by reference herein in reliance on the authority of that firm as experts with respect to matters contained in that report. 127 128 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE Consolidated Financial Statements of Pogo Producing Company ---- Report of Independent Public Accountants................................................................ F-2 Consolidated Statements of Income for the Years Ended December 31, 1997, 1996, and 1995................................................................................................. F-3 Consolidated Balance Sheets as of December 31, 1997 and 1996............................................ F-4 Consolidated Statements of Cash Flows for the Years Ended December 31, 1997, 1996 and 1995............................................................................................. F-5 Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 1997, 1996, and 1995................................................................................. F-6 Notes to Consolidated Financial Statements.............................................................. F-7
F-1 129 REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Pogo Producing Company: We have audited the accompanying consolidated balance sheets of Pogo Producing Company (a Delaware corporation) and subsidiaries as of December 31, 1997 and 1996, and the related consolidated statements of income, shareholders' equity and cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Pogo Producing Company and subsidiaries as of December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Houston, Texas February 13, 1998 F-2 130 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF INCOME
YEAR ENDED DECEMBER 31, ---------------------------------- 1997 1996 1995 ---------- ---------- ---------- (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) Revenues: Oil and gas..................... $ 285,200 $ 204,142 $ 157,459 Gains (losses) on sales......... 1,100 (165) 100 ---------- ---------- ---------- Total...................... 286,300 203,977 157,559 ---------- ---------- ---------- Operating Costs and Expenses: Lease operating................. 63,501 37,628 35,071 General and administrative...... 21,412 18,028 16,400 Exploration..................... 10,530 16,777 7,468 Dry hole and impairment......... 9,631 8,579 6,703 Depreciation, depletion and amortization.................. 103,157 61,857 68,489 ---------- ---------- ---------- Total...................... 208,231 142,869 134,131 ---------- ---------- ---------- Operating Income..................... 78,069 61,108 23,428 Interest: Charges......................... (21,886) (13,203) (11,167) Income.......................... 453 232 26 Capitalized..................... 6,175 4,244 1,834 Foreign Currency Transaction Loss.... (7,604) -- -- ---------- ---------- ---------- Income Before Taxes and Extraordinary Item............................... 55,207 52,381 14,121 ---------- ---------- ---------- Income Tax Expense................... (18,091) (18,800) (4,891) ---------- ---------- ---------- Income Before Extraordinary Item..... 37,116 33,581 9,230 Extraordinary Loss on Early Extinguishment of Debt, net of taxes.............................. -- (821) -- ---------- ---------- ---------- Net Income........................... $ 37,116 $ 32,760 $ 9,230 ========== ========== ========== Earnings per Share (restated for 1996 and 1995): Basic Before extraordinary item.................... $ 1.11 $ 1.01 $ 0.28 Extraordinary item......... -- (0.02) -- ---------- ---------- ---------- Net income................. $ 1.11 $ 0.99 $ 0.28 ========== ========== ========== Diluted Before extraordinary item.................... $ 1.06 $ 0.97 $ 0.28 Extraordinary item......... -- (0.02) -- ---------- ---------- ---------- Net income................. $ 1.06 $ 0.95 $ 0.28 ========== ========== ========== Dividends per Common Share........... $ 0.12 $ 0.12 $ 0.12 ========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part hereof. F-3 131 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
DECEMBER 31, --------------------------- 1997 1996 ----------- ----------- (EXPRESSED IN THOUSANDS) ASSETS Current Assets: Cash and cash investments ......... $ 19,646 $ 3,054 Accounts receivable ............... 39,540 30,031 Other receivables ................. 46,951 35,027 Inventory -- product .............. 713 -- Inventories -- tubulars ........... 8,334 6,165 Other ............................. 4,087 641 ----------- ----------- Total current assets ......... 119,271 74,918 ----------- ----------- Property and Equipment: Oil and gas, on the basis of successful efforts accounting Proved properties being amortized ................ 1,321,817 1,079,523 Unevaluated properties and properties under development, not being amortized ................ 110,231 111,192 Other, at cost .................... 12,619 8,773 ----------- ----------- 1,444,667 1,199,488 Less -- accumulated depreciation, depletion, and amortization, including $6,004 and $4,822 respectively, applicable to other property ..... 917,363 814,623 ----------- ----------- 527,304 384,865 ----------- ----------- Other .................................. 30,042 19,459 ----------- ----------- $ 676,617 $ 479,242 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY Current Liabilities: Accounts payable -- operating activities ....................... $ 13,639 $ 7,676 Accounts payable -- investing activities ....................... 90,833 56,961 Accrued interest payable .......... 3,130 1,957 Accrued payroll and related benefits ......................... 1,938 1,490 Other ............................. 632 163 ----------- ----------- Total current liabilities .............. 110,172 68,247 Long-Term Debt ......................... 348,179 246,230 Deferred Federal Income Tax ............ 57,502 46,321 Deferred Credits ....................... 14,658 11,162 ----------- ----------- Total liabilities ............ 530,511 371,960 ----------- ----------- Shareholders' Equity: Preferred stock, $1 par; 2,000,000 shares authorized ...... -- -- Common stock, $1 par; 100,000,000 shares authorized, and 33,552,702 and 33,321,381 shares issued, respectively ...... 33,553 33,321 Additional capital ................ 144,848 139,337 Retained earnings (deficit) ....... (31,971) (65,075) Treasury stock and other, at cost ............................. (324) (301) ----------- ----------- Total shareholders' equity ................... 146,106 107,282 ----------- ----------- $ 676,617 $ 479,242 =========== ===========
The accompanying notes to consolidated financial statements are an integral part hereof. F-4 132 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, ------------------------------------- 1997 1996 1995 --------- --------- --------- (EXPRESSED IN THOUSANDS) Cash flows from operating activities: Cash received from customers ......................................................... $ 272,004 $ 195,931 $ 164,065 Federal income taxes received ........................................................ 7,037 -- 6,000 Operating, exploration, and general and administrative expenses paid ................. (86,445) (74,512) (56,997) Interest paid ........................................................................ (20,713) (12,960) (11,036) Federal income taxes paid ............................................................ (19,500) 12,500) (6,000) Other ................................................................................ (1,651) (3,061) 301 --------- --------- --------- Net cash provided by operating activities ....................................... 150,732 92,898 96,333 --------- --------- --------- Cash flows from investing activities: Capital expenditures ................................................................. (197,326) (172,032) (96,403) Purchase of proved reserves .......................................................... (31,234) -- (11,921) Proceeds from the sale of property and tubular stock ................................. 387 100 100 --------- --------- --------- Net cash used in investing activities ........................................... (228,173) (171,932) (108,224) --------- --------- --------- Cash flows from financing activities: Proceeds from issuance of new debt ................................................... 100,000 115,000 -- Borrowings under senior debt agreements .............................................. 502,000 208,000 199,000 Payments under senior debt agreements ................................................ (500,000) (201,000) (182,000) Proceeds from exercise of stock options .............................................. 3,874 3,378 1,717 Payment of cash dividends on common stock ............................................ (4,012) (3,979) (3,946) Debt issue expenses paid ............................................................. (3,165) (3,116) -- Purchase of 8% debentures due 2005 ................................................... -- (40,699) (450) Principal payments of other long-term debt obligations ............................... -- -- (871) --------- --------- --------- Net cash provided by financing activities ....................................... 98,697 77,584 13,450 --------- --------- --------- Effect of exchange rate changes on cash .................................................. (4,664) 23 -- --------- --------- --------- Net increase (decrease) in cash and cash investments ..................................... 16,592 (1,427) 1,559 Cash and cash investments at the beginning of the year ................................... 3,054 4,481 2,922 --------- --------- --------- Cash and cash investments at the end of the year ......................................... $ 19,646 $ 3,054 $ 4,481 ========= ========= ========= Reconciliation of net income to net cash provided by operating activities: Net income ........................................................................... $ 37,116 $ 32,760 $ 9,230 Adjustments to reconcile net income to net cash provided by operating activities Extraordinary losses on early extinguishments of debt, net of taxes ............. -- 821 -- Foreign currency transaction loss ............................................... 7,604 -- -- (Gains) losses on sales ......................................................... (1,100) 165 (100) Depreciation, depletion and amortization ........................................ 103,157 61,857 68,489 Dry hole and impairment ......................................................... 9,631 8,579 6,703 Interest capitalized ............................................................ (6,175) (4,244) (1,834) Increase in deferred income tax ................................................. 12,999 7,175 5,592 Change in assets and liabilities: (Increase) decrease in accounts receivable .................................. (12,483) (8,211) 7,095 Increase in inventory -- product ............................................ (713) -- -- (Increase) decrease in other current assets ................................. (6,470) 81 23 Increase in other assets .................................................... (7,418) (5,228) (1,187) Increase (decrease) in accounts payable ..................................... 8,998 (2,079) 1,942 Increase in accrued interest payable ........................................ 1,173 243 131 Increase in accrued payroll and related benefits ............................ 448 251 2 Increase in other current liability ......................................... 469 60 63 Increase in deferred credits ................................................ 3,496 668 184 --------- --------- --------- Net cash provided by operating activities ................................................ $ 150,732 $ 92,898 $ 96,333 ========= ========= =========
The accompanying notes to consolidated financial statements are an integral part hereof. F-5 133 POGO PRODUCING COMPANY & SUBSIDIARIES CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
TREASURY RETAINED STOCK SHARE- SHARES COMMON ADDITIONAL EARNINGS AND HOLDERS' OUTSTANDING STOCK CAPITAL (DEFICIT) OTHER EQUITY ---------- ---------- ---------- ---------- ---------- ---------- (DOLLARS EXPRESSED IN THOUSANDS) BALANCE AT DECEMBER 31, 1994 ........... 32,810,261 $ 32,826 $ 130,675 $ (99,140) $ (324) $ 64,037 Net income ............................. -- -- -- 9,230 -- 9,230 Exercise of stock options .............. 181,136 181 2,206 -- -- 2,387 Dividends ($0.12 per common share) ..... -- -- -- (3,946) -- (3,946) ---------- ---------- ---------- ---------- ---------- ---------- BALANCE AT DECEMBER 31, 1995 ........... 32,991,397 33,007 132,881 (93,856) (324) 71,708 Net income ............................. -- -- -- 32,760 -- 32,760 Foreign currency translation gain ...... -- -- -- -- 23 23 Exercise of stock options .............. 274,714 274 4,924 -- -- 5,198 Shares issued in connection with the Long-Term Incentive Plan ............. 5,896 6 246 -- -- 252 Shares issued in connection with the conversion of -- 8% Debentures ..................... 32,898 33 1,267 -- -- 1,300 2004 Notes ........................ 901 1 19 -- -- 20 Dividends ($0.12 per common share) ..... -- -- -- (3,979) -- (3,979) ---------- ---------- ---------- ---------- ---------- ---------- BALANCE AT DECEMBER 31, 1996 ........... 33,305,806 33,321 139,337 (65,075) (301) 107,282 Net income ............................. -- -- -- 37,116 -- 37,116 Foreign currency translation loss ...... -- -- -- -- (23) (23) Exercise of stock options .............. 229,024 230 5,461 -- -- 5,691 Shares issued in connection with the conversion of 2004 Notes ............. 2,297 2 50 -- -- 52 Dividends ($0.12 per common share) ..... -- -- -- (4,012) -- (4,012) ---------- ---------- ---------- ---------- ---------- ---------- BALANCE AT DECEMBER 31, 1997 ........... 33,537,127 $ 33,553 $ 144,848 $ (31,971) $ (324) $ 146,106 ========== ========== ========== ========== ========== ==========
The accompanying notes to consolidated financial statements are an integral part hereof. F-6 134 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Operations -- Pogo Producing Company was incorporated in 1970. Pogo Producing Company and its subsidiaries (the "Company") are engaged in oil and gas exploration, development and production activities on its properties located offshore in the Gulf of Mexico and onshore in the United States and internationally in the Gulf of Thailand. The Company has interests in 101 lease blocks offshore Louisiana and Texas, approximately 237,000 gross acres onshore in the United States and approximately 734,000 gross acres offshore in the Kingdom of Thailand. Use of Estimates -- The preparation of these financial statements require the use of certain estimates by management in determining the Company's assets, liabilities, revenues and expenses. Depreciation, depletion and amortization of oil and gas properties and the impairment of oil and gas properties are determined using estimates of proved oil and gas reserves. There are numerous uncertainties in estimating the quantity of proved reserves and in projecting the future rates of production and timing of development expenditures. Oil and gas reserve engineering must be recognized as a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact way. Proved reserves of crude oil, condensate, natural gas and natural gas liquids are estimated quantities that geological and engineering data demonstrate with reasonable certainty to be recoverable in the future from known reservoirs under existing conditions. Principles of Consolidation -- The consolidated financial statements include the accounts of Pogo Producing Company and its subsidiary and affiliated companies, after elimination of all significant intercompany transactions. Majority owned subsidiaries are fully consolidated. Minority owned subsidiaries or affiliates are pro rata consolidated in the same manner as the Company, and the oil and gas industry generally, accounts for its operating or working interest in oil and gas joint ventures. Prior-Year Reclassifications -- Certain prior-year amounts have been reclassified to conform with the current year presentation. Foreign Currency -- The U. S. Dollar is the functional currency for all areas of operations of the Company. Accordingly, monetary assets and liabilities and items of income and expense denominated in a foreign currency are remeasured to U. S. dollars at the rate of exchange in effect at the end of each month and the resulting gains or losses on foreign currency transactions are included in the consolidated statements of income for the period. Inventory -- Product Crude oil and condensate from the Company's Tantawan field located in the Kingdom of Thailand is produced into a floating production, storage and off loading ("FPSO") system and sold periodically as an economic barge quantity is accumulated. The product inventory at December 31, 1997 consists of approximately 43,000 barrels of crude oil and condensate, net to the Company's interest, and is carried at its estimated net realizable value of $16.67 per barrel. Inventory -- Tubulars Tubular Inventories consist primarily of goods used in the Company's operations and are stated at the lower of average cost or market value. F-7 135 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Interest Capitalized -- Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are evaluated or until production commences if the projects are evaluated as successful. Earnings per Share -- In 1997, the Company adopted the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 128, Earnings Per Share ("SFAS 128"). Prior years have been restated in conformity with the provisions of SFAS 128. Earnings per common share (basic earnings per share) are based on the weighted average number of shares of common stock outstanding during the periods. Earnings per common share and potential common share (diluted earnings per share) consider the effect of dilutive securities as set out below in thousands, except per share amounts.
FOR THE YEAR ENDED DECEMBER 31, 1997 ----------------------------- INCOME SHARES PER SHARE ------- ------- ------- BASIC EARNINGS PER SHARE ........................................ $37,116 33,421 $ 1.11 Effect of potential dilutive securities: Shares assumed issued from the exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period .............................. -- 758 -- Interest expense avoided, net of taxes, and shares issued from the assumed conversion at $22.188 per share of the 2004 Notes ........................................... 3,082 3,885 ------- ------- ------- DILUTED EARNINGS PER SHARE ...................................... $40,198 38,064 $ 1.06 ======= ======= ======= Antidilutive securities: Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period ...................... -- 471 $ 40.82 Interest expense incurred, net of taxes, and shares not issued related to the assumed non-conversion at $42.185 per share of the 2006 Notes ...................... $ 4,111 2,726 $ 1.51
F-8 136 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31, 1996 ----------------------------- INCOME(a) SHARES PER SHARE ------- ------- ------- BASIC EARNINGS PER SHARE ........................................ $33,581 33,203 $ 1.01 Effect of potential dilutive securities: Shares issued from the assumed exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period .............................. -- 831 -- Interest expense avoided, net of taxes, and shares issued from the assumed conversion at $22.188 per share of the 2004 Notes ........................................... 3,083 3,886 ------- ------- ------- DILUTED EARNINGS PER SHARE ...................................... $36,664 37,920 $ 0.97 ======= ======= ======= (a) Computed on income before extraordinary item Antidilutive securities: Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period ...................... -- 20 $ 40.94 Interest expense incurred, net of taxes, and shares not issued related to the assumed non-conversion at $39.50 per share of the 8% Debentures, retired on June 28, 1996 ............................................ $ 1,179 521 $ 2.26 Interest expense incurred, net of taxes, and shares not issued related to the assumed non-conversion at $42.185 per share of the 2006 Notes ............................................. $ 2,238 1,472 $ 1.52
FOR THE YEAR ENDED DECEMBER 31, 1995 -------------------------- INCOME SHARES PER SHARE ------ ------ ------ BASIC EARNINGS PER SHARE ........................................ $9,230 32,893 $ 0.28 Effect of potential dilutive securities: Shares issued from the assumed exercise of options to purchase common shares, net of treasury shares assumed purchased from the proceeds, at the average market price for the period .............................. -- 597 -- ------ ------ ------ DILUTED EARNINGS PER SHARE ...................................... $9,230 33,490 $ 0.28 ====== ====== ====== Antidilutive securities: Shares assumed not issued from options to purchase common shares as the exercise prices are above the average market price for the period ...................... -- 598 $22.13 Interest expense incurred, net of taxes, and shares not issued related to the assumed non-conversion at $39.50 per share of the 8% Debentures ........................... $2,229 1,085 $ 2.05 Interest expense incurred, net of taxes, and shares not issued related to the assumed non-conversion at $22.188 per share of the 2004 Notes .............................. $3,083 3,887 $ 0.79
F-9 137 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Production Imbalances -- Owners of an oil and gas property often take more or less production from a property than entitled to based on their ownership percentages in the property. This results in a condition known in the industry as a production imbalance. The Company follows the "take" (cash) method of accounting for production imbalances. Under this method, the Company recognizes revenues on production as it is taken and delivered to its purchasers. The Company's crude oil imbalances are not significant. At December 31, 1997, the Company had taken approximately 3,751 MMcf of natural gas less than it was entitled to based on its interest in those properties, and approximately 1,757 MMcf more than its entitlement on other properties placing the Company at year end in a net under-delivered position of approximately 1,994 MMcf of natural gas based on its working interest ownership in the properties. Oil and Gas Activities and Depreciation, Depletion and Amortization -- The Company follows the successful efforts method of accounting for its oil and gas activities. Under the successful efforts method, lease acquisition costs and all development costs are capitalized. Proved properties are reviewed whenever events or changes in circumstances indicate that the value of such property on the Company's books may not be recoverable. Unproved properties are reviewed quarterly to determine if there has been impairment of the carrying value, with any such impairment charged to expense in the period. Exploratory drilling costs are capitalized until the results are determined. If proved reserves are not discovered, the exploratory drilling costs are expensed. Other exploratory costs are expensed as incurred. The provision for depreciation, depletion and amortization is based on the capitalized costs as determined above, plus future costs to abandon offshore wells and platforms, and is on a cost center by cost center basis using the units of production method. The Company generally creates cost centers on a field by field basis for oil and gas activities in the Gulf of Mexico and the Gulf of Thailand. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its oil and gas activities onshore in the United States. Other properties are depreciated using a straight-line method in amounts which in the opinion of management are adequate to allocate the cost of the properties over their estimated useful lives. Consolidated Statements of Cash Flows -- For the purpose of cash flows, the Company considers all highly liquid investments with a maturity date of three months or less to be cash equivalents. Significant transactions may occur which do not directly affect cash balances and as such will not be disclosed in the Consolidated Statements of Cash Flows. Certain such noncash transactions are disclosed in the Consolidated Statements of Shareholders' Equity relating to shares issued in connection with the Long-Term Incentive Plan and the conversion of debentures into Common Stock in 1996 and 1997. Commitments and Contingencies -- The Company has commitments for operating leases for office space in Houston, Midland and Bangkok and commitments for an operating lease and operating expenses related to a floating production, storage and off-loading vessel (FPSO) in the Gulf of Thailand. Rental expense for office space was $1,440,000 in 1997, $1,054,000 in 1996, and $861,000 in 1995. Expenses for the FPSO lease and related F-10 138 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) operating costs were $14,809,000 in 1997. Future minimum office and FPSO lease expenses and related FPSO operating expense payments (in thousands of dollars) at December 31, 1997 are as follows:
1998................................. $ 17,826 1999................................. 17,830 2000................................. 17,758 2001................................. 17,758 2002................................. 16,611 Thereafter........................... 91,352
(2) INCOME TAXES The components of income (loss) before income taxes for each of the three years in the period ended December 31, 1997, are as follows (expressed in thousands):
1997 1996 1995 --------- --------- --------- United States........................ $ 62,953 $ 56,380 $ 16,899 Foreign.............................. (7,746) (3,999) (2,778) --------- --------- --------- Total........................... $ 55,207 $ 52,381 $ 14,121 ========= ========= =========
The components of federal income tax expense (benefit) for each of the three years in the period ended December 31, 1997, are as follows (expressed in thousands):
1997 1996 1995 --------- --------- --------- United States, current............... $ 16,000 $ 12,500 $ -- United States, deferred(a)........... 5,964 7,162 5,602 Foreign, deferred.................... (3,873) (862) (711) --------- --------- --------- Total........................... $ 18,091 $ 18,800 $ 4,891 ========= ========= =========
- ------------ (a) Excludes $443,000 of deferred tax benefit on extraordinary loss of $1,264,000 in 1996. Total federal income tax expense (benefit) for each of the three years in the period ended December 31, 1997, differs from the amounts computed by applying the statutory federal income tax rate to income before taxes as follows (expressed as a percent of pretax income):
1997 1996 1995 --------- --------- --------- Federal statutory income tax rate.... 35.0% 35.0% 35.0% Increases (reductions) resulting from: Statutory depletion in excess of tax basis....................... (0.2) (0.2) (2.2) Foreign taxes................... (2.1) 1.1 1.6 Other........................... 0.1 -- 0.2 --------- --------- --------- 32.8% 35.9% 34.6% ========= ========= =========
Deferred income taxes are determined based upon the differences between the financial statement and tax basis of the Company's assets and liabilities using enacted tax rates in effect for the years in which the differences are expected to reverse. Deferred tax assets are recognized if it is more likely than not that the F-11 139 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) future tax benefit will be realized. The principal components of the Company's deferred income tax assets and liabilities include the following at December 31, 1997 and 1996 (expressed in thousands):
DECEMBER 31, ----------------------- 1997 1996 --------- --------- Deferred tax liabilities: Intangible drilling costs, capitalized and amortized for financial statement purposes and deducted for income tax purposes ............................................... $ 204,218 $ 184,981 Charges to property and equipment, expensed for financial statement purposes, and capitalized and amortized for income tax purposes ........................................ 12,203 8,089 Interest charges, capitalized and amortized for financial statement purposes and deducted for income tax purposes .... 19,762 21,046 --------- --------- 236,183 214,116 Deferred tax asset: Differences in depletion and depreciation rates used for tangible assets for financial and income tax purposes ...... (178,681) (167,795) --------- --------- Net deferred tax liability ........................................ $ 57,502 $ 46,321 ========= =========
(3) LONG-TERM DEBT Long-term debt and the amount due within one year at December 31, 1997 and 1996, consists of the following (dollars expressed in thousands):
DECEMBER 31, -------------------- 1997 1996 -------- -------- Senior debt -- Bank revolving credit agreement debt: LIBO Rate based loans, borrowings at December 31, 1997 and 1996 at average interest rates of 6.52% and 6.59%, respectively ............................................ $ 47,000 $ 22,000 Prime rate based loans, borrowing at December 31, 1996 at an interest rate of 8.25% ............................ -- 13,000 -------- -------- Total bank revolving credit agreement debt ............ 47,000 35,000 Uncommitted credit lines with banks, borrowing at December 31, 1996 at an average interest rate of 7.0% ... -- 10,000 -------- -------- Total senior debt .................................................... 47,000 45,000 -------- -------- Subordinated debt -- 8 3/4% Senior subordinated notes, due 2007 (issued May 22, 1997) ................................................. 100,000 -- 5 1/2% Convertible subordinated notes, due 2004 ................. 86,179 86,230 5 1/2% Convertible subordinated notes, due 2006 ................. 115,000 115,000 -------- -------- Total subordinated debt .............................................. 301,179 201,230 -------- -------- Total debt ........................................................... 348,179 246,230 -------- -------- Amount due within one year -- ........................................ -- -- -------- -------- Long-term debt ....................................................... $348,179 $246,230 ======== ========
F-12 140 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Effective August 1, 1997, the Company entered into an amended and restated credit agreement (as so amended and restated, the "Credit Agreement"). The Credit Agreement provides for an unsecured $250,000,000 revolving/term credit facility which will be fully revolving until July 1, 2000, after which the balance will be due in eight quarterly term loan installments, commencing October 31, 2000. The amount that may be borrowed under the Credit Agreement may not exceed a borrowing base which is composed of both domestic and Thai properties less, in certain circumstances, the present value of interest payments on the 2007 Notes. The domestic borrowing base is determined semiannually by the lenders in accordance with the Credit Agreement, based primarily on the discounted present value of future net revenues from the Company's domestic oil and gas reserves. The portion of the borrowing base which composed of properties located in the Kingdom of Thailand is also determined semiannually, but may, at the lenders' discretion, be redetermined once more during each semiannual period. The value of this portion of the borrowing base is determined by the lenders applying their usual and customary criteria for oil and gas evaluation. As of January 1, 1998, the Company's total borrowing base, including both domestic and Thai properties, exceeded $250,000,000. The Credit Agreement is governed by various financial and other covenants, including requirements to maintain positive working capital (excluding current maturities of debt) and fixed charge coverage ratio, and limitations on indebtedness, creation of liens, the prepayment of subordinated debt, the payment of dividends, mergers and consolidation, investments and asset dispositions. In addition, the Company is prohibited from pledging borrowing base properties as security for other debt. Borrowings under the Credit Agreement currently bear interest at a base (prime) rate or LIBOR plus 5/8%, at the Company's option. A commitment fee on the unborrowed amount under the Credit Agreement is also charged. The commitment fee is currently 0.25% per annum on the unborrowed amount under the Credit Agreement that is designated as "active" and 0.10% per annum on the unborrowed amount under the Credit Agreement that is designated as "inactive." Of the $250,000,000 that is currently available under the Credit Agreement (subject to borrowing base limitations), $125,000,000 is designated as "active" and $125,000,000 is designated as "inactive". The Company has also entered into separate letter agreements with two banks under which one of the banks may provide a $10,000,000 uncommitted money market line of credit and the other bank may provide a $20,000,000 uncommitted money market line of credit. Each line of credit is on an as available or offered basis and neither bank has an obligation to make any advances under its respective line of credit. Although loans made under these letter agreements are for a maximum term of 30 days, they will be reflected as long-term on the Company's balance sheet because the Company has the ability and intent to reborrow such amounts under its Credit Agreement. Both letter agreements permit either party to terminate such letter agreement at any time. On May 22, 1997, the Company issued $100,000,000 of 8 3/4% Senior Subordinated Notes due 2007 (the "2007 Notes"). The proceeds from the issuance of the 2007 Notes were used to repay amounts outstanding under the Company's bank revolving credit agreement, and to purchase short-term cash investments. The 2007 Notes bear interest at a rate of 8 3/4%, payable semiannually in arrears on May 15 and November 15 of each year, commencing November 15, 1997. The 2007 Notes are general unsecured senior subordinated obligations of the Company and are subordinated in right of payment to the Company's senior indebtedness, which currently includes the Company's obligations under its bank revolving credit agreement and its unsecured credit lines, but are senior in right of payment to its subordinated indebtedness, which currently includes the 2006 Notes and the 2004 Notes. The Company, at its option, may redeem the 2007 Notes in whole or in part, at any time on or after May 15, 2002, at a redemption price of 104.375% of their principal value and decreasing percentages thereafter. No sinking fund payments are required on the 2007 Notes. The 2007 Notes are redeemable at the option of any holder, upon the occurrence of a change of control (as defined in the indenture governing the 2007 Notes), at 101% of their principal amount. The indenture governing the 2007 Notes also imposes certain covenants on the Company that are customary for senior subordinated indebtedness generally, including covenants limiting: incurrence of indebtedness F-13 141 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of asset sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and mergers, consolidations and the sale of assets. As of December 31, 1997, $28,657,000 was available for dividends under this limitation, which is currently the Company's most restrictive such covenant. The 5 1/2% Convertible Subordinated Notes, due 2004 (the "2004 Notes") are convertible into Common Stock at $22.188 per share subject to adjustment upon the occurrence of certain events. The 2004 Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after March 15, 1998, at a redemption price of 103.3% and decreasing percentages thereafter. No sinking fund is provided. The 2004 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change in control and other circumstances, as defined), at 100% of the principal amount. On February 12, 1998, the Company announced its intent to redeem the 2004 Notes on March 16, 1998 at an amount equal to 103.3% of their principal amount plus accrued interest. Holders may elect to convert the principal or any integral multiple of a 2004 Note into common stock at $22.188 per share until close of business on March 13, 1998. The 5 1/2% Convertible Subordinated Notes, due 2006 (the "2006 Notes") are convertible into Common Stock at $42.185 per share subject to adjustment upon the occurrence of certain events. The 2006 Notes will be redeemable at the option of the Company, in whole or in part, at any time on or after June 15, 1999, at a redemption price of 103.85% and decreasing percentages thereafter. No sinking fund is provided. The 2006 Notes are redeemable at the option of the holder, upon the occurrence of a repurchase event (a change in control and other circumstances, as defined), at 100% of the principal amount. Current maturities and sinking fund requirements during the next five years in connection with the above long-term debt are none in 1998 and 1999, $7,050,000 in 2000, $25,850,000 in 2001 and $14,100,000 in 2002. All of the current maturities reflected above are related to the retirement of the Company's bank debt. The Company has established a history of refinancing its bank debt before scheduled maturity payments commence and expects to do so again before the amortization of bank debt commences in 2000. F-14 142 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (4) GEOGRAPHIC SEGMENT REPORTING During 1997, the Company adopted the Financial and Accounting Standard's Board's Statement of Financial Accounting Standards No. 131, Disclosures about Segments of an Enterprise and Related Information ("SFAS 131"). Information concerning the Company's revenues and long-lived assets as required by SFAS 131 is as follows (in thousands of dollars):
LONG-LIVED REVENUES ASSETS -------- -------- AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1997 United States ............................... $245,458 $366,638 Kingdom of Thailand ......................... 39,393 160,666 -------- -------- $284,851 $527,304 ======== ======== AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1996 United States ............................... $203,364 $295,108 Kingdom of Thailand ......................... -- 89,757 -------- -------- $203,364 $384,865 ======== ======== AS OF AND FOR THE YEAR ENDED DECEMBER 31, 1995 United States ............................... $156,729 $232,527 Kingdom of Thailand ......................... -- 29,306 -------- -------- $156,729 $261,833 ======== ========
(5) SALES TO MAJOR CUSTOMERS The Company is an oil and gas exploration and production company that generally sells its oil and gas to numerous customers on a month-to-month basis. Sales to the following customers exceeded 10% of revenues during any one of the three years indicated (expressed in thousands):
1997 1996 1995 ------- ------- ------- Enron Corp. and affiliates ....................... $57,965 $58,101 $42,895 Petroleum Authority of Thailand (PTT) ............ $30,108 $ -- $ -- Coastal Gas Marketing Company .................... $ -- $18,376 $18,117
(6) CREDIT RISK Substantially all of the Company's accounts receivable at December 31, 1997 and 1996, result from oil and gas sales and joint interest billings to other companies in the oil and gas industry. This concentration of customers and joint interest owners may impact the Company's overall credit risk, either positively or negatively, in that these entities may be similarly affected by industry-wide changes in economic or other conditions. Such receivables are generally not collateralized. Historically, credit losses incurred by the Company on receivables generally have not been material. No known material credit losses were experienced during 1997 or 1996. A substantial portion of the Company's oil and gas operations are conducted in Southeast Asia, and a substantial portion of its natural gas and liquid hydrocarbon production are sold there. In recent months, Southeast Asia in general, and the Kingdom of Thailand in particular, have experienced severe economic difficulties which have been characterized by sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets. The government of the Kingdom of Thailand and other governments in the region are currently acting to address these issues. However, the economic difficulties currently being experienced in Thailand, together with the volatility of the Thai Baht against the F-15 143 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) U.S. dollar, will continue to have a material impact on the Company's operations in the Kingdom of Thailand, together with the prices that the Company receives for its oil and natural gas production there. All of the Company's current natural gas production from its Thailand operations committed under a long term Gas Sales Agreement to PTT at a price denominated in Thai Baht. The Company's crude oil and condensate production from its Thailand operations is sold on a tanker load by tanker load basis. Prices that the Company receives for such production are based on world benchmark prices, which are denominated in U.S. dollars, and are currently expected on future crude oil sales to be paid in U.S. dollars. The Company believes that the current economic difficulties in Southeast Asia have resulted in a decreased demand for petroleum products in the region, which has contributed to the recent general decline in crude oil and condensate prices throughout the world. (7) EMPLOYEE BENEFITS As permitted by SFAS No. 123, the Company applies APB Opinion No. 25 and related interpretations in accounting for its stock option plans. Since the exercise price of the options granted is equal to the quoted market price of the Company's stock at the date of grant, no compensation cost has been recognized for its stock option plans. Had compensation costs been determined based on the fair value at the grant dates for awards made in 1997, 1996, and 1995 consistent with the methods of SFAS No. 123, the Company's net income and earnings per share would have been reduced to the pro forma amounts indicated below (in thousands, except for per share amounts):
1997 1996 1995 ---------- ---------- ---------- Net income: As reported ........................................... $ 37,116 $ 32,760 $ 9,230 Pro forma ............................................. $ 34,220 $ 31,194 $ 8,619 Earnings per share: As reported (restated for 1996 and 1995) -- Basic ..... $ 1.11 $ 0.99 $ 0.28 As reported (restated for 1996 and 1995) -- Diluted ... $ 1.06 $ 0.95 $ 0.28 Pro forma -- Basic .................................... $ 1.04 $ 0.94 $ 0.26 Pro forma -- Diluted .................................. $ 0.99 $ 0.91 $ 0.26
The fair value of grants was estimated on the date of grant using the Black Scholes option pricing model with the following weighted-average assumptions used in 1997, 1996, and 1995, respectively: risk-free interest rates of 6.10%, 6.25%, and 6.00%, expected volatility of 34.63%, 39.15%, and 41.78%, dividend yields of 0.29%, 0.34%, and 0.54%, and an expected life of the options of 4 years in each of the years 1997, 1996, and 1995. The Company has a tax-advantaged savings plan in which all salaried employees may participate. Under such plan, a participating employee may allocate up to 10% of his salary, up to a maximum allowed by law ($10,000 for 1998), and the Company will then match the employee's contribution on a dollar for dollar basis up to 6% of the employee's salary. Funds contributed by the employee and the matching funds contributed by the Company are held in trust by a bank trustee in six separate funds. Amounts contributed by the employee and earnings and accretions thereon may be used to purchase shares of Common Stock, invest in a money market fund or invest in four stock, bond, or blended stock and bond mutual funds according to instructions from the employee. Matching funds contributed to the savings plan by the Company are invested only in Common Stock. The Company contributed $588,000 to the savings plan in 1997, $471,000 in 1996, and $277,000 in 1995. The Company's stock option plans authorize the granting of options to key employees and non-employee directors at prices equivalent to the market value at the date of grant. Options generally become exercisable in three annual installments commencing one year after the date of grant and, if not exercised, F-16 144 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) expire 10 years from the date of grant. In 1996, the Company adopted the Financial Accounting Standards Board's Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123"). As permitted by SFAS No. 123, the Company elected to continue to account for employee stock-based compensation using the intrinsic value method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees. Accordingly, the adoption of SFAS No. 123 had no effect on the Company's results of operations in 1996 and 1997. A summary of the status of the Company's plans as of December 31, 1997, 1996, and 1995, and changes during the years ended on those dates is presented below:
WEIGHTED AVERAGE NUMBER OF EXERCISE OPTIONS PRICE ---------- ---------- Outstanding, December 31, 1994 ................................ 1,387,537 $ 11.72 Granted .................................................. 389,000 $ 22.34 Exercised ................................................ (181,136) $ 9.48 Forfeited or expired ..................................... (20,000) $ 14.88 ---------- Outstanding, December 31, 1995 ................................ 1,575,401 $ 14.56 ========== Exercisable, December 31, 1995 ................................ 1,006,686 $ 10.87 ========== Available for grant, December 31, 1995 ........................ 1,719,893 ========== Weighted-average fair value of options granted during 1995 .... $ 8.77 Outstanding, December 31, 1995 ................................ 1,575,401 $ 14.56 Granted .................................................. 406,500 $ 34.59 Exercised ................................................ (274,714) $ 12.30 ---------- Outstanding, December 31, 1996 ................................ 1,707,187 $ 19.70 ========== Exercisable, December 31, 1996 ................................ 1,077,658 $ 14.31 ========== Available for grant, December 31, 1996 ........................ 1,313,393 ========== Weighted-average fair value of options granted during 1996 .... $ 13.56 Outstanding, December 31, 1996 ................................ 1,707,187 $ 19.70 Granted .................................................. 480,400 $ 40.49 Exercised ................................................ (229,024) $ 16.83 ---------- Outstanding, December 31, 1997 ................................ 1,958,563 $ 25.13 ========== Exercisable, December 31, 1997 ................................ 1,196,803 $ 18.15 ========== Available for grant, December 31, 1997 ........................ 832,993 ========== Weighted-average fair value of options granted during 1997 .... $ 14.63
F-17 145 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table summarizes information about stock options outstanding at December 31, 1997:
OPTIONS OUTSTANDING --------------------------------------- WEIGHTED OPTIONS EXERCISABLE AVERAGE ----------------------- REMAINING WEIGHTED WEIGHTED CONTRACTUAL AVERAGE AVERAGE RANGE OF NUMBER LIFE EXERCISE NUMBER EXERCISE OPTION PRICES OUTSTANDING (DAYS) PRICE EXERCISABLE PRICE - ------------------------------------- ------------ ----------- -------- ----------- -------- $4.38........................... 92,750 12 $ 4.38 92,750 $ 4.38 $5.56 to $8.06.................. 349,361 1,107 $ 6.83 349,361 $ 6.83 $15.13 to $19.13................ 156,046 2,014 $16.46 156,046 $16.46 $20.31 to $23.88................ 484,838 2,620 $22.15 381,827 $22.17 $30.56 to $34.88................ 325,001 3,143 $33.91 102,319 $33.93 $35.13 to $38.94................ 82,667 3,150 $36.18 56,000 $36.03 $40.56 to $44.38................ 465,900 3,483 $40.80 58,500 $41.20 $48.75.......................... 2,000 3,306 $48.75 -- -- ------------ ----------- Total........................... 1,958,563 2,493 $25.13 1,196,803 $18.15 ============ ===========
F-18 146 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) A trusteed retirement plan has been adopted by the Company for its salaried employees. The benefits are based on years of service and the employee's average compensation for five consecutive years within the final ten years of service which produce the highest average compensation. The Company makes annual contributions to the plan in the amount of retirement plan cost accrued or the maximum amount which can be deducted for federal income tax purposes. The following table sets forth the plan's funded status (in thousands of dollars) as of December 31, 1997, 1996, and 1995.
1997 1996 1995 -------- -------- -------- Actuarial present value (discounted at 7%, 7 1/4%, and 7 1/4%, respectively) of benefit obligations: Accumulated benefit obligations -- Vested ................................................ $ 7,355 $ 6,408 $ 5,488 Non-vested ............................................ 1,536 1,138 1,173 -------- -------- -------- Total accumulated benefit obligations ................. 8,891 7,546 6,661 Projected salary increases (escalated at 5 1/2%, 5% and 5%, respectively) and other changes ...................... 2,329 1,804 1,734 -------- -------- -------- Projected benefit obligations for service rendered to date ..................................................... 11,220 9,350 8,395 Plan assets at fair value, primarily listed securities with an expected long-term rate of return of 9 1/2%, 8 1/2% and 8 1/2%, respectively .......................................... 31,312 24,181 19,089 -------- -------- -------- Plan assets in excess of projected benefit obligations .......... 20,092 14,831 10,694 Unrecognized: Net overfunding being recognized over 15 years ............. (336) (440) (543) Net gain arising from the difference between actual experience and that assumed .............................. (13,134) (9,335) (5,989) Prior service cost ......................................... (300) (343) (387) -------- -------- -------- Accrued retirement plan asset ................................... $ 6,322 $ 4,713 $ 3,775 ======== ======== ======== Retirement plan cost (benefit) for 1997, 1996, and 1995 included the following components: Service cost, benefits accruing each year with proration for future salary increases .................... $ 746 $ 621 $ 480 Interest cost on projected benefit obligations ........ 707 604 535 Actual return on plan assets .......................... (2,286) (1,615) (1,182) Net amortization and deferral ......................... (775) (548) (333) -------- -------- -------- Accrued retirement plan cost (benefit) ..................... $ (1,608) $ (938) $ (500) ======== ======== ========
Although the Company has no obligation to do so, the Company currently provides full medical benefits to its retired employees and dependents. For current employees, the Company assumes all or a portion of post retirement medical and term life insurance costs based on the employee's age and length of service with the Company. The post retirement medical plan has no assets and is currently funded by the Company on a pay-as-you-go basis. F-19 147 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following is an analysis (in thousands of dollars) of the annual expense and activity in the deferred cost and benefits obligation accounts for 1995, 1996 and 1997. The computation assumes that future increases in medical costs will trend down from 8.1% to 5% per year over the next 7 years for purposes of estimating future costs. The medical cost trend rate assumption has a significant effect on the amounts reported. Increasing the assumed medical cost trend rate by one percent in each year would increase the aggregate of service and interest cost components of net periodic post retirement benefit cost for 1997 by $170,000 and the accumulated post retirement benefit obligation as of December 31, 1997 by $1,104,000.
ANNUAL DEFERRED BENEFIT EXPENSE COSTS OBLIGATION ------- -------- ---------- Balance at January 1, 1995 ........................................... $ 3,349 $(5,487) Amortization of transition costs over 14 years representing the average remaining service period of eligible employees ............. $ 304 (304) 304 Amortization of net gain from earlier periods ........................ (69) (69) Service cost, including interest ..................................... 241 Interest cost on transition obligation ............................... 399 ------- 1995 expense ......................................................... $ 875 (875) ======= Current benefits paid ................................................ 145 Unrecognized net gain ................................................ 541 ------- ------- Balance at December 31, 1995 ......................................... 3,045 (5,441) Amortization of transition costs over 14 years ....................... $ 304 (304) 304 Amortization of net gain from earlier periods ........................ (41) (41) Service cost, including interest ..................................... 268 Interest cost on transition obligation ............................... 387 ------- 1996 expense ......................................................... $ 918 (918) ======= Current benefits paid ................................................ 94 Unrecognized net gain ................................................ 107 ------- ------- Balance at December 31, 1996 ......................................... 2,741 (5,895) Amortization of transition costs over 14 years ....................... $ 305 (305) 305 Amortization of net gain from earlier periods ........................ (26) (26) Service cost, including interest ..................................... 459 Interest cost on transition obligation ............................... 427 ------- 1997 expense ......................................................... $ 1,165 (1,165) ======= Current benefits paid ................................................ 99 Unrecognized net loss ................................................ (224) ------- Balance at December 31, 1997 ......................................... $ 2,436 ======= Plan assets at fair value ------- Funded status at December 31, 1997 (discounted at 7%) ................ $(6,906) =======
The accumulated postretirement benefit obligation (in thousands of dollars) at December 31, 1997 is attributable to the following groups: Retirees and beneficiaries.............. $1,951 Dependents of retirees.................. 978 Fully eligible active employees......... 802 Active employees, not fully eligible.... 3,175 ---------- $6,906 ==========
F-20 148 POGO PRODUCING COMPANY & SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (8) FAIR VALUE OF FINANCIAL INSTRUMENTS The following methods and assumptions were used to estimate the fair value of each class of financial instruments for which it is practicable to estimate that value. Cash and Cash Investments Fair value is carrying value as no cash equivalents or cash investments are included in the balances as of December 31, 1997 and 1996. Debt
INSTRUMENT BASIS OF FAIR VALUE ESTIMATE - ------------------------------------------------------------------------------- Bank revolving credit agreement....... Fair value is carrying value as of December 31, 1997 and 1996 based on the market value interest rates. Uncommitted credit lines with banks... Fair value is carrying value as of December 31, 1997 and 1996 based on the market value interest rates. 2007 Notes............................ Fair value is 102.5% of carrying value as of December 31, 1997 based on a quoted market value. 2004 Notes............................ Fair value is 140.38% and 166%, of carrying value as of December 31, 1997 and 1996, respectively, based on quoted market values. 2006 Notes............................ Fair value is 93.5% and 120%, of carrying value as of December 31, 1997 and 1996, respectively, based on quoted market values.
The carrying value and estimated fair value of the Company's financial instruments at December 31, 1997 and 1996 (in thousands of dollars) are as follows:
1997 1996 ----------------------- ----------------------- CARRYING FAIR CARRYING FAIR VALUE VALUE VALUE VALUE --------- --------- --------- --------- Cash and cash investments ................... $ 19,646 $ 19,646 $ 3,054 $ 3,054 Debt: Bank revolving credit agreement ........ (47,000) (47,000) (35,000) (35,000) Uncommitted credit lines with banks .... -- -- (10,000) (10,000) 2007 Notes ............................. (100,000) (102,500) -- -- 2004 Notes ............................. (86,179) (120,978) (86,230) (143,142) 2006 Notes ............................. (115,000) (107,525) (115,000) (138,000)
The Company occasionally enters into forward and futures contracts to minimize the impact of oil and gas price fluctuations. However, the Company does not consider its forward and futures contracts to be financial instruments since these contracts require or permit settlement by the delivery of the underlying commodity. Gains and losses on these activities are recognized in revenues when the hedged production occurs. No such contracts were outstanding as of December 31, 1997 or 1996. F-21 149 UNAUDITED SUPPLEMENTARY FINANCIAL DATA OIL AND GAS PRODUCING ACTIVITIES The results of operations from oil and gas producing activities excludes non-oil and gas revenues, general and administrative expenses, interest charges, interest income and interest capitalized. United States income tax expense was determined by applying the statutory rates to pretax operating results with adjustments for permanent differences. Kingdom of Thailand tax expense was determined by applying the statutory tax rate to Thailand taxable income.
UNITED KINGDOM OF TOTAL STATES THAILAND --------- --------- --------- (EXPRESSED IN THOUSANDS) 1997 ------------------------------------- Revenues .............................................. $ 284,851 $ 245,458 $ 39,393 Lease operating expense ............................... (63,501) (43,934) (19,567) Exploration expense ................................... (10,530) (6,242) (4,288) Dry hole and impairment expense ....................... (9,631) (9,631) -- Depreciation, depletion and amortization expense ...... (101,273) (84,443) (16,830) --------- --------- --------- Pretax operating results .............................. 99,916 101,208 (1,292) Income tax (expense) benefit .......................... (30,353) (32,390) 2,037 --------- --------- --------- Operating results ..................................... $ 69,563 $ 68,818 $ 745 ========= ========= ========= 1996 ------------------------------------- Revenues .............................................. $ 204,142 $ 204,131 $ 11 Lease operating expense ............................... (37,628) (37,628) -- Exploration expense ................................... (16,777) (14,247) (2,530) Dry hole and impairment expense ....................... (8,579) (8,834) 255 Depreciation, depletion and amortization expense ...... (61,033) (60,932) (101) --------- --------- --------- Pretax operating results .............................. 80,125 82,490 (2,365) Income tax (expense) benefit .......................... (27,905) (28,767) 862 --------- --------- --------- Operating results ..................................... $ 52,220 $ 53,723 $ (1,503) ========= ========= ========= 1995 ------------------------------------- Revenues .............................................. $ 157,459 $ 157,536 $ (77) Lease operating expense ............................... (35,071) (35,071) -- Exploration expense ................................... (7,468) (6,111) (1,357) Dry hole and impairment expense ....................... (6,703) (6,703) -- Depreciation, depletion and amortization expense ...... (67,831) (67,798) (33) --------- --------- --------- Pretax operating results .............................. 40,386 41,853 (1,467) Income tax (expense) benefit .......................... (13,623) (14,334) 711 --------- --------- --------- Operating results ..................................... $ 26,763 $ 27,519 $ (756) ========= ========= =========
F-22 150 UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED) The following table sets forth the Company's capitalized costs (expressed in thousands) incurred for oil and gas producing activities during the years indicated.
1997 1996 1995 -------- -------- -------- Capitalized costs incurred: Property acquisition -- United States ................. $ 14,492 $ 5,927 $ 14,864 Property acquisition -- Kingdom of Thailand ........... 28,617 -- 4,171 Exploration -- United States .......................... 24,016 20,651 14,562 Exploration -- Kingdom of Thailand .................... 21,187 8,317 5,418 Development -- United States .......................... 95,768 99,464 39,461 Development -- Kingdom of Thailand .................... 60,996 53,564 23,994 Interest capitalized -- United States ................. 3,331 4,244 1,834 Interest capitalized -- Kingdom of Thailand ........... 2,748 -- -- -------- -------- -------- $251,155 $192,167 $104,304 ======== ======== ======== Provision for depreciation, depletion and amortization: United States ......................................... $ 85,104 $ 61,033 $ 67,798 Kingdom of Thailand ................................... 16,830 101 33 -------- -------- -------- $101,934 $ 61,134 $ 67,831 ======== ======== ========
F-23 151 UNAUDITED SUPPLEMENTARY FINANCIAL DATA -- (CONTINUED) The following information regarding estimates of the Company's proved oil and gas reserves, which are located offshore in United States waters of the Gulf of Mexico, onshore in the United States and offshore in the Kingdom of Thailand is based on reports prepared by Ryder Scott Company Petroleum Engineers. The definitions and assumptions that served as the basis for the discussions under the caption "Item 1. Business -- Exploration and Production Data -- Reserves" should be referred to in connection with the following information. ESTIMATES OF PROVED RESERVES
TOTAL COMPANY UNITED STATES --------------------------- --------------------------- OIL OIL CONDENSATE CONDENSATE & NATURAL NATURAL & NATURAL NATURAL GAS LIQUIDS GAS GAS LIQUIDS GAS (BBLS.) (MMCF) (BBLS.) (MMCF) ----------- ----------- ----------- ----------- Proved Reserves as of December 31, 1994 .......... 33,861,612 242,890 26,187,240 186,151 Revisions of previous estimates .............. 496,849 21,800 363,213 16,592 Extensions, discoveries and other additions .. 11,901,880 78,434 4,267,871 35,058 Purchase of properties ....................... 4,015,131 30,054 460,156 3,770 Sale of properties ........................... (15,144) (748) (15,144) (748) Estimated 1995 production .................... (5,078,326) (44,369) (5,078,326) (44,369) ----------- ----------- ----------- ----------- Proved Reserves as of December 31, 1995 .......... 45,182,002 328,061 26,185,010 196,454 Revisions of previous estimates .............. (499,595) (30,034) 3,374,647 3,022 Extensions, discoveries and other additions .. 9,810,363 102,039 3,601,333 55,592 Purchase of properties ....................... -- -- -- -- Sale of properties ........................... -- -- -- -- Estimated 1996 production .................... (4,890,588) (39,122) (4,890,588) (39,122) ----------- ----------- ----------- ----------- Proved Reserves as of December 31, 1996 .......... 49,602,182 360,944 28,270,402 215,946 Revisions of previous estimates .............. 1,033,664 (16,860) 2,194,936 (5,582) Extensions, discoveries and other additions .. 9,316,407 92,063 4,649,856 49,651 Purchase of properties ....................... 5,175,501 30,319 409,428 8,919 Sale of properties ........................... (6,155) (1,864) (6,155) (1,864) Estimated 1997 production .................... (6,957,246) (63,114) (6,136,957) (50,350) ----------- ----------- ----------- ----------- Proved Reserves as of December 31, 1997 .......... 58,164,353 401,488 29,381,510 216,720 =========== =========== =========== =========== Proved developed reserves as of: December 31, 1994 ............................ 24,669,755 178,518 24,669,755 178,518 December 31, 1995 ............................ 22,487,608 164,679 22,487,608 164,679 December 31, 1996 ............................ 31,090,407 238,032 25,898,414 192,034 December 31, 1997 ............................ 33,149,612 239,732 26,167,519 179,972 KINGDOM OF THAILAND --------------------------- OIL CONDENSATE & NATURAL NATURAL GAS LIQUIDS GAS (BBLS.) (MMCF) ----------- ----------- Proved Reserves as of December 31, 1994 .......... 7,674,372 56,739 Revisions of previous estimates .............. 133,636 5,208 Extensions, discoveries and other additions .. 7,634,009 43,376 Purchase of properties ....................... 3,554,975 26,284 Sale of properties ........................... -- -- Estimated 1995 production .................... -- -- ----------- ----------- Proved Reserves as of December 31, 1995 .......... 18,996,992 131,607 Revisions of previous estimates .............. (3,874,242) (33,056) Extensions, discoveries and other additions .. 6,209,030 46,447 Purchase of properties ....................... -- -- Sale of properties ........................... -- -- Estimated 1996 production .................... -- -- ----------- ----------- Proved Reserves as of December 31, 1996 .......... 21,331,780 144,998 Revisions of previous estimates .............. (1,161,272) (11,278) Extensions, discoveries and other additions .. 4,666,551 42,412 Purchase of properties ....................... 4,766,073 21,400 Sale of properties ........................... -- -- Estimated 1997 production .................... (820,289) (12,764) ----------- ----------- Proved Reserves as of December 31, 1997 .......... 28,782,843 184,768 =========== =========== Proved developed reserves as of: December 31, 1994 ............................ -- -- December 31, 1995 ............................ -- -- December 31, 1996 ............................ 5,191,993 45,998 December 31, 1997 ............................ 6,982,093 59,760
F-24 152 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED
TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND ----------- ----------- ----------- (EXPRESSED IN THOUSANDS) 1997 ------------------------------------------- Future gross revenues ...................................... $ 1,801,254 $ 1,002,609 $ 798,645 Future production costs: Lease operating expense ............................... (604,665) (269,505) (335,160) Future development and abandonment costs ................... (401,970) (155,179) (246,791) ----------- ----------- ----------- Future net cash flows before income taxes .................. 794,619 577,925 216,694 Discount at 10% per annum .................................. (331,838) (171,764) (160,074) ----------- ----------- ----------- Discounted future net cash flow before income taxes ........ 462,781 406,161 56,620 Future income taxes, net of discount at 10% per annum ...... (113,316) (93,386) (19,930) ----------- ----------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves .................. $ 349,465 $ 312,775 $ 36,690 =========== =========== =========== 1996 ------------------------------------------- Future gross revenues ...................................... $ 2,318,113 $ 1,491,057 $ 827,056 Future production costs: Lease operating expense ............................... (504,899) (259,501) (245,398) Future development and abandonment costs ................... (310,839) (126,086) (184,753) ----------- ----------- ----------- Future net cash flows before income taxes .................. 1,502,375 1,105,470 396,905 Discount at 10% per annum .................................. (547,830) (332,343) (215,487) ----------- ----------- ----------- Discounted future net cash flow before income taxes ........ 954,545 773,127 181,418 Future income taxes, net of discount at 10% per annum ...... (268,505) (212,906) (55,599) ----------- ----------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves .................. $ 686,040 $ 560,221 $ 125,819 =========== =========== =========== 1995 ------------------------------------------- Future gross revenues ...................................... $ 1,495,320 $ 873,578 $ 621,742 Future production costs: Lease operating expense ............................... (415,829) (208,477) (207,352) Future development and abandonment costs ................... (247,019) (119,821) (127,198) ----------- ----------- ----------- Future net cash flows before income taxes .................. 832,472 545,280 287,192 Discount at 10% per annum .................................. (299,997) (144,435) (155,562) ----------- ----------- ----------- Discounted future net cash flow before income taxes ........ 532,475 400,845 131,630 Future income taxes, net of discount at 10% per annum ...... (155,330) (104,864) (50,466) ----------- ----------- ----------- Standardized measure of discounted future net cash flows relating to proved oil and gas reserves .................. $ 377,145 $ 295,981 $ 81,164 =========== =========== ===========
The standardized measure of discounted future net cash flows from the production of proved reserves is developed as follows: 1. Estimates are made of quantities of proved reserves and the future periods in which they are expected to be produced based on year end economic conditions. F-25 153 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED -- (CONTINUED) 2. The estimated future gross revenues from proved reserves are priced on the basis of year end prices, except in those instances where fixed and determinable natural gas price escalations are covered by contracts. 3. The future gross revenue streams are reduced by estimated future costs to develop and to produce the proved reserves, as well as certain abandonment costs based on year end cost estimates, and the estimated effect of future income taxes. These cost estimates are subject to some uncertainty, particularly those estimates relating to the Company's properties located in the Kingdom of Thailand. The standardized measure of discounted future net cash flows does not purport to present the fair market value of the Company's oil and gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves in excess of proved reserves, anticipated future changes in prices and costs, a discount factor more representative of the time value of money and the risks inherent in reserve estimates. The following are the principal sources of change in the standardized measure of discounted future net cash flows. All amounts are related to changes in reserves located in the United States and the Kingdom of Thailand, as noted.
YEAR ENDED DECEMBER 31, 1997 ------------------------------------- TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND --------- --------- --------- (EXPRESSED IN THOUSANDS) Beginning balance ............................................... $ 686,040 $ 560,221 $ 125,819 Revisions to prior years' proved reserves: Net changes in prices and production costs ................. (473,086) (344,493) (128,593) Net changes due to revisions in quantity estimates ......... (18,624) 9,619 (28,243) Net changes in estimates of future development costs ....... (83,170) (75,649) (7,521) Accretion of discount ...................................... 95,455 77,313 18,142 Changes in production rate ................................. (2,907) 8,568 (11,475) Other ...................................................... (28,225) (13,086) (15,139) --------- --------- --------- Total revisions ....................................... (510,557) (337,728) (172,829) New field discoveries and extensions, net of future production and development costs .............................. 79,258 76,687 2,571 Purchases of properties ......................................... 10,189 5,899 4,290 Sales of properties ............................................. (6,069) (6,069) -- Sales of oil and gas produced, net of production costs .......... (221,350) (201,524) (19,826) Previously estimated development costs incurred ................................................ 156,764 95,768 60,996 Net change in income taxes ...................................... 155,190 119,521 35,669 --------- --------- --------- Net change in standardized measure of discounted future net cash flows ............................... (336,575) (247,446) (89,129) --------- --------- --------- Ending balance .................................................. $ 349,465 $ 312,775 $ 36,690 ========= ========= =========
F-26 154 STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATED TO PROVED OIL AND GAS RESERVES -- UNAUDITED -- (CONTINUED)
YEAR ENDED DECEMBER 31, 1996 ------------------------------------- TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND --------- --------- --------- (EXPRESSED IN THOUSANDS) Beginning balance .......................................... $ 377,145 $ 295,981 $ 81,164 Revisions to prior years' proved reserves: Net changes in prices and production costs ............... 304,233 289,182 15,051 Net changes due to revisions in quantity estimates ....... 6,717 53,708 (46,991) Net changes in estimates of future development costs ..... (132,685) (79,791) (52,894) Accretion of discount .................................... 53,248 40,085 13,163 Changes in production rate ............................... (59,714) (35,762) (23,952) Other .................................................... (12,760) (2,831) (9,929) --------- --------- --------- Total revisions ....................................... 159,039 264,591 (105,552) New field discoveries and extensions, net of future production and development costs ......................... 275,738 173,962 101,776 Sales of oil and gas produced, net of production costs ..... (165,736) (165,736) -- Previously estimated development costs incurred ............ 153,028 99,464 53,564 Net change in income taxes ................................. (113,174) (108,041) (5,133) --------- --------- --------- Net change in standardized measure of discounted future net cash flows ............................ 308,895 264,240 44,655 --------- --------- --------- Ending balance ............................................. $ 686,040 $ 560,221 $ 125,819 ========= ========= =========
YEAR ENDED DECEMBER 31, 1995 ------------------------------------- TOTAL UNITED KINGDOM OF COMPANY STATES THAILAND --------- --------- --------- (EXPRESSED IN THOUSANDS) Beginning balance .......................................... $ 290,069 $ 257,266 $ 32,803 Revisions to prior years' proved reserves: Net changes in prices and production costs ............... 34,004 69,988 (35,984) Net changes due to revisions in quantity estimates ....... 29,630 26,109 3,521 Net changes in estimates of future development costs ..... (8,632) (36,721) 28,089 Accretion of discount .................................... 38,298 33,087 5,211 Changes in production rate ............................... (14,754) (15,792) 1,038 Other .................................................... (4,393) (432) (3,961) --------- --------- --------- Total revisions ....................................... 74,153 76,239 (2,086) New field discoveries and extensions, net of future production and development costs ......................... 105,172 71,701 33,471 Purchases of properties .................................... 29,299 5,160 24,139 Sales of properties ........................................ (969) (969) -- Sales of oil and gas produced, net of production costs ..... (121,615) (121,615) -- Previously estimated development costs incurred ............ 63,455 39,461 23,994 Net change in income taxes ................................. (62,419) (31,262) (31,157) --------- --------- --------- Net change in standardized measure of discounted future net cash flows ............................ 87,076 38,715 48,361 --------- --------- --------- Ending balance ............................................. $ 377,145 $ 295,981 $ 81,164 ========= ========= =========
F-27 155 QUARTERLY RESULTS -- UNAUDITED Summaries of the Company's results of operations by quarter for the years 1997 and 1996 are as follows:
QUARTER ENDED ----------------------------------------------------- MAR. 31 JUNE 30 SEPT. 30 DEC. 31 ---------- ---------- ---------- ---------- (EXPRESSED IN THOUSANDS, EXCEPT PER SHARE AMOUNTS) 1997 Revenues ................................................... $ 61,314 $ 76,740 $ 77,177 $ 71,069 Gross profit(a) ............................................ $ 27,776 $ 23,953 $ 27,648 $ 20,104 Net income ................................................. $ 12,818 $ 9,174 $ 7,386 $ 7,738 Earnings per share(b): Basic ................................................. $ 0.38 $ 0.27 $ 0.22 $ 0.23 Diluted ............................................... $ 0.36 $ 0.26 $ 0.21 $ 0.22 1996 1996 Revenues ................................................... $ 48,052 $ 51,543 $ 48,233 $ 56,149 Gross profit(a) ............................................ $ 17,004 $ 20,011 $ 16,845 $ 25,276 Income before extraordinary loss ........................... $ 6,265 $ 8,937 $ 6,971 $ 11,408 Extraordinary loss on early extinguishment of debt ......... -- $ (821) -- -- Net income ................................................. $ 6,265 $ 8,116 $ 6,971 $ 11,408 Earnings per share(b): Basic -- Income before extraordinary loss ................. $ 0.19 $ 0.27 $ 0.21 $ 0.34 Extraordinary loss ............................... -- $ (0.02) -- -- Net income ....................................... $ 0.19 $ 0.25 $ 0.21 $ 0.34 Diluted -- Income before extraordinary loss ................. $ 0.19 $ 0.26 $ 0.20 $ 0.32 Extraordinary loss ............................... -- $ (0.02) -- -- Net income ....................................... $ 0.19 $ 0.24 $ 0.20 $ 0.32
- ------------ (a) Represents revenues less lease operating, exploration, dry hole and impairment, and depreciation depletion and amortization expenses. (b) Restated for September 30, 1997, and all prior periods F-28 156 =============================================================================== YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED OR INCORPORATED BY REFERENCE IN THIS PROSPECTUS. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH DIFFERENT INFORMATION. WE ARE NOT OFFERING THE EXCHANGE NOTES IN ANY JURISDICTION WHERE THE OFFER IS NOT PERMITTED. WE DO NOT CLAIM THE ACCURACY OF THE INFORMATION IN THIS PROSPECTUS AS OF ANY DATE OTHER THAN THE DATE STATED ON THE COVER. $150,000,000 POGO PRODUCING COMPANY [LOGO] OFFER TO EXCHANGE 10 3/8% SERIES B SENIOR SUBORDINATED NOTES DUE 2009 FOR 10 3/8% SERIES A SENIOR SUBORDINATED NOTES DUE 2009 ------------------------- PROSPECTUS ------------------------- February 16, 1999 =============================================================================== -----END PRIVACY-ENHANCED MESSAGE-----